UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM
10-K
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended
2021December 31, 2019
OR
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number
1-8858
UNITIL CORPORATION
(Exact name of registrant as specified in its charter)
New Hampshire | 02-0381573 | ||
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||
6 Liberty Lane West, Hampton, | 03842-1720 | ||
(Address of principal executive offices) | (Zip Code) | ||
Registrant’s telephone number, including area code: (603)
(603)
772-0775
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol | Name of each exchange of which registered | ||
Common Stock, | UTL | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
☒
No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
☐
No
☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes
☒
No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation
S-T
(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes
☒
No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated
filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule12b-2
of the Exchange Act.Large accelerated filer ☒ Accelerated☒ Accelerated filer
☐
Non-accelerated
filer ☐
Smaller reporting company ☐
Emerging growth company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 762(b)) by the registered public accounting firm that prepared or issued its audit report ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2
of the Act). Yes ☐
No ☒
Based on the closing price of the registrant’s common stock on June 30, 2019,2021, the aggregate market value of common stock held by$880,678,701$785,923,009.
non-affiliates
of the registrant was The number of shares of the registrant’s common stock outstanding was14,930,967 15,978,791 as of January27, 2020. 28, 2022.
Documents Incorporated by Reference:
Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held on April 29, 202027, 2022 are incorporated by reference into Part III of this Report.
UNITIL CORPORATION
FORM
10-K
For the Fiscal Year Ended December 31, 20192021
Table of Contents
Item | Description | Page | ||||
PART I | ||||||
1. | 3 | |||||
3 | ||||||
4 | ||||||
6 | ||||||
8 | ||||||
9 | ||||||
11 | ||||||
12 | ||||||
12 | ||||||
12 | ||||||
1A. | 13 | |||||
1B. | 19 | |||||
2. | 19 | |||||
3. | 20 | |||||
4. | 21 | |||||
PART II | ||||||
5. | 22 | |||||
6. | 25 | |||||
7. | 26 | |||||
7A. | 41 | |||||
8. | 43 | |||||
9. | 92 | |||||
9A. | 92 | |||||
9B. | 92 | |||||
PART III | ||||||
10. | 93 | |||||
11. | 93 | |||||
12. | 93 | |||||
13. | 93 | |||||
14. | 93 | |||||
PART IV | ||||||
15. | 94 | |||||
SIGNATURES | ||||||
100 | ||||||
Item | Description | Page | ||
PART I | ||||
1. | 3 | |||
| 3 | ||||
| 4 | ||||
| 6 | ||||
| 7 | ||||
| 7 | ||||
| 7 | ||||
1A. | 8 | |||
1B. | 15 | |||
2. | 15 | |||
3. | 16 | |||
4. | 16 | |||
PART II | ||||
5. | 17 | |||
6. | 19 | |||
7. | 19 | |||
7A. | 35 | |||
8. | 36 | |||
9. | 84 | |||
9A. | 84 | |||
9B. | 84 | |||
9C. | 84 | |||
PART III | ||||
10. | 85 | |||
11. | 85 | |||
12. | 85 | |||
13. | 85 | |||
14. | 85 | |||
PART IV | ||||
15. | 86 | |||
SIGNATURES | ||||
| 93 | ||||
In this Annual Report on Form 10-K, the “Company”, “Unitil”, “we”, “us”, “our” and similar terms refer to Unitil Corporation and its subsidiaries, unless the context requires otherwise.
CAUTIONARY STATEMENT
This report and the documents incorporated by reference into this report contain statements that may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, included or incorporated by reference into this report, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for the future operations of the Company (as such term is defined in Part I, Item I (Business)), are forward-looking statements.
These statements include declarations regarding the Company’s beliefs and current expectations. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in Part I, Item 1A (Risk Factors) and the following:
numerous hazards and operating risks relating to the Company’s electric and natural gas distribution activities, which could result in accidents and other operating risks and costs;
fluctuations in the supply of, demand for, and the prices of, electric and gas energy commodities and transmission and transportation capacity and the Company’s ability to recover energy supply costs in its rates;
catastrophic events;
cyber-attacks, acts of terrorism, acts of war, severe weather, a solar event, an electromagnetic event, a natural disaster, the age and condition of information technology assets, human error, or other factors could disrupt the Company’s operations and cause the Company to incur unanticipated losses and expense;
outsourcing of services to third parties could expose us to substandard quality of service delivery or substandard deliverables, which may result in missed deadlines or other timeliness issues, non-compliance (including with applicable legal requirements and industry standards) or reputational harm, which could negatively affect our results of operations;
the coronavirus (COVID-19) pandemic (the coronavirus pandemic) could adversely affect the Company’s business, financial condition, results of operations and cash flows, including by disrupting the Company’s employees’ and contractors’ ability to provide ongoing services to the Company, by reducing customer demand for electricity or natural gas, or by reducing the supply of electricity or natural gas;
unforeseen or changing circumstances, which could adversely affect the reduction of Company-wide direct greenhouse gas emissions;
the Company’s regulatory and legislative environment (including laws and regulations relating to climate change, greenhouse gas emissions and other environmental matters), could affect the rates the Company is able to charge, the Company’s authorized rate of return, the Company’s ability to recover costs in its rates, the Company’s financial condition, results of operations and cash flows, and the scope of the Company’s regulated activities;
general economic conditions, which could adversely affect (i) the Company’s customers and, consequently, the demand for the Company’s distribution services, (ii) the availability of credit and liquidity resources, and (iii) certain of the Company’s counterparty’s obligations (including those of its insurers and lenders);
the Company’s ability to obtain debt or equity financing on acceptable terms;
increases in interest rates, which could increase the Company’s interest expense;
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declines in capital markets valuations, which could require the Company to make substantial cash contributions to cover its pension obligations, and the Company’s ability to recover pension obligation costs in its rates;
restrictive covenants contained in the terms of the Company’s and its subsidiaries’ indebtedness, which restrict certain aspects of the Company’s business operations;
customers’ preferred energy sources;
severe storms and the Company’s ability to recover storm costs in its rates;
variations in weather, which could decrease demand for the Company’s distribution services;
long-term global climate change, which could adversely affect customer demand or cause extreme weather events that could disrupt the Company’s electric and natural gas distribution services;
the Company’s ability to retain its existing customers and attract new customers; and
increased competition.competition; and
other presently unknown or unforeseen factors.
Many of these risks are beyond the Company’s control. Any forward-looking statements speak only as of the date of this report, and the Company undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events, except as required by law. New factors emerge from time to time, and it is not possible for the Company to predict all of thesesuch factors, nor can the Company assess the impacteffect of any such factor on its business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements.
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PART I
Item | 1. Business |
UNITIL CORPORATION
In this Annual Report on Formand was incorporated under the laws of the State of New Hampshire in 1984. The following companies are wholly-owned subsidiaries of Unitil:
10-K,
the “Company”, “Unitil”, “we”, and “our” refer to Unitil Corporation and its subsidiaries, unless the context requires otherwise. Unitil is a public utility holding company Company Name | State and Year of Organization | Principal Business | ||||||
Unitil Energy Systems, Inc. (Unitil Energy) | NH - 1901 | Electric Distribution Utility | ||||||
Fitchburg Gas and Electric Light Company (Fitchburg) | MA - 1852 | Electric & Natural Gas Distribution Utility | ||||||
Northern Utilities, Inc. (Northern Utilities) | NH - 1979 | Natural Gas Distribution Utility | ||||||
Granite State Gas Transmission, Inc. (Granite State) | NH - 1955 | Natural Gas Transmission Pipeline | ||||||
Unitil Power Corp. (Unitil Power) | NH - 1984 | Wholesale Electric Power Utility | ||||||
Unitil Service Corp. (Unitil Service) | NH - 1984 | Utility Service Company | ||||||
Unitil Realty Corp. (Unitil Realty) | NH - 1986 | Real Estate Management | ||||||
Unitil Resources, Inc. (Unitil Resources) | NH - 1993 | Non-regulated Energy Services | ||||||
Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005.
Unitil’s principal business is the local distribution of electricity and natural gas to 190,040194,275 customers throughout its service territories in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities: i) Unitil Energy, which provides electric service in the southeastern seacoast and state capital regions of New Hampshire, including the capital city of Concord, ii) Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts, and iii) Northern Utilities, which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland, which is the largest city in northern New England. In addition, Unitil is the parent company of Granite State, an interstate natural gas transmission pipeline company that provides interstate natural gas pipeline access and transportation services to Northern Utilities in its New Hampshire and Maine service territory. Together, Unitil’s three distribution utilities serve 106,129107,680 electric customers and 83,91186,595 natural gas customers.
Customers Served as of December 31, 2019 | ||||||||||||
Residential | Commercial & Industrial (C&I) | Total | ||||||||||
Electric: | ||||||||||||
Unitil Energy | 65,366 | 11,198 | 76,564 | |||||||||
Fitchburg | 25,617 | 3,948 | 29,565 | |||||||||
Total Electric | 90,983 | 15,146 | 106,129 | |||||||||
Natural Gas: | ||||||||||||
Northern Utilities | 51,492 | 16,370 | 67,862 | |||||||||
Fitchburg | 14,344 | 1,705 | 16,049 | |||||||||
Total Natural Gas | 65,836 | 18,075 | 83,911 | |||||||||
Total Customers Served | 156,819 | 33,221 | 190,040 | |||||||||
Customers Served as of December 31, 2021 | ||||||||||||
Residential | Commercial & Industrial (C&I) | Total | ||||||||||
Electric: | ||||||||||||
Unitil Energy | 66,331 | 11,315 | 77,646 | |||||||||
Fitchburg | 25,983 | 4,051 | 30,034 | |||||||||
Total Electric | 92,314 | 15,366 | 107,680 | |||||||||
Natural Gas: | ||||||||||||
Northern Utilities | 53,700 | 16,698 | 70,398 | |||||||||
Fitchburg | 14,482 | 1,715 | 16,197 | |||||||||
Total Natural Gas | 68,182 | 18,413 | 86,595 | |||||||||
Total Customers Served | 160,496 | 33,779 | 194,275 | |||||||||
Unitil had an investment in Net Utility Plant of $1,111.5$1,257.2 million at December 31, 2019. Unitil’s2021. The Company’s total operating revenue was $438.2$473.3 million in 2019.2021. Unitil’s operating revenue is substantially derived from regulated electric and natural gas and electric distribution utility operations. A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy, but
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May 1, 2003 Unitil Power ceased being the wholesale supplier of Unitil Energy in 2003 and divested of substantially all of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. In the period since, Unitil Power continued to flow revenues and expenses from remaining contracts to Unitil Energy under the Amended Unitil System Agreement. The last of those contracts expired October 31, 2020, and the Company no longer has material revenues or expenses associated with those contracts.
Unitil also has three other wholly-owned of in the first quarter of 2019, were indirect subsidiaries that were wholly-owned by Unitil Resources. Usource provided energy brokering and advisory services to large commercial and industrial customers in the northeastern United States. See additional discussion of the divestiture of Usource in “Divestiture of32 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report. All of the Company’s revenues are attributable to customers in the United States of America and all its long-lived assets are located in the United States of America.
non-utility
subsidiaries: Unitil Service, Unitil Realty, and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology and energy supply management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire. Unitil Resources is the Company’s wholly-ownednon-regulated
subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource), which the Company divestedNon-Regulated
Business Subsidiary” in Note 1 (Summary of Significant Accounting Policies) to the Consolidated Financial Statements. For segment information relating to each segment’s revenue, earnings and assets, see Note OPERATIONS
Electric Distribution Utility Operations
Unitil’s electric distribution operations are conducted through two of the Company’s utilities, Unitil Energy and Fitchburg. Revenue from Unitil’s electric utility operations was $248.5 million in 2021, which represents about 53% of Unitil’s total operating revenue. The Company’s GAAP Electric Gross Margin was $71.5 million in 2021. The Company’s Electric Adjusted Gross Margin (a non-GAAP financial measure) was $97.4 million in 2021, or 42% of Unitil’s total Adjusted Gross Margin. See “Results of Operations” in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) for a discussion of the non-GAAP financial measures presented in this Annual Report on Form 10-K, including a reconciliation of the non-GAAP financial measures to the most comparable GAAP financial measures for the periods presented.
The primary business of Unitil’s electric utility operations is the local distribution of electricity to customers in its service territory in New Hampshire and Massachusetts. All of Unitil Energy’s and Fitchburg’s electric customers are entitled to purchase their supply of electricity from third-party competitive suppliers, while Unitil Energy and Fitchburg remain their electric distribution company. Both Unitil Energy and Fitchburg supply electricity to those customers who do not obtain their supply from third-party competitive suppliers, with the approved costs associated with electricity supply being recovered on a pass-through basis through regulated reconciling rate mechanisms that are periodically adjusted.
Unitil Energy distributes electricity to 77,646 customers in New Hampshire in the capital city of Concord as well as parts of 12 surrounding towns, and all or part of 18 towns in the southeastern and seacoast regions of New Hampshire, including the towns of Hampton, Exeter, Atkinson and Plaistow. Unitil Energy’s service territory consists of approximately 408 square miles. Unitil Energy’s service territory encompasses retail and recreation centers for the central and southeastern parts of the state and includes the Hampton Beach recreational area. These areas serve diversified commercial and industrial businesses, including manufacturing firms engaged in the production of electronic components, wire and plastics, as well as firms engaged in the aviation, defense, healthcare and education sectors. Unitil Energy’s 2021 electric operating revenue was $172.3 million, of which approximately 56% was derived from residential sales and 44% from commercial and industrial (C&I) sales.
Fitchburg is engaged in the distribution of both electricity and natural gas in the greater Fitchburg area of north central Massachusetts. Fitchburg’s service territory encompasses approximately 170 square miles.
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Electricity is distributed by Fitchburg to 30,034 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, precision machining and molding, non-lethal ballistics manufacturing, specialty chemicals compounding, cannabis growing and processing facilities, printing, and educational institutions. Fitchburg’s 2021 electric operating revenue was $76.2 million, of which approximately 58% was derived from residential sales and 42% from C&I sales.
Natural Gas Operations
Unitil’s natural gas operations include gas distribution utility operations and interstate gas transmission pipeline operations, discussed below.operations. Revenue from Unitil’s gas operations was $203.4$224.8 million for 2019,in 2021, which represents about 46%47% of Unitil’s total operating revenue. Natural gas sales margins were $122.2The Company’s GAAP Gas Gross Margin was $100.4 million in 2019,2021. The Company’s Gas Adjusted Gross Margin (a non-GAAP financial measure) was $133.1 million in 2021, or 57%58% of Unitil’s total sales margins.Adjusted Gross Margin. See “Results of Operations” in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) for a discussion of the non-GAAP financial measures presented in this Annual Report on Form 10-K, including a reconciliation of the non-GAAP financial measures to the most comparable GAAP financial measures for the periods presented.
Natural Gas Distribution Utility Operations
Unitil’s natural gas distribution operations are conducted through two of the Company’s operating utilities, Northern Utilities and Fitchburg. The primary business of Unitil’s natural gas utility operations is the local distribution of natural gas to customers in its service territories in New Hampshire, Massachusetts and Maine. Northern Utilities’ C&I customers and Fitchburg’s residential and C&I customers are entitled to purchase their natural gas supply from third-party competitive suppliers, while Northern Utilities or Fitchburg remains their gas distribution company. Both Northern Utilities and Fitchburg supply gas to those customers who do not obtain their supply from third-party competitive suppliers, with the approved costs associated with this gas supply being recovered on a pass-through basis through regulated reconciling rate mechanisms that are periodically adjusted.
Natural gas is distributed by Northern Utilities to 67,86270,398 customers in 47 New Hampshire and southern Maine communities, from Plaistow, New Hampshire in the south to the city of Portland, Maine and then extending to Lewiston-Auburn, Maine into the north. Northern Utilities has a diversified customer base both in Maine and New Hampshire. Commercial businesses include healthcare, education, government and retail. Northern Utilities’ industrial base includes manufacturers in the auto, housing, rubber,paper, printing, textile, pharmaceutical, electronics, wire and food production industries as well as a military installation. Northern Utilities’ 20192021 gas operating revenue was $161.9$176.7 million, of which approximately 38% was derived from residential firm sales and 62% from C&I firm sales.
Natural gas is distributed by Fitchburg to 16,04916,197 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companiescannabis growing and processing facilities, printing, publishing and associated industries.educational institutions. Fitchburg’s 20192021 gas operating revenue was $34.9$40.1 million, of which approximately 58% was derived from residential firm sales and 42% from C&I firm sales.
Gas Transmission Pipeline Operations
Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State had operating revenue of $6.6$8.0 million for 2019.in 2021. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and to third-party suppliers.
Seasonality
The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the year as a
5
result of higher sales of natural gas used for heating relatedheating-related purposes. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by the weather conditions and the temperature in both the winter and summer seasons.
Unitil Energy, Fitchburg and Northern Utilities are not dependent on a single customer, or a few customers, for their electric and natural gas sales.
Non-Regulated
and OtherNon-Utility
OperationsUnitil’s of Usource in the first quarter of 2019. Usource provided energy brokering and advisory services to large commercial and industrial customers in the northeastern United States. See additional discussion of the divestiture of Usource in “Divestiture of Revenue from Unitil’snon-regulatedoperations was $0.9 million in 2019.
non-regulated
operations were conducted through Usource, a subsidiary of Unitil Resources. The Company divestedNon-Regulated
Business Subsidiary” in Note 1 (Summary of Significant Accounting Policies) to the Consolidated Financial Statements.The results of Unitil’s other32 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report.
non-utility
subsidiaries, Unitil Service and Unitil Realty, and the holding company, are included in the Company’s consolidated results of operations. The results of thesenon-utility
operations are principally derived from income earned on short-term investments and real property owned for Unitil’s and its subsidiaries’ use and are reported, after intercompany eliminations, in Other segment income. For segment information, see Note RATES AND REGULATION
Regulation
Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities also are also regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the NHPUC;New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the MDPU;Massachusetts Department of Public Utilities (MDPU); and Northern Utilities is regulated by the NHPUC and MPUC.Maine Public Utilities Commission (MPUC). Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.
Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities are provided the opportunity to recover the cost of providing distribution service to their customers based on a historical test year, and earn a return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its natural gas transmission pipeline company may also recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost trackertracking rate mechanisms.
Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recognized as an increase or a decrease in the current portion of Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the MDPU. The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.
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Also seeRegulatory Mattersin Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) Note 6 (Energy Supply) and Note 87 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information onregarding rates and regulation.
Unitil’s common stock is listed on the New York Stock Exchange under the ticker symbol “UTL”.
natural gas operations include gas distribution utility operations and interstate gas transmission pipeline operations. Revenue from Unitil’s gas operations was $224.8 million in 2021, which represents about 47% of Unitil’s total operating revenue. The Company’s annual meeting of shareholders is scheduled to be held at the offices of the Company, 6 Liberty Lane West, Hampton, New Hampshire, on Wednesday, April 29, 2020, at 11:30 a.m.
GAAP Gas Gross Margin was $100.4 million in 2021. The Company’s transfer agent, Computershare Investor Services, is responsible for shareholder records, issuance of common stock, administration of the Dividend Reinvestment and Stock Purchase Plan, and the distributionGas Adjusted Gross Margin (a non-GAAP financial measure) was $133.1 million in 2021, or 58% of Unitil’s dividends and IRS Form1099-DIV.Shareholders may contact Computershare at:
Natural Gas Distribution Utility Operations
Unitil’s natural gas distribution operations are conducted through two of the Company’s operating utilities, Northern Utilities and its subsidiaries’ indebtedness restrict the Company’s and its subsidiaries’Fitchburg. The primary business operations (including their ability to incur material amounts of additional indebtedness), which could adversely affect the Company’s financial condition and results of operations.
Natural gas is distributed by Northern Utilities to 70,398 customers in 47 New Hampshire and southern Maine communities, from Plaistow, New Hampshire in the summer months (duesouth to air conditioning demand)the city of Portland, Maine and then extending to Lewiston-Auburn, Maine to the winter months (due to heating-relatednorth. Northern Utilities has a diversified customer base both in Maine and lighting requirements). Therefore, mild summer temperaturesNew Hampshire. Commercial businesses include healthcare, education, government and mild winter temperatures could decreaseretail. Northern Utilities’ industrial base includes manufacturers in the amountauto, housing, paper, printing, textile, pharmaceutical, electronics, wire and food production industries as well as a military installation. Northern Utilities’ 2021 gas operating revenue was $176.7 million, of electricity sold by the Company, which could adversely affect the Company’s financial conditionapproximately 38% was derived from residential firm sales and results of operations. Also, because of this temperature sensitivity, sales by the Company’s distribution utilities vary62% from year to year, depending on weather conditions.C&I firm sales.
Natural gas is distributed by Fitchburg to 16,197 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, cannabis growing and processing facilities, printing, educational institutions. Fitchburg’s 2021 gas operating revenue was $40.1 million, of which approximately 58% was derived from residential firm sales and 42% from C&I firm sales.
Seasonality
The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the year as a
5
result of higher sales of natural gas used for heating relatedheating-related purposes. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by the weather conditions and the temperature in both the winter and summer seasons.
Unitil is a public utility holding companyEnergy, Fitchburg and has no operating income of its own. The Company’s ability to pay dividends on its common stock isNorthern Utilities are not dependent on dividends and other payments received from its subsidiaries and on factors directly affecting Unitil, the parent corporation. The Company cannot assure that its current annual dividend will be paid in the future.
Non-Regulated and Other Non-Utility Operations
Unitil’s non-regulated operations were conducted through Usource, a subsidiary of Unitil Resources. The Company divested Usource in the first quarter of 2019. Usource provided energy brokering and advisory services to large commercial and industrial customers in the northeastern United States. See additional discussion of the divestiture of Usource in “Divestiture of Non-Regulated Business Subsidiary” in Note 1 (Summary of Significant Accounting Policies) to the Consolidated Financial Statements.
The results of Unitil’s other non-utility subsidiaries, Unitil Service and Unitil Realty, and the holding company, are included in the Company’s consolidated results of operations. The results of these non-utility operations are principally derived from income earned on short-term investments and real property owned for Unitil’s and its subsidiaries’ use and are reported, after intercompany eliminations, in Other segment income. For segment information, see Note 2 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report.
RATES AND REGULATION
Regulation
Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities also are regulated by the FERC. Unitil’s distribution activities (including storingutilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the Massachusetts Department of Public Utilities (MDPU); and Northern Utilities is regulated by the NHPUC and Maine Public Utilities Commission (MPUC). Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and supplemental gas supplies) involve numerous hazards and operating risks that may result in accidents and other operating risks and costs. Any such accident or costsoperations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could adverselysignificantly affect the Company’s operations and financial position or results of operations.
Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recognized as an increase or a decrease in the Company’scurrent portion of Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the MDPU. The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas distribution activities are a variety of hazards and operating risks, including leaks, explosions, electrocutions, mechanical problems and aging infrastructure. These hazards and risks could result in loss of human life, significant damage to property, environmental pollution, damage to natural resources and impairment of the Company’s operations, which could adversely affect the Company’s financial position or results of operations.sales volumes, respectively.
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Natural Gas Operations
Unitil’s natural gas operations include gas distribution utility operations and interstate gas transmission pipeline operations. Revenue from Unitil’s gas operations was $224.8 million in 2021, which represents about 47% of Unitil’s total operating revenue. The Company’s GAAP Gas Gross Margin was $100.4 million in 2021. The Company’s Gas Adjusted Gross Margin (a non-GAAP financial measure) was $133.1 million in 2021, or 58% of Unitil’s total Adjusted Gross Margin. See “Results of Operations” in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) for a discussion of the non-GAAP financial measures presented in this Annual Report on Form 10-K, including a reconciliation of the non-GAAP financial measures to the most comparable GAAP financial measures for the periods presented.
Northern Utilities | Fitchburg | Granite State | Total | |||||||||||||||||
Description | NH | ME | ||||||||||||||||||
Underground Natural Gas Mains—Miles | 560 | 597 | 273 | — | 1,430 | |||||||||||||||
Natural Gas Transmission Pipeline—Miles | — | — | — | 86 | 86 | |||||||||||||||
Service Pipes | 23,912 | 22,883 | 11,123 | — | 57,918 | |||||||||||||||
Natural Gas Distribution Utility Operations
Unitil’s natural gas distribution operations are conducted through two of the Company’s operating utilities, Northern Utilities and Fitchburg. The primary business of Unitil’s natural gas utility operations is the local distribution of natural gas to customers in its service territories in New Hampshire, Massachusetts and Maine. Northern Utilities’ C&I customers and Fitchburg’s residential and C&I customers are entitled to purchase their natural gas supply from third-party competitive suppliers, while Northern Utilities or Fitchburg remains their gas distribution company. Both Northern Utilities and Fitchburg supply gas to those customers who do not obtain their supply from third-party competitive suppliers, with the approved costs associated with this gas supply recovered on a pass-through basis through regulated reconciling rate mechanisms that are periodically adjusted.
Natural gas is distributed by Northern Utilities to 70,398 customers in 47 New Hampshire and southern Maine communities, from Plaistow, New Hampshire in the south to the city of Portland, Maine and then extending to Lewiston-Auburn, Maine to the north. Northern Utilities has a diversified customer base both in Maine and New Hampshire. Commercial businesses include healthcare, education, government and retail. Northern Utilities’ industrial base includes manufacturers in the auto, housing, paper, printing, textile, pharmaceutical, electronics, wire and food production industries as well as a military installation. Northern Utilities’ 2021 gas operating revenue was $176.7 million, of which approximately 38% was derived from residential firm sales and 62% from C&I firm sales.
Natural gas is distributed by Fitchburg to 16,197 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, cannabis growing and processing facilities, printing, educational institutions. Fitchburg’s 2021 gas operating revenue was $40.1 million, of which approximately 58% was derived from residential firm sales and 42% from C&I firm sales.
Gas Transmission Pipeline Operations
Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State had operating revenue of $8.0 million in 2021. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and to third-party suppliers.
Seasonality
The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the year as a
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result of higher sales of natural gas used for heating-related purposes. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by weather conditions and the temperature in the winter and summer seasons.
Unitil Energy, Fitchburg and Northern Utilities are not dependent on a single customer, or a few customers, for their electric and natural gas sales.
Non-Regulated and Other Non-Utility Operations
Unitil’s non-regulated operations were conducted through Usource, a subsidiary of Unitil Resources. The Company divested Usource in the first quarter of 2019. Usource provided energy brokering and advisory services to large commercial and industrial customers in the northeastern United States. See additional discussion of the divestiture of Usource in “Divestiture of Non-Regulated Business Subsidiary” in Note 1 (Summary of Significant Accounting Policies) to the Consolidated Financial Statements.
The results of Unitil’s other non-utility subsidiaries, Unitil Service and Unitil Realty, and the holding company, are included in the Company’s consolidated results of operations. The results of these non-utility operations are principally derived from income earned on short-term investments and real property owned for Unitil’s and its subsidiaries’ use and are reported, after intercompany eliminations, in Other segment income. For segment information, see Note 2 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report.
RATES AND REGULATION
Regulation
Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities also are regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the Massachusetts Department of Public Utilities (MDPU); and Northern Utilities is regulated by the NHPUC and Maine Public Utilities Commission (MPUC). Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.
Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities are provided the opportunity to recover the cost of providing distribution service to their customers based on a historical test year, and earn a return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its natural gas transmission pipeline company may recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost tracking rate mechanisms.
Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recognized as an increase or a decrease in the current portion of Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the MDPU. The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.
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Also see Note 6 (Energy Supply) and Note 7 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information regarding rates and regulation.
EMPLOYEES
Unitil’s commitment to excellence begins with its employees. As of December 31, 2021, the Company and its subsidiaries had 508 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions. Unitil’s employees are focused on the Company’s mission to safely and reliably deliver “energy for life” and provide customers with affordable and sustainable energy solutions.
The Company strives to be the employer of choice in the communities it serves—regardless of race, religion, color, gender, or sexual orientation. The Company works diligently to attract the best talent from a diverse range of sources to meet the current and future demands of our business.
To attract and retain a talented workforce, Unitil provides employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. All employees are eligible for health insurance, paid and unpaid leave, educational assistance, retirement plan and life and disability/accident coverage.
Employees at Unitil have the opportunity to be heard. Feedback from employees is collected annually in the Company’s Employee Opinion survey. This feedback helps create action plans to improve the engagement of employees consistent with the Company’s culture of continuous improvement.
As of December 31, 2021, a total of 167 employees of certain of the Company’s subsidiaries were represented by labor unions. The following table details by subsidiary the employees covered by a collective bargaining agreement (CBA) as of December 31, 2021:
Employees Covered | CBA Expiration | |||||||
Fitchburg | 43 | 05/31/2022 | ||||||
Northern Utilities NH Division | 37 | 06/07/2025 | ||||||
Northern Utilities ME Division | 38 | 03/31/2026 | ||||||
Granite State | 4 | 03/31/2026 | ||||||
Unitil Energy | 40 | 05/31/2023 | ||||||
Unitil Service | 5 | 05/31/2023 | ||||||
The CBAs provide discrete salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.
AVAILABLE INFORMATION
The Internet address for the Company’s website is. On the Investors section of the Company’s website, the Company makes available, free of charge, its Securities and Exchange Commission (SEC) reports, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other reports, as well as amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practical after the Company electronically files such material with, or furnishes such material to, the SEC.
unitil.com
The Company’s current Code of Ethics was approved by Unitil’s Board of Directors on January 15, 2004. This Code of Ethics, along with any amendments or waivers, is also available on Unitil’s website.
Unitil’s common stock is listed on the New York Stock Exchange under the ticker symbol “UTL”.
INVESTOR INFORMATION
Annual Meeting
The Company’s annual meeting of shareholders is scheduled to be held at the offices of the Company, 6 Liberty Lane West, Hampton, New Hampshire, on Wednesday, April 27, 2022, at 11:30 a.m.
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Transfer Agent
The Company’s transfer agent, Computershare Investor Services, is responsible for shareholder records, issuance of common stock, administration of the Dividend Reinvestment and Stock Purchase Plan, and the distribution of Unitil’s dividends and IRS Form 1099-DIV. Shareholders may contact Computershare at:
Computershare Investor Services
P.O. Box 505005
Louisville, KY 40233-5005
Telephone: 800-736-3001
www.computershare.com/investor
Investor Relations
For information about the Company, you may call the Company directly, toll-free, at: 800-999-6501 and ask for the Investor Relations Representative; visit the Investors page at; or contact the transfer agent, Computershare, at the number listed above.
www.unitil.com
Special Services & Shareholder Programs Available to Holders of Record
If a shareholder’s shares of our common stock are registered directly in the shareholder’s name with the Company’s transfer agent, the shareholder is considered a holder of record of the shares. The following services and programs are available to shareholders of record:
Internet Account Access is available at.
www.computershare.com/investor
Dividend Reinvestment and Stock Purchase Plan:
To enroll, please contact the Company’s Investor Relations Representative or Computershare.
Dividend Direct Deposit Service:
To enroll, please contact the Company’s Investor Relations Representative or Computershare.
Direct Registration:
For information, please contact Computershare at 800-935-9330 or the Company’s Investor Relations Representative at 800-999-6501.
Item 1A. | Risk Factors |
When considering an investment in our securities, investors should consider the following risk factors, as well as the information contained under the caption “Cautionary Statement” immediately following the Table of Contents in this Annual Report on Form 10-K. Additional risks not presently known to the Company or that the Company currently believes are immaterial may also impair business operations and financial results. If any of the following risks actually occur, the Company’s business, financial condition or results of operations could be adversely affected. In such case, the trading price of the Company’s common stock could decline and investors could lose all or part of their investment. The risk factors below are categorized by operational, regulatory, financial and general.
OPERATIONAL RISKS
A substantial disruption or lack of growth in interstate natural gas pipeline transmission and storage capacity and electric transmission capacity may impair the Company’s ability to meet customers’ existing and future requirements.
To meet existing and future customer demands for electricity and natural gas, the Company must acquire sufficient supplies of electricity and natural gas. In addition, the Company must contract for reliable and adequate upstream transmission and transportation capacity for its distribution systems while considering the dynamics of the natural gas interstate pipelines and storage, the electric transmission markets and its own on-system resources. The Company’s financial condition or results of operations may be adversely affected if the future availability of electric and natural gas supply were insufficient to meet future customer demands for electricity and natural gas.
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The Company’s electric and natural gas distribution activities (including storing natural gas and supplemental gas supplies) involve numerous hazards and operating risks that may result in accidents and other operating risks and costs. Any such accident or costs could adversely affect the Company’s financial position or results of operations.
Inherent in the Company’s electric and natural gas distribution activities are a variety of hazards and operating risks, including leaks, explosions, electrocutions, mechanical problems and aging infrastructure. These hazards and risks could result in loss of human life, significant damage to property, environmental pollution, damage to natural resources and impairment of the Company’s operations, which could adversely affect the Company’s financial position or results of operations.
The Company maintains insurance against some, but not all, of these risks and losses in accordance with customary industry practice. The location of pipelines, storage facilities and electric distribution equipment near populated areas (including residential areas, commercial business centers and industrial sites) could increase the level of damages associated with these hazards and operating risks. The occurrence of any of these events could adversely affect the Company’s financial position or results of operations.
The Company’s operational and information systems on which it relies to conduct its business and serve customers could fail to function properly due to technological problems, a cyber-attack, acts of terrorism, severe weather, a solar event, an electromagnetic event, a natural disaster, the age and condition of information technology assets, human error, or other reasons, that could disrupt the Company’s operations and cause the Company to incur unanticipated losses and expense.
The operation of the Company’s extensive electric and natural gas systems rely on evolving information technology systems and network infrastructure that are likely to become more complex as new technologies and systems are developed. The Company’s business is highly dependent on its ability to process and monitor, on a daily basis, a very large number of transactions, many of which are highly complex. The failure of these information systems and networks could significantly disrupt operations; result in outages and/or damages to the Company’s assets or operations or those of third parties on which it relies; and subject the Company to claims by customers or third parties, any of which could have a material effect on the Company’s financial condition, results of operations, and cash flows.
The Company’s information systems, including its financial information, operational systems, metering, and billing systems, require constant maintenance, modification, and updating, which can be costly and increases the risk of errors and malfunction. Any disruptions or deficiencies in existing information systems, or disruptions, delays or deficiencies in the modification or implementation of new information systems, could result in increased costs, the inability to track or collect revenues, the diversion of management’s and employees’ attention and resources, and could negatively affect the effectiveness of the Company’s control environment, and/or the Company’s ability to timely file required regulatory reports. Despite implementation of security and mitigation measures, all of the Company’s technology systems are vulnerable to impairment or failure due to cyber-attacks, computer viruses, human errors, acts of war or terrorism and other reasons. If the Company’s information technology systems were to fail or be materially impaired, the Company might be unable to fulfill critical business functions and serve its customers, which could have a material effect on the Company’s financial condition, results of operations, and cash flows.
In the ordinary course of its business, the Company collects and retains sensitive electronic data including personal identification information about customers and employees, customer energy usage, and other confidential information. The theft, damage, or improper disclosure of sensitive electronic data through security breaches or other means could subject the Company to penalties for violation of applicable privacy laws or claims from third parties and could harm the Company’s reputation and adversely affect the Company’s financial condition and results of operations.
In addition, the Company’s electric and natural gas distribution and transmission delivery systems are part of an interconnected regional grid and pipeline system. If these neighboring interconnected systems were to be disrupted due to cyber-attacks, computer viruses, human errors, acts of war or terrorism or other reasons, the Company’s operations and its ability to serve its customers would be adversely affected, which could have a material effect on the Company’s financial condition, results of operations, and cash flows.
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We outsource certain business functions to third-party suppliers and service providers, and substandard performance by those third parties could harm our business, reputation and results of operations.
We outsource certain services to third parties in areas including information technology, telecommunications, networks, transaction processing, human resources, payroll and payroll processing and other areas. Outsourcing of services to third parties could expose us to substandard quality of service delivery or substandard deliverables, which may result in missed deadlines or other timeliness issues, non-compliance (including with applicable legal requirements and industry standards) or reputational harm, which could negatively affect our results of operations. We also continue to pursue enhancements to modernize our systems and processes. If any difficulties in the operation of these systems were to occur, they could adversely affect our results of operations, or adversely affect our ability to work with regulators, unions, customers or employees.
The inability to attract and retain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, could have an adverse effect on the Company’s operations.
The success of our business depends on the leadership of our executive officers and other key employees to implement our business strategies. The inability to maintain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, may negatively affect our ability to service our existing or new customers, or successfully manage our business or achieve our business objectives. There may not be sufficiently skilled employees available internally to replace employees when they retire or otherwise leave active employment. Shortages of certain highly skilled employees may also mean that qualified employees are not available externally to replace these employees when they are needed. In addition, shortages in highly skilled employees coupled with competitive pressures may require the Company to incur additional employee recruiting and compensation expenses.
The Company may be adversely affected by work stoppages, labor disputes, and/or pandemic illness to which it may not able to promptly respond.
Approximately one-third of the Company’s employees are represented by labor unions and are covered by collective bargaining agreements. Disputes with the unions over terms and conditions of the agreements could result in instability in the Company’s labor relationships and work stoppages that could affect the timely delivery of electricity and natural gas, which could strain relationships with customers and state regulators and cause a loss of revenues. The Company’s collective bargaining agreements may also increase the cost of employing its union workforce, affect its ability to continue offering market-based salaries and employee benefits, limit its flexibility in dealing with its workforce, and limit its ability to change work rules and practices and implement other efficiency-related improvements to successfully compete in today’s challenging marketplace, which may negatively affect the Company’s financial condition and results of operations.
Additionally, pandemic illness could result in part, or all, of the Company’s workforce being unable to operate or maintain the Company’s infrastructure or perform other tasks necessary to conduct the Company’s business. A slow or inadequate response to this type of event may adversely affect the Company’s financial condition, results of operations, and cash flows.
The coronavirus outbreak could adversely affect Unitil’s business, financial conditions, results of operations and cash flows.
In December 2019, a novel strain of coronavirus (COVID-19) emerged in Wuhan, Hubei Province, China. While initially the outbreak was largely concentrated in China and caused significant disruptions to its economy, the virus spread to several other countries and infections have been reported globally. The extent to which the coronavirus affects Unitil’s financial condition, results of operations, and cash flows will depend on future developments, which are highly uncertain and cannot be predicted with confidence, including the duration of the outbreak, new information which may emerge concerning the severity of the coronavirus, and the actions to contain the coronavirus or treat its effect, among others. In particular, the continued spread of the coronavirus could adversely affect Unitil’s business, including (i) by disrupting Unitil’s employees and contractors ability to provide ongoing services to Unitil, (ii) by reducing customer
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demand for electricity or gas, or (iii) by reducing the supply of electricity or gas, each of which could have an adverse effect on Unitil’s financial condition, results of operations, and cash flows.
REGULATORY RISKS
The Company is subject to comprehensive regulation, which could adversely affect the rates it is able to charge, its authorized rate of return and its ability to recover costs. In addition, certain regulatory authorities have the statutory authority to impose financial penalties and other sanctions on the Company, which could adversely affect the Company’s financial condition, results of operations, and cash flows.
The Company is subject to comprehensive regulation by federal regulatory authorities (including the FERC) and state regulatory authorities (including the NHPUC, MDPU and MPUC). These authorities regulate many aspects of the Company’s operations, including the rates that the Company can charge customers, the Company’s authorized rates of return, the Company’s ability to recover costs from its customers, construction and maintenance of the Company’s facilities, the Company’s safety protocols and procedures, including environmental compliance, the Company’s ability to issue securities, the Company’s accounting matters, and transactions between the Company and its affiliates. The Company is unable to predict the effect on its financial condition and results of operations from the regulatory activities of any of these regulatory authorities. Changes in regulations, the imposition of additional regulations, regulatory proceedings regarding fossil fuel use and system electrification, or regulatory decisions particular to the Company could adversely affect the Company’s financial condition and results of operations.
The Company’s ability to obtain rate adjustments to maintain its current authorized rates of return depends upon action by regulatory authorities under applicable statutes, rules and regulations. These regulatory authorities are authorized to leave the Company’s rates unchanged, to grant increases in such rates, or to order decreases in such rates. The Company may be unable to obtain favorable rate adjustments or to maintain its current authorized rates of return, which could adversely affect its financial condition, results of operations, and cash flows.
Regulatory authorities also have authority with respect to the Company’s ability to recover its electricity and natural gas supply costs, as incurred by Unitil Power, Unitil Energy, Fitchburg, and Northern Utilities. If the Company is unable to recover a significant amount of these costs, or if the Company’s recovery of these costs is significantly delayed, the Company’s financial condition, results of operations, or cash flows could be adversely affected.
In addition, certain regulatory authorities have the statutory authority to impose financial penalties and other sanctions on the Company if the Company is found to have violated statutes, rules or regulations governing its utility operations. Any such penalties or sanctions could adversely affect the Company’s financial condition, results of operations, and cash flows.
The Company’s business is subject to environmental regulation in all jurisdictions in which it operates and its costs of compliance are significant. New, or changes to existing, environmental regulation, including those related to climate change or greenhouse gas emissions, and the incurrence of environmental liabilities could adversely affect the Company’s financial condition, results of operations, and cash flows.
The Company’s utility operations are generally subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources, and the health and safety of the Company’s employees. The Company’s utility operations also may be subject to new and emerging federal, state and local legislative and regulatory initiatives related to climate change or greenhouse gas emissions including the U.S. Environmental Protection Agency’s mandatory greenhouse gas reporting rule. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties and other sanctions; imposition of remedial requirements; and issuance of injunctions to ensure future compliance. Liability under certain environmental laws and regulations is strict, joint and several in nature. Although the Company believes it is in material compliance with all applicable environmental and safety laws and regulations, we cannot assure you that the Company will not incur significant costs and liabilities in the future. Moreover, it is possible
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that other developments, such as increasingly stringent federal, state or local environmental laws and regulations, including those related to climate change or greenhouse gas emissions, could result in increased environmental compliance costs. Additionally, unforeseen or changing circumstances could adversely affect the reduction of Company-wide direct greenhouse gas emissions.
FINANCIAL RISKS
The Company may not be able to obtain financing, or may not be able to obtain financing on acceptable terms, which could adversely affect the Company’s financial condition and results of operations.
The Company requires capital to fund utility plant additions, working capital and other utility expenditures. While the Company derives the capital necessary to meet these requirements primarily from internally generated funds, the Company supplements internally generated funds by incurring short-term and long-term debt, as needed. Additionally, from time to time the Company has accessed the public capital markets through public offerings of equity securities. A downgrade of our credit rating or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.
The Company’s short-term debt revolving credit facility typically has variable interest rates. Therefore, an increase or decrease in interest rates will increase or decrease the Company’s interest expense associated with its revolving credit facility. An increase in the Company’s interest expense could adversely affect the Company’s financial condition and results of operations. As of December 31, 2021, the Company had approximately $64.1 million in short-term debt outstanding under its revolving credit facility. If the lending counterparties under the Company’s current credit facility are unwilling or unable to meet their funding obligations, the Company may be unable to, or limited in its ability, to borrow under its credit facility. This situation could hinder or prevent the Company from meeting its current and future capital needs, which could correspondingly adversely affect the Company’s financial condition, results or operations, and cash flows.
Also, from time to time the Company repays portions of its short-term debt with the proceeds it receives from long-term debt financings or equity financings. General economic conditions, conditions in the capital and credit markets and the Company’s operating and financial performance could negatively affect the Company’s ability to obtain such financings or the terms of such financings, which could correspondingly adversely affect the Company’s financial condition, results of operations, and cash flows. The Company’s long-term debt typically has fixed interest rates. Therefore, changes in interest rates will not affect the Company’s interest expense associated with its presently outstanding fixed rate long-term debt. However, an increase or decrease in interest rates may increase or decrease the Company’s interest expense associated with any new fixed rate long-term debt issued by the Company, which could adversely affect the Company’s financial condition, results of operations, and cash flows.
The Company may need to use a significant portion of its cash flow to repay its short-term debt and long-term debt, which would limit the amount of cash it has available for working capital, capital expenditures and other general corporate purposes and could adversely affect its financial condition, results of operations, and cash flows.
Changes in taxation and the ability to quantify such changes could adversely affect the Company’s financial results.
The Company is subject to taxation by the various taxing authorities at the federal, state and local levels where it does business. See “Tax Cuts and Jobs Act of 2017” in “Rates and Regulation” section. Legislation or regulation which could affect the Company’s tax burden could be enacted by any of these governmental authorities. The Company cannot predict the timing or extent of such tax-related developments which could have a negative effect on the financial results. The Company uses its best judgment in attempting to quantify and reserve for these tax obligations. However, a challenge by a taxing authority, the Company’s ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates.
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Declines in capital market valuations could require the Company to make substantial cash contributions to cover its pension and other post-retirement benefit obligations. If the Company is unable to recover a significant amount of pension and other post-retirement benefit obligation costs in its rates, or if the Company’s recovery of these costs in its rates is significantly delayed, its financial condition and results of operations could be adversely affected.
The amount of cash contributions the Company is required to make in respect of its pension and other post-retirement benefit obligations is dependent upon the valuation of the capital markets. Adverse changes in capital market valuations could result in the Company being required to make substantial cash contributions in respect to these obligations. These cash contributions could have an adverse effect on the Company’s financial condition, results of operations, and cash flows if the Company is unable to recover such costs in rates or if such recovery is significantly delayed. See section titledin Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 9 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements for a more detailed discussion of the Company’s pension obligations.
Critical Accounting Policies—Retirement Benefit Obligations
The terms of the Company’s and its subsidiaries’ indebtedness restrict the Company’s and its subsidiaries’ business operations (including their ability to incur material amounts of additional indebtedness), which could adversely affect the Company’s financial condition and results of operations.
The terms of the Company’s and its subsidiaries’ indebtedness impose various restrictions on the Company’s business operations, including the ability of the Company and its subsidiaries to incur additional indebtedness. These restrictions could adversely affect the Company’s financial condition, results of operations, and cash flows. See sections titledin Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements for a more detailed discussion of these restrictions.
Liquidity, Commitments and Capital Requirements
Unitil is a public utility holding company and has no operating income of its own. The Company’s ability to pay dividends on its common stock is dependent on dividends and other payments received from its subsidiaries and on factors directly affecting Unitil, the parent corporation. The Company cannot assure that its current annual dividend will be paid in the future.
The ability of the Company’s subsidiaries to pay dividends or make distributions to Unitil depends on, among other things:
the actual and projected earnings and cash flow, capital requirements and general financial condition of the Company’s subsidiaries;
the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by the Company’s subsidiaries;
the restrictions on the payment of dividends contained in the existing loan agreements of the Company’s subsidiaries and that may be contained in future debt agreements of the Company’s subsidiaries, if any; and
limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory authorities.
In addition, before the Company can pay dividends on its common stock, it must satisfy its debt obligations and comply with any statutory or contractual limitations.
As of February 1, 2022, the Company’s current effective annualized dividend is $1.56 per share of common stock, payable quarterly. The Company’s Board of Directors reviews Unitil’s dividend policy periodically in light of a number of business and financial factors, including those referred to in this report, and the Company cannot assure the amount of dividends, if any, that may be paid in the future.
13
GENERAL RISKS
The Company’s electric and natural gas sales and revenues are highly correlated with the economy, and national, regional and local economic conditions may adversely affect the Company’s customers and correspondingly the Company’s financial condition, results of operations, and cash flows.
The Company’s business is influenced by the economic activity within its service territory. The level of economic activity in the Company’s electric and natural gas distribution service territories directly affects the Company’s business. As a result, adverse changes in the economy may adversely affect the Company’s financial condition, results or operations, and cash flows. Economic downturns or periods of high electric and gas supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories. If any such declines were to occur without corresponding adjustments in rates, our revenues would be reduced and our future growth prospects would be limited. In addition, a period of prolonged economic weakness could affect our customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations, and cash flows.
A significant amount of the Company’s sales are temperature sensitive. Because of this, mild winter and summer temperatures could decrease the Company’s sales, which could adversely affect the Company’s financial condition and results of operations. Also, the Company’s sales may vary from year to year depending on weather conditions, and the Company’s results of operations generally reflect seasonality.
The Company estimates that approximately 70% of its annual natural gas sales are temperature sensitive. Therefore, mild winter temperatures could decrease the amount of natural gas sold by the Company, which could adversely affect the Company’s financial condition, results of operations, and cash flows. The Company’s electric sales also are temperature sensitive, but less so than its natural gas sales. The highest usage of electricity typically occurs in the summer months (due to air conditioning demand) and the winter months (due to heating-related and lighting requirements). Therefore, mild summer temperatures and mild winter temperatures could decrease the amount of electricity sold by the Company, which could adversely affect the Company’s financial condition, results of operations, and cash flows. Also, because of this temperature sensitivity, sales by the Company’s distribution utilities vary from year to year, depending on weather conditions.
The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the year as a result of higher sales of natural gas used for heating-related purposes. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by the weather conditions and the temperature in both the winter and summer seasons.
Catastrophic events could adversely affect the Company’s financial condition and results of operations.
The electric and natural gas utility industries are from time to time affected by catastrophic events, such as unusually severe weather and significant and widespread failures of plant and equipment. Other catastrophic occurrences, such as terrorist attacks on utility facilities, may occur in the future. Such events could inhibit the Company’s ability to deliver electricity or natural gas to its customers for an extended period, which could affect customer satisfaction and adversely affect the Company’s financial condition, results of operations, and cash flows. If customers, legislators, or regulators develop a negative opinion of the Company, this situation could result in increased regulatory oversight and could affect the equity returns that the Company is allowed to earn. Also, if the Company is unable to recover in its rates a significant amount of costs associated with catastrophic events, or if the Company’s recovery of such costs in its rates is significantly delayed, the Company’s financial condition, results or operations, or cash flows may be adversely affected.
14
The Company’s business could be adversely affected if it is unable to retain its existing customers or attract new customers, or if customers’ demand for its current products and services significantly decreases.
The success of the Company’s business depends, in part, on its ability to maintain and increase its customer base and the demand that those customers have for the Company’s products and services. The Company’s failure to maintain or increase its customer base and/or customer demand for its products and services could adversely affect its financial condition, results of operations, and cash flows.
The electricity and natural gas supply requirements of the Company’s customers are fulfilled by the Company or, in some instances and as allowed by state regulatory authorities, by third-party suppliers who contract directly with customers. In either scenario, significant increases in electricity and natural gas commodity prices may negatively affect the Company’s ability to attract new customers and grow its customer base.
Developments in distributed generation, energy conservation, power generation and energy storage could affect the Company’s revenues and the timing of the recovery of the Company’s costs. Advancements in power generation technology are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to meet their around-the-clock electricity requirements. Such developments could reduce customer purchases of electricity, but may not necessarily reduce the Company’s investment and operating requirements due to the Company’s obligation to serve customers, including those self-supply customers whose equipment has failed for any reason, to provide the power they need. In addition, because a portion of the Company’s costs are recovered through charges based upon the volume of power delivered, reductions in electricity deliveries will affect the timing of the Company’s recovery of those costs and may require changes to the Company’s rate structures.
Item 1B. | Unresolved Staff Comments |
None.
Item 2. | Properties |
As of December 31, 2021, Unitil owned through its electric and natural gas distribution utilities, five utility operating centers located in New Hampshire, Maine and Massachusetts. The Company’s real estate subsidiary, Unitil Realty, owns the Company’s corporate headquarters building and the land on which it is located in Hampton, New Hampshire.
The following tables detail certain of the Company’s electric and natural gas operations properties.
Electric Operations
Description | Unitil Energy | Fitchburg | Total | |||||||||
Primary Transmission and Distribution Pole Miles—Overhead | 1,279 | 446 | 1,725 | |||||||||
Conduit Distribution Bank Miles—Underground | 233 | 67 | 300 | |||||||||
Transmission and Distribution Substations | 34 | 16 | 50 | |||||||||
Transformer Capacity of Transmission and Distribution Substations (MVA) | 542.7 | 608.2 | 1,150.9 | |||||||||
Description | Unitil Energy | Fitchburg | Total | |||||||||
Primary Transmission and Distribution Pole Miles—Overhead | 1,294 | 455 | 1,749 | |||||||||
Conduit Distribution Bank Miles—Underground | 240 | 68 | 308 | |||||||||
Transmission and Distribution Substations | 34 | 15 | 49 | |||||||||
Transformer Capacity of Transmission and Distribution Substations* (MVA) | 470.1 | 429.4 | 899.5 | |||||||||
| * | Does not include load served directly from sub-transmission. |
Natural Gas Operations
Northern Utilities | Fitchburg | Granite State | Total | |||||||||||||||||
Description | NH | ME | ||||||||||||||||||
Underground Natural Gas Mains—Miles | 576 | 604 | 272 | — | 1,452 | |||||||||||||||
Natural Gas Transmission Pipeline—Miles | — | — | — | 86 | 86 | |||||||||||||||
Service Pipes | 24,494 | 23,556 | 11,211 | — | 59,261 | |||||||||||||||
15
Unitil Energy’s electric substations are located on land owned by Unitil Energy or land occupied by Unitil Energy pursuant to perpetual easements in the southeastern seacoast and state capital regions of New HampshireUnitil Energy’s electric distribution lines are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by Unitil Energy without objection by the owners. In the case of certain distribution lines, Unitil Energy owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telecommunication companies.
.
The physical utility properties of Unitil Energy, with certain exceptions, and its franchises are subject to its indenture of mortgage and deed of trust under which the respective series of first mortgage bonds of Unitil Energy are outstanding.
Fitchburg’s electric substations, with minor exceptions, are located in north central Massachusetts on land owned by Fitchburg or occupied by Fitchburg pursuant to perpetual easements. Fitchburg’s electric distribution lines and gas mains are located in, on, or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, express or implied through use by Fitchburg without objection by the owners. Fitchburg owns full interest in the poles upon which its wires are installed.
The Company’s natural gas operations property includes two liquefied propane gas plants and two liquid natural gas plants. Northern Utilities also owns a propane air gas plant and an LNG storage and vaporization facility. Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility, both of which are located on land owned by Fitchburg in north central Massachusetts.
Northern Utilities’ gas mains are primarily made up of polyethylene plastic (82.5%), coated and wrapped cathodically protected steel (15.6%), cast/wrought iron (1.7%), and unprotected bare and coated steel (0.2%). FG&E’s gas mains are primarily made up of coated steel (44.0%), bare steel (1.4%), polyethylene plastic (40.7%), cast iron (13.4%) and wrought and ductile iron (0.5%)
Granite State’s underground natural gas transmission pipeline, regulated by the FERC, is located primarily in Maine and New Hampshire.
The Company believes that its facilities are currently adequate for their intended uses.
Item 3. | Legal Proceedings |
The Company is involved in legal and administrative proceedings and claims of various types, including those which arise in the ordinary course of business. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these claims will not have a material impacteffect on its financial position, operating results or cash flows.
Item 4. | Mine Safety Disclosures |
Not applicable.
PART II
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
The Company’s common stock is listed on the New York Stock Exchange under the symbol “UTL.” As of December 31, 2019,2021, there were 1,3091,236 shareholders of record of our common stock.
Common Stock Data
Dividends per Common Share | 2019 | 2018 | ||||||
1st Quarter | $ | 0.370 | $ | 0.365 | ||||
2nd Quarter | 0.370 | 0.365 | ||||||
3rd Quarter | 0.370 | 0.365 | ||||||
4th Quarter | 0.370 | 0.365 | ||||||
Total for Year | $ | 1.48 | $ | 1.46 | ||||
Dividends per Common Share | 2021 | 2020 | ||||||
1st Quarter | $ | 0.380 | $ | 0.375 | ||||
2nd Quarter | 0.380 | 0.375 | ||||||
3rd Quarter | 0.380 | 0.375 | ||||||
4th Quarter | 0.380 | 0.375 | ||||||
Total for Year | $ | 1.52 | $ | 1.50 | ||||
See also “Dividends” in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) below..
Information regarding securities authorized for issuance under our equity compensation plans, as of December 31, 2019,2021, is set forth in the table below.following table.
Equity Compensation Plan Information
(a) | (b) | (c) | |||||||||||
Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | ||||||||||
Equity compensation plans approved by security holders (1) | — | — | |||||||||||
Equity compensation plans not approved by security holders | — | — | — | ||||||||||
Total | — | — | 190,677 | ||||||||||
NOTES: (also see Note 65 (Equity) to the accompanying Consolidated Financial Statements)
| (1) | Consists of the Second Amended and Restated 2003 Stock Plan (the Plan). On April 19, 2012, shareholders approved the Plan, and a total of 677,500 shares of our common stock were reserved for issuance pursuant to awards of restricted stock, restricted stock units and common stock under the Plan. A total of |
17
Stock Performance Graph
The following graph compares Unitil Corporation’s cumulative stockholder return since December 31, 20142016 with the Peer Group index, comprised of the S&P 500 Utilities Index, and the S&P 500 index. The graph assumes that the value of the investment in the Company’s common stock and each index (including reinvestment of dividends) was $100 on December 31, 2014.2016.
Comparative Five-Year Total Returns
NOTE:
| (1) | The graph above assumes $100 invested on December 31, |
Unregistered Sales of Equity Securities and Uses of Proceeds
There were no sales of unregistered equity securities by the Company for the fiscal period ended December 31, 2019.2021.
Issuer Purchases of Equity Securities
Pursuant to the written trading plan under Rule2019,2021, the Company will periodically repurchase shares of its Common Stock on the open market related to the stock portion of the Directors’ annual retainer for those Directors who elected to receive common stock. There is no pool or maximum number of shares related to these purchases; however, the trading plan will terminate when $195,000$350,500 in value of shares have been purchased or, if sooner, on May 1, 2020.2022.
10b5-1
under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted and announced by the Company on May 1, The Company may suspend or terminate this trading plan at any time, so long as the suspension or termination is made in good faith and not as part of a plan or scheme to evade the prohibitions of Rule
10b-5
under the Exchange Act, or other applicable securities laws.18
The following table showsprovides information regarding repurchases by the Company of shares of its common stock pursuant to the trading plan for each month in the quarter ended December 31, 2019.2021.
Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs | ||||||||||||
10/1/19 – 10/31/19 | 2,911 | $ | 63.54 | 2,911 | $ | 10,034 | ||||||||||
11/1/19 – 11/30/19 | — | — | — | $ | 10,034 | |||||||||||
12/1/19 – 12/31/19 | — | — | — | $ | 10,034 | |||||||||||
Total | 2,911 | $ | 63.54 | 2,911 | ||||||||||||
Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs | ||||||||||||
10/1/21 – 10/31/21 | 8,012 | $ | 43.746 | 8,012 | $ | 11 | ||||||||||
11/1/21 – 11/30/21 | — | — | — | $ | 11 | |||||||||||
12/1/21 – 12/31/21 | — | — | — | $ | 11 | |||||||||||
Total | 8,012 | $ | 43.746 | 8,012 | ||||||||||||
Item 6. | Reserved |
For the Years Ended December 31, (all data in millions except customers served, shares, % and per share data) | ||||||||||||||||||||
2019 (2) | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||
Customers Served (Year-End): | ||||||||||||||||||||
Electric: | ||||||||||||||||||||
Residential | 90,983 | 90,537 | 90,009 | 89,400 | 88,444 | |||||||||||||||
Commercial & Industrial | 15,146 | 15,034 | 14,969 | 14,872 | 14,825 | |||||||||||||||
Total Electric | 106,129 | 105,571 | 104,978 | 104,272 | 103,269 | |||||||||||||||
Natural Gas: | ||||||||||||||||||||
Residential | 65,836 | 64,604 | 63,441 | 62,284 | 61,270 | |||||||||||||||
Commercial & Industrial | 18,075 | 18,155 | 17,868 | 17,654 | 17,479 | |||||||||||||||
Total Natural Gas | 83,911 | 82,759 | 81,309 | 79,938 | 78,749 | |||||||||||||||
Total Customers Served | 190,040 | 188,330 | 186,287 | 184,210 | 182,018 | |||||||||||||||
Electric and Gas Sales: | ||||||||||||||||||||
Electric Distribution Sales (kWh) | 1,595.7 | 1,675.8 | 1,624.1 | 1,628.8 | 1,667.7 | |||||||||||||||
Firm Natural Gas Distribution Sales (Therms) | 232.1 | 231.1 | 213.8 | 205.7 | 219.4 | |||||||||||||||
Consolidated Statements of Earnings: | ||||||||||||||||||||
Operating Revenue | $ | 438.2 | $ | 444.1 | $ | 406.2 | $ | 383.4 | $ | 426.8 | ||||||||||
Operating Income | 73.1 | 71.2 | 75.4 | 70.2 | 68.0 | |||||||||||||||
Interest Expense, Net | 23.7 | 24.0 | 23.1 | 22.5 | 21.9 | |||||||||||||||
Other Expense (Income), Net | (8.6 | ) | 5.8 | 5.8 | 5.2 | 4.4 | ||||||||||||||
Income Before Income Taxes | 58.0 | 41.4 | 46.5 | 42.5 | 41.7 | |||||||||||||||
Income Taxes | 13.8 | 8.4 | 17.5 | 15.4 | 15.4 | |||||||||||||||
Net Income | 44.2 | 33.0 | 29.0 | 27.1 | 26.3 | |||||||||||||||
Dividends on Preferred Stock | — | — | — | — | — | |||||||||||||||
Earnings Applicable to Common Shareholders | $ | 44.2 | $ | 33.0 | $ | 29.0 | $ | 27.1 | $ | 26.3 | ||||||||||
Earnings Per Average Share: | $ | 2.97 | $ | 2.23 | $ | 2.06 | $ | 1.94 | $ | 1.89 | ||||||||||
Common Stock—(Diluted Weighted Average Outstanding, 000’s) | 14,900 | 14,829 | 14,102 | 13,996 | 13,920 | |||||||||||||||
Dividends Declared Per Share | $ | 1.48 | $ | 1.46 | $ | 1.44 | $ | 1.42 | $ | 1.40 | ||||||||||
Book Value Per Share (Year-End) | $ | 25.22 | $ | 23.60 | $ | 22.72 | $ | 20.82 | $ | 20.20 | ||||||||||
Balance Sheet Data (as of December 31,): | ||||||||||||||||||||
Utility Plant | $ | 1,467.5 | $ | 1,369.3 | $ | 1,279.2 | $ | 1,173.4 | $ | 1,080.6 | ||||||||||
Lease Obligations (1) | $ | 4.5 | $ | 5.8 | $ | 8.8 | $ | 11.3 | $ | 14.1 | ||||||||||
Total Assets | $ | 1,370.8 | $ | 1,298.3 | $ | 1,241.9 | $ | 1,128.2 | $ | 1,038.8 | ||||||||||
Capitalization: | ||||||||||||||||||||
Common Stock Equity | $ | 376.6 | $ | 351.1 | $ | 336.6 | $ | 292.9 | $ | 282.6 | ||||||||||
Preferred Stock | 0.2 | 0.2 | 0.2 | 0.2 | 0.2 | |||||||||||||||
Long-Term Debt, less current portion | 437.5 | 387.4 | 376.3 | 316.8 | 305.5 | |||||||||||||||
Total Capitalization | $ | 814.3 | $ | 738.7 | $ | 713.1 | $ | 609.9 | $ | 588.3 | ||||||||||
Current Portion of Long-Term Debt | $ | 19.5 | $ | 18.4 | $ | 29.8 | $ | 16.8 | $ | 17.1 | ||||||||||
Short-Term Debt | $ | 58.6 | $ | 82.8 | $ | 38.3 | $ | 81.9 | $ | 42.0 | ||||||||||
Capital Structure Ratios (as of December 31,): | ||||||||||||||||||||
Common Stock Equity | 46 | % | 48 | % | 47 | % | 48 | % | 48 | % | ||||||||||
Long-Term Debt, less current portion | 54 | % | 52 | % | 53 | % | 52 | % | 52 | % | ||||||||||
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) (Note references are to the Notes to the Consolidated Financial Statements included in Item |
OVERVIEW
Unitil is a public utility holding company headquartered in Hampton, New Hampshire. Unitil is subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005.
Unitil’s principal business is the local distribution of electricity and natural gas to approximately 190,000194,275 customers throughout its service territory in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities:
| i) | Unitil Energy, which provides electric service in the southeastern seacoast and state capital regions of New Hampshire; |
| ii) | Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts; and |
| iii) | Northern Utilities, which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland and the Lewiston-Auburn area. |
Unitil Energy, Fitchburg and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 106,100107,680 electric customers and 83,90086,595 natural gas customers in their service territory.territories. The distribution utilities are local “wires and pipes” operating companies.
In addition, Unitil is the parent company of Granite State, a natural gas transmission pipeline, regulated by the FERC, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to North American pipeline supplies.
Unitil previously conducted of Usource in the first quarter of 2019. Usource provided energy brokering and advisory services to large commercial and industrial customers in the northeastern United States. Usource’s total revenues were $0.9 million in 2019. See additional discussion of the divestiture of Usource in “Divestiture of
non-regulated
operations principally through Usource, which was wholly-owned by Unitil Resources. The Company divestedNon-Regulated
Business Subsidiary” in Note 1 (Summary of Significant Accounting Policies) to the Consolidated Financial Statements. The Company’s other subsidiaries include Unitil Service, which provides, at cost, a variety of19
administrative and professional services to Unitil’s affiliated companies, and Unitil Realty, which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.
Regulation
Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities are also regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the NHPUC; Fitchburg is subject to regulation by the MDPU; and Northern
Utilities is regulated by the NHPUC and MPUC. Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations, financial position, and financial position.cash flows.
Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory,territories, at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities are provided the opportunity to recover the cost of providing distribution service to their customers based on a historical test year, and earn a return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its natural gas transmission pipeline company also may also recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost tracker rate mechanisms.
Most of Unitil’s customers have the opportunity to purchase their electricity or natural gas supplies from third-party energy suppliers. Many of Unitil’s distribution utilities’ largest C&I customers purchase their electricity or gas supply from third-party suppliers, while most small C&I customers, as well as residential customers, purchase their electricity or gas supply from the distribution utilities under regulated rates and tariffs. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale energy suppliers and recover the actual approved costs of these supplies on a pass-through basis, through reconciling rate mechanisms that are periodically adjusted.
Also seeshown belowin this section and Note 87 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on rates and regulation.
Regulatory Matters
Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recognized as an increase or a decrease in the current portion of Accrued Revenue which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases that the Company files with the MDPU. The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.
RESULTS OF OPERATIONS
The following discussion of the Company’s financial condition and results of operations should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.
The Company continues to respond to the coronavirus pandemic by taking steps to mitigate the potential risks posed by its spread. The Company’s electric and gas utility distribution operating systems have continued to provide service to customers without disruption due to the coronavirus pandemic through the date of this filing. The Company has implemented its Crisis Response Plan to address specific aspects of
20
the coronavirus pandemic. The Crisis Response Plan guides emergency response, business continuity, and the precautionary measures being taken on behalf of employees and the public. The Company has initiated extra precautions to protect employees who work in the field and for employees who continue to work in operations, distribution and corporate facilities. The Company has implemented social distancing and work from home policies, where appropriate. The Company continues to implement strong physical and cyber-security measures to ensure that its systems remain functional in order to serve both operational needs with a remote workforce and to help ensure uninterrupted service to customers.
The extent to which the coronavirus pandemic affects the Company’s financial condition, results of operations, and cash flows will depend on future developments, that are highly uncertain and cannot be predicted with confidence, including the duration of the outbreak, new information that may emerge concerning the severity of the coronavirus pandemic, and the actions to contain the coronavirus pandemic or treat its effect, among others. In particular, the continued spread of the coronavirus could adversely affect the Company’s business, including (i) by disrupting the Company’s employees and contractors ability to provide ongoing services to the Company, (ii) by reducing customer demand for electricity or gas, or (iii) by reducing the supply of electricity or gas, each of which could have an adverse effect on the Company’s financial condition, results of operations, and cash flows.
The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the yearheating season as a result of higher sales of natural gas used for heating related purposes.due to cold weather. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the resultresults of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by the weather conditions and the temperature in both the winter and summer seasons. Also, as a result of recent rate cases, the Company’s natural gas salesGAAP gross margins and gas adjusted gross margins (a non-GAAP financial measure) are derived from a higher percentage of fixed billing components, including customer charges. Therefore, naturalfuture gas revenues and gas adjusted gross margin will be less affected by the seasonal nature of the natural gas business. In addition, as discussed above, approximately 27% and 11% of the Company’s total annual electric and natural gas sales volumes, respectively, are decoupled and changes in sales to existing customers do not affect GAAP gross margin and adjusted gross margin.
On August 6, 2021, the Company issued and sold 800,000 shares of its common stock at a price of $50.80 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $38.6 million. The proceeds were used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes.
As part of the Offering, the Company granted the underwriters a 30-day option to purchase additional shares. The underwriters exercised the option and purchased an additional 120,000 shares of the Company’s common stock on September 8, 2021. The Company’s net increase to Common Equity and Cash proceeds from the exercise of the option was approximately $5.9 million. The proceeds were used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes. Overall, the results of operations and earnings for the year ended December 31, 2021 reflect the higher number of average shares outstanding.
The Company analyzes operating results using Electric and Gas Adjusted Gross Margins, which are non-GAAP financial measures. Electric Adjusted Gross Margin is calculated as Total Electric Operating Revenue less Cost of Electric Sales. Gas Adjusted Gross Margin is calculated as Total Gas Operating Revenues less Cost of Gas Sales. The Company’s management believes Electric and Gas Adjusted Gross Margins provide useful information to investors regarding profitability. Also, the Company’s management believes Electric and Gas Adjusted Gross Margins are important financial measures to analyze revenue from the Company’s ongoing operations because the approved cost of electric and gas sales margin on decoupledare tracked, reconciled and passed through directly to customers in electric and gas tariff rates, resulting in an equal and offsetting amount reflected in Total Electric and Gas Operating Revenue.
In the following tables the Company has reconciled Electric and Gas Adjusted Gross Margin to GAAP Gross Margin, which we believe to be the most comparable GAAP financial measure. GAAP Gross Margin
21
is calculated as Revenue less Cost of Sales, and Depreciation and Amortization. The Company calculates Electric and Gas Adjusted Gross Margin as Revenue less Cost of Sales. The Company believes excluding Depreciation and Amortization, which are period costs and not related to volumetric sales, volumes.is a meaningful financial measure to inform investors of the Company’s profitability from electric and gas sales in the period.
Twelve Months Ended December 31, 2021 ($ millions) | ||||||||||||||||
Electric | Gas | Non-Regulated and Other | Total | |||||||||||||
Total Operating Revenue | $ | 248.5 | $ | 224.8 | $ | — | $ | 473.3 | ||||||||
Less: Cost of Sales | (151.1 | ) | (91.7 | ) | — | (242.8 | ) | |||||||||
Less: Depreciation and Amortization | (25.9 | ) | (32.6 | ) | (1.0 | ) | (59.5 | ) | ||||||||
GAAP Gross Margin | 71.5 | 100.5 | (1.0 | ) | 171.0 | |||||||||||
Depreciation and Amortization | 25.9 | 32.6 | 1.0 | 59.5 | ||||||||||||
Adjusted Gross Margin | $ | 97.4 | $ | 133.1 | $ | — | $ | 230.5 | ||||||||
Twelve Months Ended December 31, 2020 ($ millions) | ||||||||||||||||
Electric | Gas | Non-Regulated and Other | Total | |||||||||||||
Total Operating Revenue | $ | 227.2 | $ | 191.4 | $ | — | $ | 418.6 | ||||||||
Less: Cost of Sales | (134.3 | ) | (68.8 | ) | — | (203.1 | ) | |||||||||
Less: Depreciation and Amortization | (23.8 | ) | (29.8 | ) | (0.9 | ) | (54.5 | ) | ||||||||
GAAP Gross Margin | 69.1 | 92.8 | (0.9 | ) | 161.0 | |||||||||||
Depreciation and Amortization | 23.8 | 29.8 | 0.9 | 54.5 | ||||||||||||
Adjusted Gross Margin | $ | 92.9 | $ | 122.6 | $ | — | $ | 215.5 | ||||||||
Twelve Months Ended December 31, 2019 ($ millions) | ||||||||||||||||
Electric | Gas | Non-Regulated and Other | Total | |||||||||||||
Total Operating Revenue | $ | 233.9 | $ | 203.4 | $ | 0.9 | $ | 438.2 | ||||||||
Less: Cost of Sales | (142.0 | ) | (81.2 | ) | — | (223.2 | ) | |||||||||
Less: Depreciation and Amortization | (22.6 | ) | (28.5 | ) | (0.9 | ) | (52.0 | ) | ||||||||
GAAP Gross Margin | 69.3 | 93.7 | — | 163.0 | ||||||||||||
Depreciation and Amortization | 22.6 | 28.5 | 0.9 | 52.0 | ||||||||||||
Adjusted Gross Margin | $ | 91.9 | $ | 122.2 | $ | 0.9 | $ | 215.0 | ||||||||
Electric GAAP Gross Margin was $71.5 million in 2021, an increase of $2.4 million compared to 2020. The increase was driven by higher rates and customer growth of $4.5 million, partially offset by higher depreciation and amortization expense of $2.1 million.
Electric GAAP Gross Margin was $69.1 million in 2020, a decrease of $0.2 million compared to 2019. The decrease reflects an unfavorable effect of $0.8 million attributed to the combined net effect of lower Commercial and Industrial (C&I) sales and higher Residential sales associated with the coronavirus pandemic, and higher depreciation and amortization of $1.2 million, partially offset by higher rates of $1.4 million and the positive combined effect of customer growth and warmer summer weather of $0.4 million.
Gas GAAP Gross Margin was $100.5 million in 2021, an increase of $7.7 million compared to 2020. The increase was driven by higher rates and customer growth of $9.4 million, and $1.1 million from the favorable effect of colder weather during the peak heating season in 2021, which the Company defines as the months of January—April, and November—December, partially offset by higher depreciation and amortization of $2.8 million.
Gas GAAP Gross Margin was $92.8 million in 2020, a decrease of $0.9 million compared to 2019. The decrease was driven by unfavorable effects of $4.4 million from lower sales due to warmer weather in
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2020, $2.1 million attributed to lower sales primarily associated with the economic slowdown caused by the coronavirus pandemic, and higher depreciation and amortization of $1.3 million. These decreases were partially offset by higher rates of $5.1 million and customer growth of $1.8 million.
Net Income and EPS Overview
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Electric Adjusted Gross Margin (a non-GAAP financial measure) was $97.4 million or $0.66 per
Electric kilowatt-hour (kWh) sales increased 2.2% in 2021 compared to 2020. Sales to Residential customers increased 0.5% and sales to C&I customers increased 3.5% in 2021 compared to 2020. The increase in sales to Residential customers principally reflects positive customer growth. The increase in sales to C&I customers reflects customer growth and increased usage due to improving economic conditions. As of December 31, 2021, the number of electric customers served increased by approximately 600 over the previous year.
Gas Adjusted Gross Margin (a non-GAAP financial measure) was $133.1 million in 2021, an increase of $10.5 million compared to 2020. The increase was driven by higher rates and customer growth of $9.4 million, and $1.1 million from the favorable effect of colder weather during the peak heating season in 2021.
Gas therm sales increased 0.4%3.3% in 20192021 compared to 2018.2020. Sales to Residential customers decreased 0.7% and sales to C&I customers increased 4.4% in 2021 compared to 2020. The overall increase in gas therm sales was driven byreflects customer growth partially offset by milderand colder weather in the fourth quarterpeak heating season. As of 2019 compared to 2018.December 31, 2021, the number of gas customers served increased by approximately 1,000, including seasonal accounts, over the previous year. Based on weather data collected in the Company’s natural gas service areas, on average there were 6.7%0.4% fewer Effective Degree Days (EDD) in 2019, on average,2021 compared to 2018.2020 and 8.2% fewer EDD compared to normal. However, there were 3.4% more EDD in the peak heating season in 2021 compared to the same period in 2020. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 4.2%2.8% higher in 20192021 compared to 2018. As of December 31, 2019 the number of natural gas customers served increased by 1,152 over the previous year.
Operation and Maintenance (O&M) expenses decreased $2.3increased $3.0 million in 20192021 compared to 2018. Excluding thenon-recurringadjustment discussed above which increased gas revenue2020, reflecting higher labor costs of $1.6 million and O&M expenses by $1.2 million in the second quarter of 2018 in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility; O&M expenses decreased $1.1 million in 2019 compared to 2018. The decrease in 2019 includes $2.4 million of lower labor and other costs related to the divestiture of Usource. Excluding the lower expenses associated with the Usource divestiture and the 2018non-recurringadjustment; O&M expenses were higher by $1.3 million. The change in O&M expenses reflects higher utility operating costs of $0.7 million, higher labor costs of $0.5 million, and higher professional fees of $0.1$1.4 million.
Depreciation and Amortization expense increased $1.6$5.0 million in 20192021 compared to 2018,2020, reflecting increasedadditional depreciation onassociated with higher levels of utility plant in service partially offset by lowerand higher amortization.
Taxes Other Than Income Taxes increased $0.3$0.6 million in 20192021 compared to 2018,2020, reflecting higher payroll taxes and higher local property tax ratestaxes on higher levels of utility plant in service, partially offset by $1.0 million of property tax abatements received in 2019.
Interest Expense, Net decreased $0.3increased $1.8 million in 20192021 compared to 20182020 primarily reflecting lowerhigher interest on long-term debt and higherlower interest income, on Allowance for Funds Used During Construction (AFUDC), partially offset by interestlower rates on higherlower levels of short-term borrowings.debt.
Other (Income) Expense (Income), Net changed from an expense of $5.8decreased $0.6 million in 20182021 compared to income of $8.6 million in 2019, a net change of $14.4 million. This change primarily reflects apre-taxgain of
Federal and State Income Taxes increased $5.4$1.3 million in 20192021 compared to 20182020, reflecting income taxes associated with the gain on the Company’s divestiture of Usource, discussed above, and higher
pre-tax
earnings in the current period.In 2019,2021, Unitil’s annual common dividend was $1.48$1.52 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January 20202022 meeting, the
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Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.375$0.39 per share, an increase of $0.005$0.01 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.50$1.56 per share from $1.48$1.52 per share.
2020 Compared to 20172019
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Therm Sales (millions) | Change | |||||||||||||||||||||||||||
2019 vs. 2018 | 2018 vs. 2017 | |||||||||||||||||||||||||||
2019 | 2018 | 2017 | Therms | % | Therms | % | ||||||||||||||||||||||
Residential | 48.0 | 48.7 | 43.4 | (0.7 | ) | (1.4 | %) | 5.3 | 12.2 | % | ||||||||||||||||||
Commercial & Industrial | 184.1 | 182.4 | 170.4 | 1.7 | 0.9 | % | 12.0 | 7.0 | % | |||||||||||||||||||
Total Therm Sales | 232.1 | 231.1 | 213.8 | 1.0 | 0.4 | % | 17.3 | 8.1 | % | |||||||||||||||||||
Gas Operating Revenues and Sales Margin (millions) | ||||||||||||||||||||||||||||
Change | ||||||||||||||||||||||||||||
2019 vs. 2018 | 2018 vs. 2017 | |||||||||||||||||||||||||||
2019 | 2018 | 2017 | $ | % | $ | % | ||||||||||||||||||||||
Gas Operating Revenue: | ||||||||||||||||||||||||||||
Residential | $ | 81.2 | $ | 86.0 | $ | 77.3 | $ | (4.8 | ) | (5.6 | %) | $ | 8.7 | 11.3 | % | |||||||||||||
Commercial & Industrial | 122.2 | 130.1 | 116.7 | (7.9 | ) | (6.1 | %) | 13.4 | 11.5 | % | ||||||||||||||||||
Total Gas Operating Revenue | $ | 203.4 | $ | 216.1 | $ | 194.0 | $ | (12.7 | ) | (5.9 | %) | $ | 22.1 | 11.4 | % | |||||||||||||
Cost of Gas Sales | $ | 81.2 | $ | 99.2 | $ | 84.3 | $ | (18.0 | ) | (18.1 | %) | $ | 14.9 | 17.7 | % | |||||||||||||
Gas Sales Margin | $ | 122.2 | $ | 116.9 | $ | 109.7 | $ | 5.3 | 4.5 | % | $ | 7.2 | 6.6 | % | ||||||||||||||
Electric Sales, Revenues and Adjusted Gross Margin
Kilowatt-hour Sales
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Unitil’s total electric kWh sales increased 3.2% in 2018 compared to 2017.2020 were essentially on par with 2019. Sales to Residential customers increased 6.5% and sales to C&I customers increased 5.6% and 1.6%, respectively,decreased 4.5% in 20182020 compared to 2017, reflecting2019. The increase in sales to Residential customers reflects higher consumption by Residential customers due to the coronavirus pandemic and warmer summer weather in 2020 compared to 2019, which resulted in higher use of air conditioning, and customer growthgrowth. As of December 31, 2020, the number of electric customers served increased by 948 over the previous year. These positive effects on 2020 electric kWh sales were partially offset by the warmer winter weather in 2020 which adversely affected the usage of electricity for heating purposes. The decrease in sales to C&I customers reflects lower usage as a result of the economic slowdown caused by the coronavirus pandemic, and warmer-than-average summer temperaturesthe warmer winter weather in 2018.2020, partially offset by customer growth. Based on weather data collected in the Company’s electric service areas, there were 42.2%37.9% more CDD in 20182020, on average, compared to 2017. As of December 31, 2018, the number of electric customers served increased by 593 over the last year.2019.
The following table details total kWh sales for the last three years by major customer class:
kWh Sales (millions) | Change | |||||||||||||||||||||||||||
2019 vs. 2018 | 2018 vs. 2017 | |||||||||||||||||||||||||||
2019 | 2018 | 2017 | kWh | % | kWh | % | ||||||||||||||||||||||
Residential | 648.2 | 685.5 | 649.4 | (37.3 | ) | (5.4 | %) | 36.1 | 5.6 | % | ||||||||||||||||||
Commercial & Industrial | 947.5 | 990.3 | 974.7 | (42.8 | ) | (4.3 | %) | 15.6 | 1.6 | % | ||||||||||||||||||
Total kWh Sales | 1,595.7 | 1,675.8 | 1,624.1 | (80.1 | ) | (4.8 | %) | 51.7 | 3.2 | % | ||||||||||||||||||
kWh Sales (millions) | Change | |||||||||||||||||||||||||||
2021 vs. 2020 | 2020 vs. 2019 | |||||||||||||||||||||||||||
2021 | 2020 | 2019 | kWh | % | kWh | % | ||||||||||||||||||||||
Residential | 694.2 | 690.6 | 648.2 | 3.6 | 0.5 | % | 42.4 | 6.5 | % | |||||||||||||||||||
Commercial & Industrial | 936.8 | 905.3 | 947.5 | 31.5 | 3.5 | % | (42.2 | ) | (4.5 | %) | ||||||||||||||||||
Total kWh Sales | 1,631.0 | 1,595.9 | 1,595.7 | 35.1 | 2.2 | % | 0.2 | — | ||||||||||||||||||||
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Electric Operating Revenues and SalesElectric Adjusted Gross Margin
Electric Operating Revenues and Sales Margin (millions) | ||||||||||||||||||||||||||||
Change | ||||||||||||||||||||||||||||
2019 vs. 2018 | 2018 vs. 2017 | |||||||||||||||||||||||||||
2019 | 2018 | 2017 | $ | % | $ | % | ||||||||||||||||||||||
Electric Operating Revenue: | ||||||||||||||||||||||||||||
Residential | $ | 133.8 | $ | 127.2 | $ | 115.5 | $ | 6.6 | 5.2 | % | $ | 11.7 | 10.1 | % | ||||||||||||||
Commercial & Industrial | 100.1 | 96.1 | 90.7 | 4.0 | 4.2 | % | 5.4 | 6.0 | % | |||||||||||||||||||
Total Electric Operating Revenue | $ | 233.9 | $ | 223.3 | $ | 206.2 | $ | 10.6 | 4.7 | % | $ | 17.1 | 8.3 | % | ||||||||||||||
Cost of Electric Sales | $ | 142.0 | $ | 131.4 | $ | 114.0 | $ | 10.6 | 8.1 | % | $ | 17.4 | 15.3 | % | ||||||||||||||
Electric Sales Margin | $ | 91.9 | $ | 91.9 | $ | 92.2 | $ | — | — | $ | (0.3 | ) | (0.3 | %) | ||||||||||||||
Other Revenue (millions) | ||||||||||||||||||||||||||||
Change | ||||||||||||||||||||||||||||
2019 vs. 2018 | 2018 vs. 2017 | |||||||||||||||||||||||||||
2019 | 2018 | 2017 | $ | % | $ | % | ||||||||||||||||||||||
Usource | $ | 0.9 | $ | 4.7 | $ | 6.0 | $ | (3.8 | ) | (80.9 | %) | $ | (1.3 | ) | (21.7 | %) | ||||||||||||
Total Other Revenue | $ | 0.9 | $ | 4.7 | $ | 6.0 | $ | (3.8 | ) | (80.9 | %) | $ | (1.3 | ) | (21.7 | %) | ||||||||||||
Electric Operating Revenues and Electric Adjusted Gross Margin (millions) | ||||||||||||||||||||||||||||
Change | ||||||||||||||||||||||||||||
2021 vs. 2020 | 2020 vs. 2019 | |||||||||||||||||||||||||||
2021 | 2020 | 2019 | $ | % | $ | % | ||||||||||||||||||||||
Electric Operating Revenue: | ||||||||||||||||||||||||||||
Residential | $ | 140.8 | $ | 134.7 | $ | 133.8 | $ | 6.1 | 4.5 | % | $ | 0.9 | 0.7% | |||||||||||||||
Commercial & Industrial | 107.7 | 92.5 | 100.1 | 15.2 | 16.4 | % | (7.6 | ) | (7.6%) | |||||||||||||||||||
Total Electric Operating Revenue | $ | 248.5 | $ | 227.2 | $ | 233.9 | $ | 21.3 | 9.4 | % | $ | (6.7 | ) | (2.9%) | ||||||||||||||
Cost of Electric Sales | $ | 151.1 | $ | 134.3 | $ | 142.0 | $ | 16.8 | 12.5 | % | $ | (7.7 | ) | (5.4%) | ||||||||||||||
Electric | 97.4 | $ | 92.9 | $ | 91.9 | $ | 4.5 | 4.8 | % | $ | 1.0 | 1.1% | ||||||||||||||||
Electric Adjusted Gross Margin (a non-GAAP financial measure) was $97.4 million in 2021, an increase of $4.5 million compared with 2020. The increase was driven by higher rates and customer growth of $4.5 million.
The increase in Total Electric Operating Revenue of $21.3 million, or 9.4%, in 2021 compared to 2020 reflects higher cost of electric sales, which are tracked and reconciled costs as a pass-through to customers, and higher sales of electricity.
Electric Adjusted Gross Margin (a non-GAAP financial measure) was $92.9 million in 2020, an increase of $1.0 million compared with 2019. The increase reflects higher rates of $1.4 million and the positive combined effect of customer growth and warmer summer weather of $0.4 million, partially offset by an unfavorable effect of $0.8 million attributed to the combined net effect of lower C&I sales and higher Residential sales associated with the coronavirus pandemic.
The decrease in Total Electric Operating Revenue of $6.7 million, or 2.9%, in 2020 compared to 2019 reflects lower cost of electric sales, which are tracked and reconciled costs as a pass-through to customers, partially offset by higher sales of electricity.
Gas Sales, Revenues and Adjusted Gross Margin
Therm Sales
Unitil’s total therm sales of natural gas decreased 7.5% in 2020 compared to 2019. Sales to Residential and C&I customers decreased 6.9% and 7.6%, respectively in 2020 compared to 2019. The decrease in overall gas therm sales in the Company’s service areas reflects warmer weather in 2020 compared to 2019, as well as lower sales to C&I customers, primarily in the second, third and fourth quarters, due to the economic slowdown caused by the coronavirus pandemic. These negative effects on 2020 gas therm sales were partially offset by customer growth. As of December 31, 2020, the number of gas customers served increased by 1,663, including seasonal accounts, over the previous year. Based on weather data collected in the Company’s gas service areas, there were 8.2% fewer EDD in 2020, on average, compared to 2019 and 8.0% fewer EDD compared to normal. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were 1.6% lower in 2020 compared to 2019.
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The following table details total therm sales for the last three years, by major customer class:
Therm Sales (millions) | Change | |||||||||||||||||||||||||||
2021 vs. 2020 | 2020 vs. 2019 | |||||||||||||||||||||||||||
2021 | 2020 | 2019 | Therms | % | Therms | % | ||||||||||||||||||||||
Residential | 44.4 | 44.7 | 48.0 | (0.3 | ) | (0.7 | %) | (3.3 | ) | (6.9 | %) | |||||||||||||||||
Commercial & Industrial | 177.5 | 170.1 | 184.1 | 7.4 | 4.4 | % | (14.0 | ) | (7.6 | %) | ||||||||||||||||||
Total Therm Sales | 221.9 | 214.8 | 232.1 | 7.1 | 3.3 | % | (17.3 | ) | (7.5 | %) | ||||||||||||||||||
Gas Operating Revenues and Adjusted Gross Margin
—
Gas Operating Revenues and Gas Adjusted Gross Margin (millions) | ||||||||||||||||||||||||||||
Change | ||||||||||||||||||||||||||||
2021 vs. 2020 | 2020 vs. 2019 | |||||||||||||||||||||||||||
2021 | 2020 | 2019 | $ | % | $ | % | ||||||||||||||||||||||
Gas Operating Revenue: | ||||||||||||||||||||||||||||
Residential | $ | 90.6 | $ | 78.0 | $ | 81.2 | $ | 12.6 | 16.2 | % | $ | (3.2 | ) | (3.9%) | ||||||||||||||
Commercial & Industrial | 134.2 | 113.4 | 122.2 | 20.8 | 18.3 | % | (8.8 | ) | (7.2%) | |||||||||||||||||||
Total Gas Operating Revenue | $ | 224.8 | $ | 191.4 | $ | 203.4 | $ | 33.4 | 17.5 | % | $ | (12.0 | ) | (5.9%) | ||||||||||||||
Cost of Gas Sales | $ | 91.7 | $ | 68.8 | $ | 81.2 | $ | 22.9 | 33.3 | % | $ | (12.4 | ) | (15.3%) | ||||||||||||||
Gas Adjusted Gross Margin | $ | 133.1 | $ | 122.6 | $ | 122.2 | $ | 10.5 | 8.6 | % | $ | 0.4 | 0.3% | |||||||||||||||
Gas Adjusted Gross Margin (a non-GAAP financial measure) was $133.1 million in 2021, an increase of $10.5 million compared to 2020. The increase was driven by higher rates and customer growth of $9.4 million, and $1.1 million from the favorable effect of colder weather during the peak heating season in 2021.
The increase in Total Gas Operating Revenues of $33.4 million, or 17.5%, in 2021 compared to 2020 reflects higher cost of gas sales, which are tracked and reconciled costs as a pass-through to customers, and higher gas sales volumes.
Gas Adjusted Gross Margin (a non-GAAP financial measure) was $122.6 million in 2020, an increase of $0.4 million compared to 2019. The increase was driven by higher rates of $5.1 million and customer growth of $1.8 million, largely offset by unfavorable effects of $4.4 million from lower sales due to warmer weather in 2020, and $2.1 million attributed to lower sales primarily associated with the economic slowdown caused by the coronavirus pandemic.
The decrease in Total Gas Operating Revenues of $12.0 million, or 5.9%, in 2020 compared to 2019 reflects lower cost of gas sales, which are tracked and reconciled costs as a pass-through to customers, and lower sales volumes.
Operating Revenue—Other
Total Other Operating Revenue (See “Other Operating Revenue—Non-regulated” in Note 1 to the accompanying Consolidated Financial Statements) is comprised of revenues from the Company’s non-regulated energy brokering business, Usource, which was divested in the first quarter of 2019 (See “Divestiture of Non-Regulated Business Subsidiary” in Note 1 to the accompanying Consolidated Financial Statements). Usource’s revenues were primarily derived from fees and charges billed to suppliers as customers take delivery of energy from those suppliers under term contracts brokered by Usource. Usource’s revenues were $0.9 million in 2019.
Operating Expenses
Cost of Electric Sales
26
efficiency programs. Cost of Electric Sales increased $16.8 million, or 12.5%, in 2021 compared to 2020. This increase reflects higher sales of electricity and higher wholesale electricity prices, partially offset by an increase in the amount of electricity purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.
In 2020, Cost of Electric Sales decreased $7.7 million, or 5.4%, compared to 2019. This decrease reflects lower wholesale electricity prices, partially offset by slightly higher sales of electricity and a decrease in the amount of electricity purchased by customers directly from third-party suppliers.
Cost of Gas Sales
—
In 2020, Cost of Gas decreased $12.4 million, or 15.3%, compared to 2019. This decrease reflects lower wholesale gas commodity prices and lower gas sales, partially offset by a decrease in the amount of gas purchased by customers directly from third-party suppliers.
Operation and Maintenance
—
In 2020, total O&M expenses decreased $1.5 million, or 2.2% compared to 2019. The decrease includes $0.4 million of lower operating costs attributed to Usource operations incurred in the first quarter of 2019. The change in O&M expenses also reflects lower labor costs of $1.3 million, partially offset by higher utility operating costs of $0.2 million. The lower labor costs reflect lower employee benefit costs.
Depreciation and Amortization
—
In 2020, Depreciation and Amortization expense increased $2.5 million, or 4.8%, compared to 2019, reflecting increased depreciation on higher levels of utility plant in service and higher amortization.
Taxes Other Than Income Taxes—
In 2020, Taxes Other Than Income Taxes increased $1.2 million, or 5.3%, compared to 2019, reflecting higher local property taxes on higher utility plant in service of $1.2 million as well as the absence in 2020 of $0.6 million in property tax abatements recognized in 2019. This increase was partially offset by lower payroll taxes in 2020 reflecting the recognition of $0.6 million of payroll tax credits associated with the CARES Act in 2020.
Interest Expense, Net
Interest expense is presented in the Consolidated Financial Statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and short-term borrowings (See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements). Certain reconciling rate mechanisms used by the Company’s distribution utilities give rise to regulatory assets and regulatory liabilities on which interest is calculated.
27
Interest Expense, Net increased $1.8 million, or 7.6%, in 2021 compared to 2020 primarily reflecting higher interest on long-term debt and lower interest income, partially offset by lower rates on lower levels of short-term debt.
Interest Expense, Net increased $0.1 million, or 0.4%, in 2020 compared to 2019 reflecting higher levels of long-term debt, largely offset by lower rates on short-term debt and lower interest expense on regulatory liabilities.
Other (Income) Expense, Net
Other Expense (Income), Net decreased $0.6 million, or 11.5% in 2021 compared to 2020, reflecting lower retirement benefit and other costs.
Other Expense (Income), Net changed from income of $8.6 million in 2019 to expense of $5.2 million in 2020, a net change of $13.8 million. This change primarily reflects a pre-tax gain of $13.4 million on the Company’s divestiture of Usource in the first quarter of 2019 and $0.4 million of other costs in 2020.
Provision for Income Taxes
Federal and State Income Taxes increased $1.3 million in 2021 compared to 2020, reflecting higher pre-tax earnings in the current period.
Federal and State Income Taxes decreased $3.6 million in 2020 compared to 2019, primarily reflecting lower pre-tax earnings in the current period.
LIQUIDITY, COMMITMENTS AND CAPITAL REQUIREMENTS
Sources of Capital
Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally generated funds, which consist of cash flows from operating activities. The Company initially supplements internally generated funds through short-term bank borrowings, as needed, under its unsecured revolving Credit Facility. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term nature of its utility assets. Additionally, from time to time the Company has accessed the public capital markets through public offerings of equity securities. The Company’s utility operations are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The amount, type and timing of any future financing will vary from year to year based on capital needs and maturity or redemptions of securities.
On August 6, 2021, the Company issued and sold 800,000 shares of its common stock at a price of $50.80 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $38.6 million and was used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes.
As part of the Offering, the Company granted the underwriters a 30-day over-allotment option to purchase additional shares. The underwriters exercised the over-allotment option and purchased an additional 120,000 shares of the Company’s common stock on September 8, 2021. The Company’s net increase to Common Equity and Cash proceeds from the over-allotment sales was approximately $5.9 million and was used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes.
The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (Cash Pool). The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool allows for an efficient exchange of cash among the Company and its subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on actual interest costs from lenders under the Company’s revolving Credit Facility. At December 31, 2021 and December 31, 2020, the Company and all of its subsidiaries were in compliance with the regulatory requirements governing participation in the Cash Pool.
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On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement (Credit Facility) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit agreement, dated as of October 4, 2013, as amended. The Credit Facility extends to July 25, 2023, subject to two one-year extensions and has a borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate (LIBOR) plus 1.125%. The terms of the current credit facility allow for a comparable successor rate to be used if the one-month LIBOR rate becomes unavailable. The Company believes that a change to a new rate will not have a material effect on its financial position, operating results, or cash flows. Provided there is no event of default, the Company may increase the borrowing limit under the Credit Facility by up to $50 million.
The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $239.1 million and $248.9 million for the years ended December 31, 2021 and December 31, 2020, respectively. Total gross repayments were $229.7 million and $252.8 million for the years ended December 31, 2021 and December 31, 2020, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2021 and December 31, 2020:
Revolving Credit Facility (millions) | ||||||||
December 31, | ||||||||
2021 | 2020 | |||||||
Limit | $ | 120.0 | $ | 120.0 | ||||
Short-Term Borrowings Outstanding | $ | 64.1 | $ | 54.7 | ||||
Letters of Credit Outstanding | $ | — | $ | 0.1 | ||||
Available | $ | 55.9 | $ | 65.2 | ||||
The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized).
The Company is monitoring the coronavirus pandemic, and does not believe the pandemic will adversely affect its access to capital and funding sources, or its planned capital expenditures. The Company believes its future operating cash flows, its available borrowing capacity, and its access to private and public capital markets for the issuance of long-term debt and equity securities will be sufficient to meet its working capital and capital investment needs.
The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2021 and December 31, 2020, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 4 (Debt and Financing Arrangements.)
Issuance of Long-Term Debt
On September 15, 2020, Northern Utilities issued $40 million of Notes due 2040 at 3.78%. Fitchburg issued $27.5 million of Notes due 2040 at 3.78%. Unitil Energy issued $27.5 million of Bonds due 2040 at 3.58%. Northern Utilities, Fitchburg and Unitil Energy used the net proceeds from these offerings to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.
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On December 18, 2019, Unitil Corporation issued $30 million of Notes due 2029 at 3.43%. Unitil Corporation used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.2 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.
On September 12, 2019, Northern Utilities issued $40 million of Notes due 2049 at 4.04%. Northern Utilities used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.2 million of costs associated with these issuances have recorded as a reduction to against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.
Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services. Unitil Corporation and Granite State are currently rated “Baa2”, and Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1” by Moody’s Investors Services.
The continued availability of various methods of financing, as well as the choice of a specific form of security for such financing, will depend on many factors, including, but not limited to: security market conditions; general economic climate; regulatory approvals; the ability to meet covenant issuance restrictions; the level of earnings, cash flows and financial position; and the competitive pricing offered by financing sources. The Company believes it has sufficient sources of working capital to fund its operations.
Contractual Obligations
The Company and its subsidiaries have material obligations for payment of principal and interest on its long-term debt as well as for operating and capital leases that are discussed in Note 4 (Debt and Financing Arrangements).
The Company and its subsidiaries have material energy supply commitments that are discussed in Note 6 (Energy Supply) and Note 7 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements. Cash outlays for the purchase of electricity and natural gas to serve customers are subject to reconciling recovery through periodic changes in rates, with carrying charges on deferred balances. From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time. Rate recovery mechanisms are typically designed to collect the under-recovered cash or refund the over-collected cash over subsequent periods of less than one year.
The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of December 31, 2021, there were approximately $ 0.7 million of guarantees outstanding with a duration of less than one year.
Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $8.3 million and $5.4 million of natural gas storage inventory at December 31, 2021 and 2020, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2021, which was payable in January 2022, was $1.6 million and was recorded in Accounts Payable at December 31, 2021. The amount of natural gas inventory released in December 2020, which was payable in January 2021, was $1.0 million and was recorded in Accounts Payable at December 31, 2020.
Revolving Credit Facility (millions) | ||||||||
December 31, | ||||||||
2019 | 2018 | |||||||
Limit | $ | 120.0 | $ | 120.0 | ||||
Short-Term Borrowings Outstanding | $ | 58.6 | $ | 82.8 | ||||
Letters of Credit Outstanding | $ | 0.1 | $ | — | ||||
Available | $ | 61.3 | $ | 37.2 | ||||
Payments Due by Period | ||||||||||||||||||||
Contractual Obligations (millions) as of December 31, 2019 | Total | 2020 | 2021— 2022 | 2023— 2024 | 2025 & Beyond | |||||||||||||||
Long-Term Debt | $ | 460.5 | $ | 19.8 | $ | 36.8 | $ | 13.4 | $ | 390.5 | ||||||||||
Interest on Long-Term Debt | 340.4 | 23.8 | 44.5 | 40.3 | 231.8 | |||||||||||||||
Gas Supply Contracts | 584.8 | 45.6 | 96.7 | 82.0 | 360.5 | |||||||||||||||
Electric Supply Contracts | 14.2 | 2.0 | 2.4 | 2.4 | 7.4 | |||||||||||||||
Other (Including Capital and Operating Lease Obligations) | 5.1 | 1.7 | 2.3 | 1.0 | 0.1 | |||||||||||||||
Total Contractual Cash Obligations | $ | 1,405.0 | $ | 92.9 | $ | 182.7 | $ | 139.1 | $ | 990.3 | ||||||||||
Benefit Plan Funding
The Company, along with its subsidiaries, made cash contributions to its Pension Plan in the amounts of $6.9$4.1 million and $16.6$4.7 million in 20192021 and 2018,2020, respectively. The Company, along with its subsidiaries,
contributed $4.0$8.9 million and $4.2 million to Voluntary Employee Benefit Trusts (VEBTs) in each of 20192021 and 2018.2020, respectively. The Company, along with its subsidiaries, expects to continue to make contributions to
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its Pension Plan and the VEBTs in 20202022 and future years at least at minimum required andamounts. The Company may also make additional discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these benefit plans.contributions. See Note 109 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements.
Off-Balance
Sheet ArrangementsThe Company and its subsidiaries do not currently use, and are not dependent on the use of,Additionally, asAs of December 31, 2019,2021, there were approximately $6.2$0.7 million of guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities outstanding. See Note 54 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.
off-balance
sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. Cash Flows
Unitil’s utility operations, taken as a whole, are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The tables below summarize the major sources and uses of cash (in millions) for 20192021 and 2018.2020.
2019 | 2018 | |||||||
Cash Provided by Operating Activities | $ | 104.9 | $ | 78.5 | ||||
2021 | 2020 | |||||||
Cash Provided by Operating Activities | $ | 107.8 | $ | 75.7 | ||||
Cash Provided by Operating Activities
—
Cash flow from Net Income, adjusted for the total of$96.3$106.4 million in 20192021 compared to $91.4$96.0 million in 2018,2020, an increase of $4.9$10.4 million. The change to Net Income is primarily dueattributable to an increaseincreases in natural electric and gas sales marginsmargin and customer growth. The increase in depreciation and amortization of $1.6$5.0 million in 20192021 compared to 20182020 reflects higher depreciation on higher utility plant in service. The increase in the deferred tax provision of $5.5$1.5 million in 20192021 compared to 20182020 is primarily a result of increaseddriven by higher tax depreciation deductionsrepairs and deferred tax reductions related to the TCJA revaluations.depreciation.
non-cash
charges was Changes in working capital items resulted in a $13.9$6.2 million source of cash in 20192021 compared to a $3.9($15.3) million sourceuse of cash in 2018,2020, representing an increase of $10.0$21.5 million. The change in working capital in 20192021 compared to 20182020 is primarily related to the change in accounts payable and accrued revenue and is reflective of normal fluctuations inthe effect of the current macroeconomic environment on business and operating conditions.
Deferred Regulatory and Other Charges increased by $6.0$6.6 million in 20192021 compared to 2018. The2020, primarily driven by changes in Regulatory Assets and Liabilities, and the change in Other, net in 20192021 compared to 20182020 was $5.5 million, primarily driven by decreased contributions to the Company’s retirement plans.($6.4) million.
2019 | 2018 | |||||||
Cash Used in Investing Activities | $ | (105.8 | ) | $ | (102.4 | ) | ||
2021 | 2020 | |||||||
Cash Used in Investing Activities | $ | (115.0 | ) | $ | (122.6 | ) | ||
Cash Used in Investing Activities
—
2019 | 2018 | |||||||
Cash (Used In) Provided by Financing Activities | $ | (1.7 | ) | $ | 22.8 | |||
2021 | 2020 | |||||||
Cash Provided by Financing Activities | $ | 7.7 | $ | 47.7 | ||||
Cash (Used in) Provided by Financing Activities
—
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FINANCIAL COVENANTS AND RESTRICTIONS
The agreements under which the Company and its subsidiaries issue long-term debt contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions, business combinations and covenants restricting the ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity or (iv) sell, lease or otherwise dispose of all or substantially all assets. See Note 54 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.
Unitil’s Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 20192021 and December 31, 2018,2020, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.
The Company and its subsidiaries are currently in compliance with all such covenants in these debt instruments.
DIVIDENDS
Unitil’s annual common dividend was $1.48$1.52 per common share in 2019, $1.462021, $1.50 per common share in 2018,2020, and $1.44$1.48 per share in 2017.2019. Unitil’s dividend policy is reviewed periodically by the Board of Directors. Unitil has maintained an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January 20202022 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.375$0.39 per share, an increase of $0.005$.01 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.50$1.56 from $1.48.$1.52. The amount and timing of all dividend payments are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. In addition, the ability of the Company’s subsidiaries to pay dividends or make distributions to Unitil, and, therefore, Unitil’s ability to pay dividends, depends on, among other things:
the actual and projected earnings and cash flow, capital requirements and general financial condition of the Company’s subsidiaries;
the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by the Company’s subsidiaries;
the restrictions on the payment of dividends contained in the existing loan agreements of the Company’s subsidiaries and that may be contained in future debt agreements of the Company’s subsidiaries, if any; and
limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory agencies.
In addition, before the Company can pay dividends on its common stock, it has tomust satisfy its debt obligations and comply with any statutory or contractual limitations. See, above,in this report, as well as Note 54 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.
Financial Covenants and Restrictions
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LEGAL PROCEEDINGS
The Company is involved in legal and administrative proceedings and claims of various types, including those which arise in the ordinary course of business. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these claims will not have a material impacteffect on its financial position, operating results or cash flows. Refer to “Legal Proceedings” in Note 87 (Commitments and Contingencies) of the Consolidated Financial Statements for a discussion of legal proceedings.
REGULATORY MATTERS
See Note 87 (Commitments and Contingencies) to the Consolidated Financial Statements.
CRITICAL ACCOUNTING POLICIES
The preparation of the Company’s Consolidated Financial Statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, the Company is sometimes required to make difficult, subjective and/or complex judgments about the impacteffect of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in its financial statements. If actual results were to differ significantly from those estimates, assumptions and judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies where judgments or uncertainties could materially affect the application of those policies. For a complete discussion of the Company’s significant accounting policies, refer to the financial statements and Note 1: Summary1 (Summary of Significant Accounting Policies.Policies).
Regulatory Accounting
—
The FASB Codification specifies the economic effects that result from the cause and effect relationship of costs and revenues in the rate-regulated environment and how these effects are to be accountedthe related accounting for by a regulated enterprise. Revenues intended to cover somecertain costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets.” If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities.”
The Company’s principal regulatory assets and liabilities are included on the Company’s Consolidated Balance Sheet and a summary of the Company’s Regulatory Assets is provided in Note 1 thereto.(Summary of Significant Accounting Policies) to the consolidated financial statements. Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impacteffect on the Company’s consolidated financial statements.
The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of
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its assets or operations, were to cease meeting the criteria for application of these accounting rules,
accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.
Utility Revenue Recognition
—
Retirement Benefit Obligations
—
non-qualified
retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.The FASB Codification requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates. The Company’s RBO and reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. The Company has made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. The Company’s RBO areis affected by actual employee demographics, the level of contributions made to the plans, earnings on plan assets, and health care cost trends. Changes made to the provisions of these plans may also affect current and future costs. If these assumptions were changed, the resultantresulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impacteffect on the Company’s financial statements. The discount rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For the year ended December 31, 2019,2021, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $534,000$679,000 in the Net Periodic Benefit Cost for the Pension Plan. Similarly, a change of 0.50% in the expected long-term rate of return on plan assets would have resulted in an increase or decrease of approximately $565,000$646,000 in the Net Periodic Benefit Cost for the Pension Plan. (See Note 109 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements.)
Income Taxes
—
temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with the FASB Codification
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guidance on Income Taxes. The Company classifies penaltypenalties and interest expense related to income tax liabilities as income tax expense and interest expense, respectively, in the Consolidated Statements of Earnings.
Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. Periodically, theThe Company assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances that gave rise to the revision become known.
Commitments and Contingencies
—
Refer to “Recently Issued Pronouncements” in Note 1 of the Notes of Consolidated Financial Statements for information regarding recently issued accounting standards.
For furtheradditional information regarding the foregoing matters, see Note 1 (Summary of Significant Accounting Policies), Note 9 (Income Taxes), Note 76 (Energy Supply), Note 107 (Commitments and Contingencies), Note 8 (Income Taxes), and Note 9 (Retirement Benefit Plans) and Note 8 (Commitment and Contingencies) to the Consolidated Financial Statements.
Item 7A. | Quantitative and Qualitative Disclosures about Market Risk |
Please also refer to Part I, Item 1A. “Risk Factors”.
INTEREST RATE RISK
COMMODITY PRICE RISK
Although Unitil’s three distribution utilities are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of electric power and natural gas supply costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making. Additionally, as discussed in the section entitledin Part I, Item 1 (Business) and in Note 87 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements, the Company has divested its commodity-relatedlong-term power supply contracts and therefore, further reduced its exposure to commodity risk.
Rates and Regulation
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Item 8. | Financial Statements and Supplementary Data |
Report of Independent Registered Public Accounting Firm
To the shareholders and the Board of Directors of Unitil Corporation:
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Unitil Corporation and subsidiaries (the “Company”) as of December 31, 20192021 and 2018,2020, the related consolidated statements of earnings, changes in common stock equity, and cash flows, for each of the three years in the period ended December 31, 2019,2021, and the related notes (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2021, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of
records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
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of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate-Regulation on Various Account Balances and Disclosures—Refer to Notes 1 and 87 to the financial statements
Critical Audit Matter Description
The Company’s principal business is the distribution of electricity and natural gas and is subject to regulation by the Massachusetts, New Hampshire and Maine Public Service Commissions as well as the Federal Energy Regulatory Commission (the(collectively, the “Commissions”). Accordingly, the Company accounts for their regulated operations in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 980, - , and has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable Commission. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.
Regulated Operations
Accounting for the economics of rate regulation affects multiple financial statement line items, including property, plant, and equipment; regulatory assets and liabilities; operating revenues; and depreciation expense, and affects multiple disclosures in the Company’s financial statements. While the Company has indicated that it expects to recover costs and a return on its investments, there is a risk that the CommissionsCommissions’ will not approve full recovery of the costs of providing utility service or recovery of all amounts invested in the utility business and a reasonable return on that investment. As a result, we identified the impact of rate regulation as a critical audit matter due to the high degree of subjectivity involved in assessing the impact of current and future regulatory orders on events that have occurred as of December 31, 2019,2021, and the judgments made by management to support its assertions about impacted account balances and disclosures. Management judgments included assessing the likelihood of (1) recovery in future rates of incurred costs or (2) refunds to customers or future reduction in rates. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the commissions, auditing these judgments requires specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
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How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions focused on the ongoing base rate proceedings for Northern New Hampshire and Unitil Energy Systems as well as the ongoing prudency evaluation of the CIS project for Northern Maine and included the following, among others:
We tested the effectiveness of internal controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant,relevant regulatory account balances and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness ofdisclosures, including management’s controls over the initial recognition of amounts as property, plant, and equipment, regulatory assets or liabilities, and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
We made inquiries of management and read relevant regulatory orders and settlements issued by the
Commissions in Massachusetts, New Hampshire and Maine, regulatory statutes, interpretations, procedural memorandums, filings made by interveners or the Company, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated this external information and compared to management’s recorded regulatory asset and liability balances and searched for any evidence that might contradict management’s assertions.
We obtained an analysis from management describing the orders and filings that support management’s assertions regarding the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ Deloitte & Touche LLP
Boston, MA
We have served as the Company’s auditor since 2014.
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CONSOLIDATED STATEMENTS OF EARNINGS
(Millions, except per share data)
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
Operating Revenues: | ||||||||||||
Gas | $ | 203.4 | $ | 216.1 | $ | 194.0 | ||||||
Electric | 233.9 | 223.3 | 206.2 | |||||||||
Other | 0.9 | 4.7 | 6.0 | |||||||||
Total Operating Revenues | 438.2 | 444.1 | 406.2 | |||||||||
Operating Expenses: | ||||||||||||
Cost of Gas Sales | 81.2 | 99.2 | 84.3 | |||||||||
Cost of Electric Sales | 142.0 | 131.4 | 114.0 | |||||||||
Operation and Maintenance | 67.2 | 69.5 | 64.5 | |||||||||
Depreciation and Amortization | 52.0 | 50.4 | 46.9 | |||||||||
Taxes Other Than Income Taxes | 22.7 | 22.4 | 21.1 | |||||||||
Total Operating Expenses | 365.1 | 372.9 | 330.8 | |||||||||
Operating Income | 73.1 | 71.2 | 75.4 | |||||||||
Interest Expense, Net | 23.7 | 24.0 | 23.1 | |||||||||
Other (Income) Expense, Net | (8.6 | ) | 5.8 | 5.8 | ||||||||
Income Before Income Taxes | 58.0 | 41.4 | 46.5 | |||||||||
Provision for Income Taxes | 13.8 | 8.4 | 17.5 | |||||||||
Net Income Applicable to Common Shares | $ | 44.2 | $ | 33.0 | $ | 29.0 | ||||||
Earnings per Common Share—Basic and Diluted | $ | 2.97 | $ | 2.23 | $ | 2.06 | ||||||
Weighted Average Common Shares Outstanding—(Basic and Diluted) | 14.9 | 14.8 | 14.1 | |||||||||
Year Ended December 31, | 2021 | 2020 | 2019 | |||||||||
Operating Revenues: | ||||||||||||
Electric | $ | 248.5 | $ | 227.2 | $ | 233.9 | ||||||
Gas | 224.8 | 191.4 | 203.4 | |||||||||
Other | — | — | 0.9 | |||||||||
Total Operating Revenues | 473.3 | 418.6 | 438.2 | |||||||||
Operating Expenses: | ||||||||||||
Cost of Electric Sales | 151.1 | 134.3 | 142.0 | |||||||||
Cost of Gas Sales | 91.7 | 68.8 | 81.2 | |||||||||
Operation and Maintenance | 68.7 | 65.7 | 67.2 | |||||||||
Depreciation and Amortization | 59.5 | 54.5 | 52.0 | |||||||||
Taxes Other Than Income Taxes | 24.5 | 23.9 | 22.7 | |||||||||
Total Operating Expenses | 395.5 | 347.2 | 365.1 | |||||||||
Operating Income | 77.8 | 71.4 | 73.1 | |||||||||
Interest Expense, Net | 25.6 | 23.8 | 23.7 | |||||||||
Other Expense (Income), Net | 4.6 | 5.2 | (8.6 | ) | ||||||||
Income Before Income Taxes | 47.6 | 42.4 | 58.0 | |||||||||
Provision for Income Taxes | 11.5 | 10.2 | 13.8 | |||||||||
Net Income Applicable to Common Shares | $ | 36.1 | $ | 32.2 | $ | 44.2 | ||||||
Earnings per Common Share—Basic and Diluted | $ | 2.35 | $ | 2.15 | $ | 2.97 | ||||||
Weighted Average Common Shares Outstanding—(Basic and Diluted) | 15.4 | 15.0 | 14.9 | |||||||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
CONSOLIDATED BALANCE SHEETS
(Millions)
ASSETS
December 31, | 2019 | 2018 | ||||||
Current Assets: | ||||||||
Cash and Cash Equivalents | $ | 5.2 | $ | 7.8 | ||||
Accounts Receivable, Net | 55.1 | 66.8 | ||||||
Accrued Revenue | 50.0 | 54.7 | ||||||
Exchange Gas Receivable | 6.1 | 8.1 | ||||||
Gas Inventory | 0.8 | 0.8 | ||||||
Materials and Supplies | 7.9 | 7.0 | ||||||
Prepayments and Other | 5.8 | 7.0 | ||||||
Total Current Assets | 130.9 | 152.2 | ||||||
Utility Plant: | ||||||||
Gas | 837.7 | 760.6 | ||||||
Electric | 529.7 | 500.1 | ||||||
Common | 62.7 | 83.1 | ||||||
Construction Work in Progress | 37.4 | 25.5 | ||||||
Utility Plant | 1,467.5 | 1,369.3 | ||||||
Less: Accumulated Depreciation | 356.0 | 332.5 | ||||||
Net Utility Plant | 1,111.5 | 1,036.8 | ||||||
Other Noncurrent Assets: | ||||||||
Regulatory Assets | 112.0 | 99.0 | ||||||
Operating Lease Right of Use Assets | 4.0 | — | ||||||
Other Assets | 12.4 | 10.3 | ||||||
Total Other Noncurrent Assets | 128.4 | 109.3 | ||||||
TOTAL ASSETS | $ | 1,370.8 | $ | 1,298.3 | ||||
December 31, | 2021 | 2020 | ||||||
Current Assets: | ||||||||
Cash and Cash Equivalents | $ | 6.5 | $ | 6.0 | ||||
Accounts Receivable, Net | 66.9 | 62.0 | ||||||
Accrued Revenue | 61.2 | 50.9 | ||||||
Exchange Gas Receivable | 7.4 | 4.9 | ||||||
Gas Inventory | 1.0 | 0.6 | ||||||
Materials and Supplies | 8.6 | 8.5 | ||||||
Prepayments and Other | 8.1 | 6.4 | ||||||
Total Current Assets | 159.7 | 139.3 | ||||||
| Utility Plant: | ||||||||
Electric | 602.4 | 575.9 | ||||||
Gas | 972.6 | 920.2 | ||||||
Common | 66.4 | 64.1 | ||||||
Construction Work in Progress | 47.5 | 34.8 | ||||||
Utility Plant | 1,688.9 | 1,595.0 | ||||||
Less: Accumulated Depreciation | 431.7 | 401.8 | ||||||
Net Utility Plant | 1,257.2 | 1,193.2 | ||||||
Other Noncurrent Assets: | ||||||||
Regulatory Assets | 108.9 | 127.4 | ||||||
Operating Lease Right of Use Assets | 4.7 | 5.2 | ||||||
Other Assets | 9.8 | 12.8 | ||||||
Total Other Noncurrent Assets | 123.4 | 145.4 | ||||||
TOTAL ASSETS | $ | 1,540.3 | $ | 1,477.9 | ||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
CONSOLIDATED BALANCE SHEETS (cont.)
(Millions, except number of shares)
LIABILITIES AND CAPITALIZATION
December 31, | 2019 | 2018 | ||||||
Current Liabilities: | ||||||||
Accounts Payable | $ | 37.6 | $ | 42.6 | ||||
Short-Term Debt | 58.6 | 82.8 | ||||||
Long-Term Debt, Current Portion | 19.5 | 18.4 | ||||||
Regulatory Liabilities | 7.4 | 11.5 | ||||||
Energy Supply Obligations | 10.5 | 13.4 | ||||||
Environmental Obligations | 0.6 | 0.6 | ||||||
Other Current Liabilities | 25.6 | 23.2 | ||||||
Total Current Liabilities | 159.8 | 192.5 | ||||||
Noncurrent Liabilities: | ||||||||
Retirement Benefit Obligations | 141.9 | 121.5 | ||||||
Deferred Income Taxes, Ne t | 103.6 | 97.8 | ||||||
Cost of Removal Obligations | 96.0 | 90.7 | ||||||
Regulatory Liabilities | 46.6 | 47.0 | ||||||
Environmental Obligations | 2.1 | 1.4 | ||||||
Other Noncurrent Liabilities | 6.5 | 8.7 | ||||||
Total Noncurrent Liabilities | 396.7 | 367.1 | ||||||
Capitalization: | ||||||||
Long-Term Debt, Less Current Portion | 437.5 | 387.4 | ||||||
Stockholders’ Equity: | ||||||||
Common Equity (Outstanding 14,930,170 and 14,876,955 Shares) | 282.5 | 279.1 | ||||||
Retained Earnings | 94.1 | 72.0 | ||||||
Total Common Stock Equity | 376.6 | 351.1 | ||||||
Preferred Stock | 0.2 | 0.2 | ||||||
Total Stockholders’ Equity | 376.8 | 351.3 | ||||||
Total Capitalization | 814.3 | 738.7 | ||||||
Commitments and Contingencies | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | $ | 1,370.8 | $ | 1,298.3 | ||||
December 31, | 2021 | 2020 | ||||||
Current Liabilities: | ||||||||
Accounts Payable | $ | 52.4 | $ | 33.2 | ||||
Short-Term Debt | 64.1 | 54.7 | ||||||
Long-Term Debt, Current Portion | 8.2 | 8.5 | ||||||
Regulatory Liabilities | 9.5 | 5.5 | ||||||
Energy Supply Obligations | 14.5 | 10.4 | ||||||
Environmental Obligations | 0.5 | 0.3 | ||||||
Other Current Liabilities | 24.3 | 23.5 | ||||||
Total Current Liabilities | 173.5 | 136.1 | ||||||
Noncurrent Liabilities: | ||||||||
Retirement Benefit Obligations | 133.9 | 162.3 | ||||||
Deferred Income Taxes, Net | 127.7 | 109.0 | ||||||
Cost of Removal Obligations | 107.5 | 105.2 | ||||||
Regulatory Liabilities | 42.6 | 44.3 | ||||||
Environmental Obligations | 2.2 | 1.8 | ||||||
Other Noncurrent Liabilities | 6.6 | 6.9 | ||||||
Total Noncurrent Liabilities | 420.5 | 429.5 | ||||||
Capitalization: | ||||||||
Long-Term Debt, Less Current Portion | 497.8 | 523.1 | ||||||
Stockholders’ Equity: | ||||||||
Common Equity (Outstanding 15,977,766 and 15,012,310 Shares) | 332.1 | 285.3 | ||||||
Retained Earnings | 116.2 | 103.7 | ||||||
Total Common Stock Equity | 448.3 | 389.0 | ||||||
Preferred Stock | 0.2 | 0.2 | ||||||
Total Stockholders’ Equity | 448.5 | 389.2 | ||||||
Total Capitalization | 946.3 | 912.3 | ||||||
Commitments and Contingencies 7 ) | 0 | 0 | ||||||
TOTAL LIABILITIES AND CAPITALIZATION | $ | 1,540.3 | $ | 1,477.9 | ||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
Operating Activities: | ||||||||||||
Net Income | $ | 44.2 | $ | 33.0 | $ | 29.0 | ||||||
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: | ||||||||||||
Depreciation and Amortization | 52.0 | 50.4 | 46.9 | |||||||||
Deferred Tax Provision | 13.5 | 8.0 | 17.5 | |||||||||
Gain on Divestiture, net (See Note 1) | (13.4 | ) | — | — | ||||||||
Changes in Working Capital Items: | ||||||||||||
Accounts Receivable | 11.7 | 0.6 | (14.5 | ) | ||||||||
Accrued Revenue | 4.7 | (1.4 | ) | (3.8 | ) | |||||||
Regulatory Liabilities | (4.1 | ) | 2.3 | (1.2 | ) | |||||||
Exchange Gas Receivable | 2.0 | (2.3 | ) | 2.5 | ||||||||
Accounts Payable | (5.0 | ) | 1.1 | 9.1 | ||||||||
Other Changes in Working Capital Items | 4.6 | 3.6 | (1.8 | ) | ||||||||
Deferred Regulatory and Other Charges | (5.3 | ) | (11.3 | ) | (6.1 | ) | ||||||
Other, net | — | (5.5 | ) | 8.6 | ||||||||
Cash Provided by Operating Activities | 104.9 | 78.5 | 86.2 | |||||||||
Investing Activities: | ||||||||||||
Property, Plant and Equipment Additions | (119.2 | ) | (102.4 | ) | (119.3 | ) | ||||||
Proceeds from Divestiture, Net (See Note 1) | 13.4 | — | — | |||||||||
Cash Used In Investing Activities | (105.8 | ) | (102.4 | ) | (119.3 | ) | ||||||
Financing Activities: | ||||||||||||
(Repayment of) Proceeds from Short-Term Debt, net | (24.2 | ) | 44.5 | (43.6 | ) | |||||||
Issuance of Long-Term Debt | 69.6 | 29.9 | 89.3 | |||||||||
Repayment of Long-Term Debt | (18.8 | ) | (30.1 | ) | (17.2 | ) | ||||||
Decrease in Capital Lease Obligations | (5.3 | ) | (3.0 | ) | (2.5 | ) | ||||||
Net (Decrease) Increase in Exchange Gas Financing | (2.0 | ) | 2.1 | (2.4 | ) | |||||||
Dividends Paid | (22.1 | ) | (21.8 | ) | (20.4 | ) | ||||||
Proceeds from Issuance of Common Stock | 1.1 | 1.2 | 33.0 | |||||||||
Cash (Used In) Provided by Financing Activities | (1.7 | ) | 22.8 | 36.2 | ||||||||
Net (Decrease) Increase in Cash and Cash Equivalents | (2.6 | ) | (1.1 | ) | 3.1 | |||||||
Cash and Cash Equivalents at Beginning of Year | 7.8 | 8.9 | 5.8 | |||||||||
Cash and Cash Equivalents at End of Year | $ | 5.2 | $ | 7.8 | $ | 8.9 | ||||||
Supplemental Information: | ||||||||||||
Interest Paid | $ | 24.1 | $ | 24.6 | $ | 23.0 | ||||||
Income Taxes Paid | $ | 0.8 | $ | 0.4 | $ | — | ||||||
Payments on Capital Leases | $ | 5.5 | $ | 3.3 | $ | 3.3 | ||||||
Capital Expenditures Included in Accounts Payable | $ | 0.6 | $ | 0.5 | $ | 1.1 | ||||||
Non-Cash Additions to Property, Plant and Equipment | $ | — | $ | — | $ | — | ||||||
Right-of-Use Assets Obtained in Exchange for Lease Obligations | $ | 4.0 | $ | — | $ | — | ||||||
Year Ended December 31, | 2021 | 2020 | 2019 | |||||||||
Operating Activities: | ||||||||||||
Net Income | $ | 36.1 | $ | 32.2 | $ | 44.2 | ||||||
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: | ||||||||||||
Depreciation and Amortization | 59.5 | 54.5 | 52.0 | |||||||||
Deferred Tax Provision | 10.8 | 9.3 | 13.5 | |||||||||
Gain on Divestiture, net (See Note 1) | — | — | (13.4 | ) | ||||||||
Changes in Working Capital Items: | ||||||||||||
Accounts Receivable | (4.9 | ) | (6.9 | ) | 11.7 | |||||||
Accrued Revenue | (10.3 | ) | (0.9 | ) | 4.7 | |||||||
Regulatory Liabilities | 4.0 | (1.9 | ) | (4.1 | ) | |||||||
Exchange Gas Receivable | (2.5 | ) | 1.2 | 2.0 | ||||||||
Accounts Payable | 19.2 | (4.4 | ) | (5.0 | ) | |||||||
Other Changes in Working Capital Items | 0.7 | (2.4 | ) | 4.6 | ||||||||
Deferred Regulatory and Other Charges | (2.7 | ) | (9.3 | ) | (5.3 | ) | ||||||
Other, net | (2.1 | ) | 4.3 | — | ||||||||
Cash Provided by Operating Activities | 107.8 | 75.7 | 104.9 | |||||||||
Investing Activities: | ||||||||||||
Property, Plant and Equipment Additions | (115.0 | ) | (122.6 | ) | (119.2 | ) | ||||||
Proceeds from Divestiture, Net (See Note 1) | — | — | 13.4 | |||||||||
Cash Used In Inves t ing Activities | (115.0 | ) | (122.6 | ) | (105.8 | ) | ||||||
Financing Activities: | ||||||||||||
Proceeds from (Repayment of) Short-Term Debt, net | 9.4 | (3.9 | ) | (24.2 | ) | |||||||
Issuance of Long-Term Debt | — | 99.7 | 70.0 | |||||||||
Repayment of Long-Term Debt | (25.8 | ) | (24.8 | ) | (18.8 | ) | ||||||
Long-Term Debt Issuance Costs | — | (0.6 | ) | (0.4 | ) | |||||||
Decrease in Capital Lease Obligations | (0.1 | ) | (0.1 | ) | (5.3 | ) | ||||||
Net Increase (Decrease) in Exchange Gas Financing | 2.3 | (1.1 | ) | (2.0 | ) | |||||||
Dividends Paid | (23.6 | ) | (22.6 | ) | (22.1 | ) | ||||||
Proceeds from Issuance of Common Stock | 45.5 | 1.1 | 1.1 | |||||||||
| Cash Provided by (Used In) Financing Activities | 7.7 | 47.7 | (1.7 | ) | ||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | 0.5 | 0.8 | (2.6 | ) | ||||||||
Cash and Cash Equivalents at Beginning of Year | 6.0 | 5.2 | 7.8 | |||||||||
Cash and Cash Equivalents at End of Year | $ | 6.5 | $ | 6.0 | $ | 5.2 | ||||||
Supplemental Information: | ||||||||||||
Interest Paid | $ | 26.0 | $ | 23.7 | $ | 24.1 | ||||||
Income Taxes Paid | $ | 1.4 | $ | 0.9 | $ | 0.8 | ||||||
Payments on Capital Leases | $ | 0.2 | $ | 0.3 | $ | 5.5 | ||||||
Capital Expenditures Included in Accounts Payable | $ | 4.9 | $ | 1.7 | $ | 0.6 | ||||||
Right-of-Use | $ | 0.7 | $ | 1.2 | $ | 4.0 | ||||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
CONSOLIDATED STATEMENTS OF
CHANGES IN COMMON STOCK EQUITY
(Millions, except shares data)
Common Equity | Retained Earnings | Total | ||||||||||
Balance at January 1, 2017 | $ | 240.7 | $ | 52.2 | $ | 292.9 | ||||||
Net Income for 2017 | 29.0 | 29.0 | ||||||||||
Dividends ($1.44 per Common Share) | (20.4 | ) | (20.4 | ) | ||||||||
Shares Issued Under Stock Plans | 2.1 | 2.1 | ||||||||||
Issuance of 26,256 Common Shares (See Note 6) | 1.3 | 1.3 | ||||||||||
Issuance of 690,000 Common Shares (See Note 6) | 31.7 | 31.7 | ||||||||||
Balance at December 31, 2017 | 275.8 | 60.8 | 336.6 | |||||||||
Net Income for 201 8 | 33.0 | 33.0 | ||||||||||
Dividends ($1.46 per Common Share) | (21.8 | ) | (21.8 | ) | ||||||||
Shares Issued Under Stock Plans | 2.1 | 2.1 | ||||||||||
Issuance of 25,932 Common Shares (See Note 6) | 1.2 | 1.2 | ||||||||||
Balance at December 31, 2018 | 279.1 | 72.0 | 351.1 | |||||||||
Net Income for 2019 | 44.2 | 44.2 | ||||||||||
Dividends ($1.48 per Common Share) | (22.1 | ) | (22.1 | ) | ||||||||
Shares Issued Under Stock Plans | 2.3 | 2.3 | ||||||||||
Issuance of 20,065 Common Shares (See Note 6) | 1.1 | 1.1 | ||||||||||
Balance at December 31, 2019 | $ | 282.5 | $ | 94.1 | $ | 376.6 | ||||||
Common Equity | Retained Earnings | Total | ||||||||||
Balance at January 1, 2019 | $ | 279.1 | $ | 72.0 | $ | 351.1 | ||||||
Net Income for 2019 | 44.2 | 44.2 | ||||||||||
Dividends ($1.48 per Common Share) | (22.1 | ) | (22.1 | ) | ||||||||
Shares Issued Under Stock Plans | 2.3 | 2.3 | ||||||||||
Issuance of 20,065 Common Shares (See Note 5 ) | 1.1 | 1.1 | ||||||||||
Balance at December 31, 2019 | 282.5 | 94.1 | 376.6 | |||||||||
Net Income for 2020 | 32.2 | 32.2 | ||||||||||
Dividends ($1.50 per Common Share) | (22.6 | ) | (22.6 | ) | ||||||||
Shares Issued Under Stock Plans | 1.7 | 1.7 | ||||||||||
Issuance of 23,658 Common Shares (See Note 5 ) | 1.1 | 1.1 | ||||||||||
Balance at December 31, 2020 | 285.3 | 103.7 | 389.0 | |||||||||
Net Income for 2020 | 36.1 | 36.1 | ||||||||||
Dividends ($1.52 per Common Share) | (23.6 | ) | (23.6 | ) | ||||||||
Shares Issued Under Stock Plans | 1.3 | 1.3 | ||||||||||
Issuance of 942,316 Common Shares (See Note 5 ) | 45.5 | 45.5 | ||||||||||
Balance at December 31, 2021 | $ | 332.1 | $ | 116.2 | $ | 448.3 | ||||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
Note 1
Nature of Operations
—
non-regulated
business unit Unitil Resources, Inc. (Unitil Resources).The Company’s earnings are seasonal and are typically higher in the first and fourth quarters when customers
use natural gas for heating purposes.
Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has 3 distribution
utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively, referred to as the “distribution utilities”)distribution utilities).
Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to 3 major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.
A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, on May 1, 2003 Unitil Power ceased being the wholesale supplier of Unitil Energy on
and
divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. In the period since, Unitil Power continued to flow revenues and expenses from remaining contracts to Unitil Energy under the Amended Unitil System Agreement. The last of those contracts expired October 31, 2020, and the Company no longer has material revenues or expenses associated
with those contracts.
Unitil also has 3 other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-ownedof in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. Usource provided See additional discussion of the divestiture of Usource below.
non-regulated
subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource), which the Company divested energy
brokering and advisory services to large commercial and industrial customers in the northeastern United States.Divestiture of Non-Regulated Business Subsidiary
—
non-regulated
energy brokering and advisory business subsidiary, Usource. The Company recognized anafter-tax
net gain of approximatelymillion on this divestiture in the first quarter of 2019. The
pre-tax
net gain of approximatelymillion on this divestiture is included in Other Income (Expense), Net on the Consolidated Statements of Earnings for the year-ended December 31, 2019, while the income taxes associated with this transaction of
million are included in the Provision For Income Taxes.
4
4
Basis of Presentation
Principles of Consolidation
—
Use of Estimates
—
Fair Value
—
Level 1— | Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. | ||
Level 2— | Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly. | ||
Level 3— | Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. | ||
To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1
to Level 2
or from Level 2
to Level 3
There have been no changes in the valuation techniques used during the current period.
Utility Revenue Recognition—Recognition
—
Billed and unbilled revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculatedestimated each month based on estimated customer usage by class and applicable customer rates, taking into account current and historical weather data, assumptions pertaining to metering patterns, billing cycle statistics, and other estimates and assumptions, and are then reversed in the following month when billed to customers.
4535
A majority of the Company’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customer monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer.
The Company’s billed and unbilled revenuerevASU2014-09.Accounting Standards Codification (ASC) 606. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in Accounting Standards Codification (ASC)980-605-25-3,ASC 980, as the Company has the ability to adjust rates in the future as a result of past activities or completed events. ASU2014-09The rate adjustment mechanisms meet the criteria within ASC 980. In cases where allowable costs are greater than operating revenues billed in the current period for the individual rate adjustment mechanism additional operating revenue is recognized. In cases where allowable costs are less than operating revenues billed in the current period for the individual rate adjustment mechanism, operating revenue is reduced. ASC 606 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.
e
nue meets the definition of “revenues from contracts with customers” as defined in In the following tables, revenue is classified by the types of goods/services rendered and market/customer type.
Twelve Months Ended December 31, 2019 | ||||||||||||
Gas and Electric Operating Revenues (millions): | Gas | Electric | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 81.4 | $ | 121.5 | $ | 202.9 | ||||||
Commercial & Industrial | 120.1 | 93.8 | 213.9 | |||||||||
Other | 10.6 | 7.8 | 18.4 | |||||||||
Total Billed and Unbilled Revenue | 212.1 | 223.1 | 435.2 | |||||||||
Rate Adjustment Mechanism Revenue | (8.7 | ) | 10.8 | 2.1 | ||||||||
Total Gas and Electric Operating Revenues | $ | 203.4 | $ | 233.9 | $ | 437.3 | ||||||
Twelve Months Ended December 31, 2018 | ||||||||||||
Gas and Electric Operating Revenues (millions): | Gas | Electric | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 81.4 | $ | 123.6 | $ | 205.0 | ||||||
Commercial & Industrial | 119.7 | 96.4 | 216.1 | |||||||||
Other | 9.6 | 8.7 | 18.3 | |||||||||
Total Billed and Unbilled Revenue | 210.7 | 228.7 | 439.4 | |||||||||
Rate Adjustment Mechanism Revenue | 5.4 | (5.4 | ) | — | ||||||||
Total Gas and Electric Operating Revenues | $ | 216.1 | $ | 223.3 | $ | 439.4 | ||||||
Twelve Months Ended December 31, 2021 | ||||||||||||
Electric and Gas Operating Revenues (millions): | Electric | Gas | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 135.1 | $ | 83.9 | $ | 219.0 | ||||||
Commercial & Industrial | 103.3 | 124.1 | 227.4 | |||||||||
Other | 10.1 | 9.6 | 19.7 | |||||||||
Total Billed and Unbilled Revenue | 248.5 | 217.6 | 466.1 | |||||||||
Rate Adjustment Mechanism Revenue | 0 | 7.2 | 7.2 | |||||||||
Total Electric and Gas Operating Revenues | $ | 248.5 | $ | 224.8 | $ | 473.3 | ||||||
Twelve Months Ended December 31, 2020 | ||||||||||||
Electric and Gas Operating Revenues (millions): | Electric | Gas | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 128.7 | $ | 73.1 | $ | 201.8 | ||||||
Commercial & Industrial | 91.4 | 104.5 | 195.9 | |||||||||
Other | 6.6 | 7.6 | 14.2 | |||||||||
Total Billed and Unbilled Revenue | 226.7 | 185.2 | 411.9 | |||||||||
Rate Adjustment Mechanism Revenue | 0.5 | 6.2 | 6.7 | |||||||||
Total Electric and Gas Operating Revenues | $ | 227.2 | $ | 191.4 | $ | 418.6 | ||||||
Twelve Months Ended December 31, 2017 | ||||||||||||
Gas and Electric Operating Revenues (millions): | Gas | Electric | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 71.2 | $ | 107.9 | $ | 179.1 | ||||||
Commercial & Industrial | 102.8 | 87.7 | 190.5 | |||||||||
Other | 13.5 | 6.0 | 19.5 | |||||||||
Total Billed and Unbilled Revenue | 187.5 | 201.6 | 389.1 | |||||||||
Rate Adjustment Mechanism Revenue | 6.5 | 4.6 | 11.1 | |||||||||
Total Gas and Electric Operating Revenues | $ | 194.0 | $ | 206.2 | $ | 400.2 | ||||||
Twelve Months Ended December 31, 2019 | ||||||||||||
Electric and Gas Operating Revenues (millions): | Electric | Gas | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 121.5 | $ | 81.4 | $ | 202.9 | ||||||
Commercial & Industrial | 93.8 | 120.1 | 213.9 | |||||||||
Other | 7.8 | 10.6 | 18.4 | |||||||||
Total Billed and Unbilled Revenue | 223.1 | 212.1 | 435.2 | |||||||||
Rate Adjustment Mechanism Revenue | 10.8 | (8.7 | ) | 2.1 | ||||||||
Total Electric and Gas Operating Revenues | $ | 233.9 | $ | 203.4 | $ | 437.3 | ||||||
Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales.
The
difference
between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded as an increase or a decrease in the current portion of Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases that the Company files with the Massachusetts Department of Public Utilities (MDPU). The Company estimates that revenue decoupling applies to approximately
The Company bills its customers for sales tax in Massachusetts and Maine. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings.
Other Operating Revenue—Non-regulated—Non-regulated
—
non-regulated
subsidiary, which,Other Operating Revenues ($ millions): | Twelve Months Ended December 31 | |||||||||||
As Reported | If ASU 2014-09 Had Been in Effect | |||||||||||
2019 | 2018 | 2017 | ||||||||||
Usource Contract Revenue | $ | 1.1 | $ | 5.7 | $ | 6.0 | ||||||
Less: Revenue Sharing Payments | (0.2 | ) | (1.0 | ) | (1.1 | ) | ||||||
Total Other Operating Revenues | $ | 0.9 | $ | 4.7 | $ | 4.9 | ||||||
Operation and Maintenance Expense ($ millions): | Twelve Months Ended December 31 | |||||||||||
As Reported | If ASU 2014-09 Had Been in Effect | |||||||||||
2019 | 2018 | 2017 | ||||||||||
Operation and Maintenance Expense | $ | 67.2 | $ | 69.5 | $ | 63.4 | ||||||
Depreciation and Amortization
—
depreciable property balances at the beginning and end of each year: 2021 – 3.29%, 2020 – 3.34% and 2019
– 3.41%, 2018
1,688.9
Less: Accumulated Depreciation
431.7
Net Utility Plant
1,257.2
Other Noncurrent Assets:
Regulatory Assets
108.9
Operating Lease Right of Use Assets
4.7
Other Assets
9.8
Total Other Noncurrent Assets
123.4
TOTAL ASSETS
$
1,540.3
(The accompanying Notes are an integral part of these consolidated financial statements.)
40
CONSOLIDATED BALANCE SHEETS (cont.)
(Millions, except number of shares)
LIABILITIES AND CAPITALIZATION
December 31, | 2021 | 2020 | ||||||
Current Liabilities: | ||||||||
Accounts Payable | $ | 52.4 | $ | 33.2 | ||||
Short-Term Debt | 64.1 | 54.7 | ||||||
Long-Term Debt, Current Portion | 8.2 | 8.5 | ||||||
Regulatory Liabilities | 9.5 | 5.5 | ||||||
Energy Supply Obligations | 14.5 | 10.4 | ||||||
Environmental Obligations | 0.5 | 0.3 | ||||||
Other Current Liabilities | 24.3 | 23.5 | ||||||
Total Current Liabilities | 173.5 | 136.1 | ||||||
Noncurrent Liabilities: | ||||||||
Retirement Benefit Obligations | 133.9 | 162.3 | ||||||
Deferred Income Taxes, Net | 127.7 | 109.0 | ||||||
Cost of Removal Obligations | 107.5 | 105.2 | ||||||
Regulatory Liabilities | 42.6 | 44.3 | ||||||
Environmental Obligations | 2.2 | 1.8 | ||||||
Other Noncurrent Liabilities | 6.6 | 6.9 | ||||||
Total Noncurrent Liabilities | 420.5 | 429.5 | ||||||
Capitalization: | ||||||||
Long-Term Debt, Less Current Portion | 497.8 | 523.1 | ||||||
Stockholders’ Equity: | ||||||||
Common Equity (Outstanding 15,977,766 and 15,012,310 Shares) | 332.1 | 285.3 | ||||||
Retained Earnings | 116.2 | 103.7 | ||||||
Total Common Stock Equity | 448.3 | 389.0 | ||||||
Preferred Stock | 0.2 | 0.2 | ||||||
Total Stockholders’ Equity | 448.5 | 389.2 | ||||||
Total Capitalization | 946.3 | 912.3 | ||||||
Commitments and Contingencies 7 ) | 0 | 0 | ||||||
TOTAL LIABILITIES AND CAPITALIZATION | $ | 1,540.3 | $ | 1,477.9 | ||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
41
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
Year Ended December 31, | 2021 | 2020 | 2019 | |||||||||
Operating Activities: | ||||||||||||
Net Income | $ | 36.1 | $ | 32.2 | $ | 44.2 | ||||||
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: | ||||||||||||
Depreciation and Amortization | 59.5 | 54.5 | 52.0 | |||||||||
Deferred Tax Provision | 10.8 | 9.3 | 13.5 | |||||||||
Gain on Divestiture, net (See Note 1) | — | — | (13.4 | ) | ||||||||
Changes in Working Capital Items: | ||||||||||||
Accounts Receivable | (4.9 | ) | (6.9 | ) | 11.7 | |||||||
Accrued Revenue | (10.3 | ) | (0.9 | ) | 4.7 | |||||||
Regulatory Liabilities | 4.0 | (1.9 | ) | (4.1 | ) | |||||||
Exchange Gas Receivable | (2.5 | ) | 1.2 | 2.0 | ||||||||
Accounts Payable | 19.2 | (4.4 | ) | (5.0 | ) | |||||||
Other Changes in Working Capital Items | 0.7 | (2.4 | ) | 4.6 | ||||||||
Deferred Regulatory and Other Charges | (2.7 | ) | (9.3 | ) | (5.3 | ) | ||||||
Other, net | (2.1 | ) | 4.3 | — | ||||||||
Cash Provided by Operating Activities | 107.8 | 75.7 | 104.9 | |||||||||
Investing Activities: | ||||||||||||
Property, Plant and Equipment Additions | (115.0 | ) | (122.6 | ) | (119.2 | ) | ||||||
Proceeds from Divestiture, Net (See Note 1) | — | — | 13.4 | |||||||||
Cash Used In Inves t ing Activities | (115.0 | ) | (122.6 | ) | (105.8 | ) | ||||||
Financing Activities: | ||||||||||||
Proceeds from (Repayment of) Short-Term Debt, net | 9.4 | (3.9 | ) | (24.2 | ) | |||||||
Issuance of Long-Term Debt | — | 99.7 | 70.0 | |||||||||
Repayment of Long-Term Debt | (25.8 | ) | (24.8 | ) | (18.8 | ) | ||||||
Long-Term Debt Issuance Costs | — | (0.6 | ) | (0.4 | ) | |||||||
Decrease in Capital Lease Obligations | (0.1 | ) | (0.1 | ) | (5.3 | ) | ||||||
Net Increase (Decrease) in Exchange Gas Financing | 2.3 | (1.1 | ) | (2.0 | ) | |||||||
Dividends Paid | (23.6 | ) | (22.6 | ) | (22.1 | ) | ||||||
Proceeds from Issuance of Common Stock | 45.5 | 1.1 | 1.1 | |||||||||
| Cash Provided by (Used In) Financing Activities | 7.7 | 47.7 | (1.7 | ) | ||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | 0.5 | 0.8 | (2.6 | ) | ||||||||
Cash and Cash Equivalents at Beginning of Year | 6.0 | 5.2 | 7.8 | |||||||||
Cash and Cash Equivalents at End of Year | $ | 6.5 | $ | 6.0 | $ | 5.2 | ||||||
Supplemental Information: | ||||||||||||
Interest Paid | $ | 26.0 | $ | 23.7 | $ | 24.1 | ||||||
Income Taxes Paid | $ | 1.4 | $ | 0.9 | $ | 0.8 | ||||||
Payments on Capital Leases | $ | 0.2 | $ | 0.3 | $ | 5.5 | ||||||
Capital Expenditures Included in Accounts Payable | $ | 4.9 | $ | 1.7 | $ | 0.6 | ||||||
Right-of-Use | $ | 0.7 | $ | 1.2 | $ | 4.0 | ||||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
42
CONSOLIDATED STATEMENTS OF
CHANGES IN COMMON STOCK EQUITY
(Millions, except shares data)
Common Equity | Retained Earnings | Total | ||||||||||
Balance at January 1, 2019 | $ | 279.1 | $ | 72.0 | $ | 351.1 | ||||||
Net Income for 2019 | 44.2 | 44.2 | ||||||||||
Dividends ($1.48 per Common Share) | (22.1 | ) | (22.1 | ) | ||||||||
Shares Issued Under Stock Plans | 2.3 | 2.3 | ||||||||||
Issuance of 20,065 Common Shares (See Note 5 ) | 1.1 | 1.1 | ||||||||||
Balance at December 31, 2019 | 282.5 | 94.1 | 376.6 | |||||||||
Net Income for 2020 | 32.2 | 32.2 | ||||||||||
Dividends ($1.50 per Common Share) | (22.6 | ) | (22.6 | ) | ||||||||
Shares Issued Under Stock Plans | 1.7 | 1.7 | ||||||||||
Issuance of 23,658 Common Shares (See Note 5 ) | 1.1 | 1.1 | ||||||||||
Balance at December 31, 2020 | 285.3 | 103.7 | 389.0 | |||||||||
Net Income for 2020 | 36.1 | 36.1 | ||||||||||
Dividends ($1.52 per Common Share) | (23.6 | ) | (23.6 | ) | ||||||||
Shares Issued Under Stock Plans | 1.3 | 1.3 | ||||||||||
Issuance of 942,316 Common Shares (See Note 5 ) | 45.5 | 45.5 | ||||||||||
Balance at December 31, 2021 | $ | 332.1 | $ | 116.2 | $ | 448.3 | ||||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
43
Note 1: Summary of Significant Accounting Policies
Nature of Operations
—
The Company’s earnings are seasonal and are typically higher in the first and fourth quarters when customers use natural gas for heating purposes.
Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has 3 distribution
utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively, the distribution utilities).
Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to 3 major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.
A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, on May 1, 2003 Unitil Power ceased being the wholesale supplier of Unitil Energy and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. In the period since, Unitil Power continued to flow revenues and expenses from remaining contracts to Unitil Energy under the Amended Unitil System Agreement. The last of those contracts expired October 31, 2020, and the Company no longer has material revenues or expenses associated
with those contracts.
Unitil also has 3 other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned
non-regulated
subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource), which the Company divested in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. Usource provided energy brokering and advisory services to large commercial and industrial customers in the northeastern United States.Divestiture of Non-Regulated Business Subsidiary
—
million on this divestiture in the first quarter of 2019. The pre-tax net gain of approximately
million on this divestiture is included in Other Income (Expense), Net on the Consolidated Statements of Earnings for the year-ended December 31, 2019, while the income taxes associated with this transaction of
million are included in the Provision For Income Taxes.
4
4
Basis of Presentation
Principles of Consolidation
—
Use of Estimates
—
Fair Value
—
Level 1— | Inputs are quoted prices (unadjusted) in active markets for | |
Level 2— | Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly. | |
Level 3— | Prices or valuations that require inputs that are both significant to the fair | |
To the extent valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.
There have been no changes in the valuation techniques used during the current period.
Utility Revenue Recognition
—
Billed and unbilled revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are estimated each month based on estimated customer usage by class and applicable customer rates, taking into account current and historical weather data, assumptions pertaining to metering patterns, billing cycle statistics, and other estimates and assumptions, and are then reversed in the following month when billed to customers.
4
5
A majority of the Company’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customer monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer.
The Company’s billed and unbilled rev
e
nue meets the definition of “revenues from contracts with customers” as defined in Accounting Standards Codification (ASC) 606. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in ASC 980, as the Company has the ability to adjust rates in the future as a result of past activities or completed events. The rate adjustment mechanisms meet the criteria within ASC 980. In cases where allowable costs are greater than operating revenues billed in the current period for the individual rate adjustment mechanism additional operating revenue is recognized. In cases where allowable costs are less than operating revenues billed in the current period for the individual rate adjustment mechanism, operating revenue is reduced. ASC 606 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.In the following tables, revenue is classified by the types of goods/services rendered and market/customer type.
Twelve Months Ended December 31, 2021 | ||||||||||||
Electric and Gas Operating Revenues (millions): | Electric | Gas | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 135.1 | $ | 83.9 | $ | 219.0 | ||||||
Commercial & Industrial | 103.3 | 124.1 | 227.4 | |||||||||
Other | 10.1 | 9.6 | 19.7 | |||||||||
Total Billed and Unbilled Revenue | 248.5 | 217.6 | 466.1 | |||||||||
Rate Adjustment Mechanism Revenue | 0 | 7.2 | 7.2 | |||||||||
Total Electric and Gas Operating Revenues | $ | 248.5 | $ | 224.8 | $ | 473.3 | ||||||
Twelve Months Ended December 31, 2020 | ||||||||||||
Electric and Gas Operating Revenues (millions): | Electric | Gas | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 128.7 | $ | 73.1 | $ | 201.8 | ||||||
Commercial & Industrial | 91.4 | 104.5 | 195.9 | |||||||||
Other | 6.6 | 7.6 | 14.2 | |||||||||
Total Billed and Unbilled Revenue | 226.7 | 185.2 | 411.9 | |||||||||
Rate Adjustment Mechanism Revenue | 0.5 | 6.2 | 6.7 | |||||||||
Total Electric and Gas Operating Revenues | $ | 227.2 | $ | 191.4 | $ | 418.6 | ||||||
Twelve Months Ended December 31, 2019 | ||||||||||||
Electric and Gas Operating Revenues (millions): | Electric | Gas | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 121.5 | $ | 81.4 | $ | 202.9 | ||||||
Commercial & Industrial | 93.8 | 120.1 | 213.9 | |||||||||
Other | 7.8 | 10.6 | 18.4 | |||||||||
Total Billed and Unbilled Revenue | 223.1 | 212.1 | 435.2 | |||||||||
Rate Adjustment Mechanism Revenue | 10.8 | (8.7 | ) | 2.1 | ||||||||
Total Electric and Gas Operating Revenues | $ | 233.9 | $ | 203.4 | $ | 437.3 | ||||||
Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales.
The
46
difference
between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded as an increase or a decrease in the current portion of Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases that the Company files with the Massachusetts Department of Public Utilities (MDPU). The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.
The Company bills its customers for sales tax in Massachusetts and Maine. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings.
Other Operating Revenue—Non-regulated
—
Depreciation and Amortization
—
Accrued Revenue (millions) | December 31, | |||||||
2019 | 2018 | |||||||
Regulatory Assets—Current | $ | 35.8 | $ | 41.3 | ||||
Unbilled Revenues | 14.2 | 13.4 | ||||||
Total Accrued Revenue | $ | 50.0 | $ | 54.7 | ||||
Exchange Gas Receivable (millions) | December 31, | |||||||
201 9 | 201 8 | |||||||
Northern Utilities | $ | 5.5 | $ | 7.5 | ||||
Fitchburg | 0.6 | 0.6 | ||||||
Total Exchange Gas Receivable | $ | 6.1 | $ | 8.1 | ||||
Gas Inventory (millions) | December 31, | |||||||
201 9 | 201 8 | |||||||
Natural Gas | $ | 0.4 | $ | 0.3 | ||||
Propane | 0.3 | 0.4 | ||||||
Liquefied Natural Gas & Other | 0.1 | 0.1 | ||||||
Total Gas Inventory | $ | 0.8 | $ | 0.8 | ||||
Utility Plant
1,688.9
Less: Accumulated Depreciation
431.7
Net Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 3.90%, 2.70% and 2.90% in2019
Other Noncurrent Assets:
Regulatory AccountingAssets
108.9
Operating Lease Right of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the MDPU, Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded RegulatoryUse Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.
4.7
Other Assets
9.8
Total Other Noncurrent Assets
123.4
TOTAL ASSETS
$
1,540.3
Regulatory Assets consist of the following (millions) | December 31 , | |||||||
2019 | 2018 | |||||||
Retirement Benefits | $ | 88.9 | $ | 72.0 | ||||
Energy Supply & Other Rate Adjustment Mechanisms | 31.0 | 38.4 | ||||||
Deferred Storm Charges | 5.6 | 6.3 | ||||||
Environmental | 7.2 | 7.9 | ||||||
Income Taxes | 4.2 | 5.7 | ||||||
Other Deferred Charges | 10.9 | 10.0 | ||||||
Total Regulatory Assets | 147.8 | 140.3 | ||||||
Less: Current Portion of Regulatory Assets (1) | 35.8 | 41.3 | ||||||
Regulatory Assets—noncurrent | $ | 112.0 | $ | 99.0 | ||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
40
CONSOLIDATED BALANCE SHEETS (cont.)
(Millions, except number of shares)
LIABILITIES AND CAPITALIZATION
December 31, | 2021 | 2020 | ||||||
Current Liabilities: | ||||||||
Accounts Payable | $ | 52.4 | $ | 33.2 | ||||
Short-Term Debt | 64.1 | 54.7 | ||||||
Long-Term Debt, Current Portion | 8.2 | 8.5 | ||||||
Regulatory Liabilities | 9.5 | 5.5 | ||||||
Energy Supply Obligations | 14.5 | 10.4 | ||||||
Environmental Obligations | 0.5 | 0.3 | ||||||
Other Current Liabilities | 24.3 | 23.5 | ||||||
Total Current Liabilities | 173.5 | 136.1 | ||||||
Noncurrent Liabilities: | ||||||||
Retirement Benefit Obligations | 133.9 | 162.3 | ||||||
Deferred Income Taxes, Net | 127.7 | 109.0 | ||||||
Cost of Removal Obligations | 107.5 | 105.2 | ||||||
Regulatory Liabilities | 42.6 | 44.3 | ||||||
Environmental Obligations | 2.2 | 1.8 | ||||||
Other Noncurrent Liabilities | 6.6 | 6.9 | ||||||
Total Noncurrent Liabilities | 420.5 | 429.5 | ||||||
Capitalization: | ||||||||
Long-Term Debt, Less Current Portion | 497.8 | 523.1 | ||||||
Stockholders’ Equity: | ||||||||
Common Equity (Outstanding 15,977,766 and 15,012,310 Shares) | 332.1 | 285.3 | ||||||
Retained Earnings | 116.2 | 103.7 | ||||||
Total Common Stock Equity | 448.3 | 389.0 | ||||||
Preferred Stock | 0.2 | 0.2 | ||||||
Total Stockholders’ Equity | 448.5 | 389.2 | ||||||
Total Capitalization | 946.3 | 912.3 | ||||||
Commitments and Contingencies 7 ) | 0 | 0 | ||||||
TOTAL LIABILITIES AND CAPITALIZATION | $ | 1,540.3 | $ | 1,477.9 | ||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
41
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
Year Ended December 31, | 2021 | 2020 | 2019 | |||||||||
Operating Activities: | ||||||||||||
Net Income | $ | 36.1 | $ | 32.2 | $ | 44.2 | ||||||
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: | ||||||||||||
Depreciation and Amortization | 59.5 | 54.5 | 52.0 | |||||||||
Deferred Tax Provision | 10.8 | 9.3 | 13.5 | |||||||||
Gain on Divestiture, net (See Note 1) | — | — | (13.4 | ) | ||||||||
Changes in Working Capital Items: | ||||||||||||
Accounts Receivable | (4.9 | ) | (6.9 | ) | 11.7 | |||||||
Accrued Revenue | (10.3 | ) | (0.9 | ) | 4.7 | |||||||
Regulatory Liabilities | 4.0 | (1.9 | ) | (4.1 | ) | |||||||
Exchange Gas Receivable | (2.5 | ) | 1.2 | 2.0 | ||||||||
Accounts Payable | 19.2 | (4.4 | ) | (5.0 | ) | |||||||
Other Changes in Working Capital Items | 0.7 | (2.4 | ) | 4.6 | ||||||||
Deferred Regulatory and Other Charges | (2.7 | ) | (9.3 | ) | (5.3 | ) | ||||||
Other, net | (2.1 | ) | 4.3 | — | ||||||||
Cash Provided by Operating Activities | 107.8 | 75.7 | 104.9 | |||||||||
Investing Activities: | ||||||||||||
Property, Plant and Equipment Additions | (115.0 | ) | (122.6 | ) | (119.2 | ) | ||||||
Proceeds from Divestiture, Net (See Note 1) | — | — | 13.4 | |||||||||
Cash Used In Inves t ing Activities | (115.0 | ) | (122.6 | ) | (105.8 | ) | ||||||
Financing Activities: | ||||||||||||
Proceeds from (Repayment of) Short-Term Debt, net | 9.4 | (3.9 | ) | (24.2 | ) | |||||||
Issuance of Long-Term Debt | — | 99.7 | 70.0 | |||||||||
Repayment of Long-Term Debt | (25.8 | ) | (24.8 | ) | (18.8 | ) | ||||||
Long-Term Debt Issuance Costs | — | (0.6 | ) | (0.4 | ) | |||||||
Decrease in Capital Lease Obligations | (0.1 | ) | (0.1 | ) | (5.3 | ) | ||||||
Net Increase (Decrease) in Exchange Gas Financing | 2.3 | (1.1 | ) | (2.0 | ) | |||||||
Dividends Paid | (23.6 | ) | (22.6 | ) | (22.1 | ) | ||||||
Proceeds from Issuance of Common Stock | 45.5 | 1.1 | 1.1 | |||||||||
| Cash Provided by (Used In) Financing Activities | 7.7 | 47.7 | (1.7 | ) | ||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | 0.5 | 0.8 | (2.6 | ) | ||||||||
Cash and Cash Equivalents at Beginning of Year | 6.0 | 5.2 | 7.8 | |||||||||
Cash and Cash Equivalents at End of Year | $ | 6.5 | $ | 6.0 | $ | 5.2 | ||||||
Supplemental Information: | ||||||||||||
Interest Paid | $ | 26.0 | $ | 23.7 | $ | 24.1 | ||||||
Income Taxes Paid | $ | 1.4 | $ | 0.9 | $ | 0.8 | ||||||
Payments on Capital Leases | $ | 0.2 | $ | 0.3 | $ | 5.5 | ||||||
Capital Expenditures Included in Accounts Payable | $ | 4.9 | $ | 1.7 | $ | 0.6 | ||||||
Right-of-Use | $ | 0.7 | $ | 1.2 | $ | 4.0 | ||||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
42
CONSOLIDATED STATEMENTS OF
CHANGES IN COMMON STOCK EQUITY
(Millions, except shares data)
Regulatory Liabilities consist of the following (millions) | December 31, | |||||||
2019 | 2018 | |||||||
Rate Adjustment Mechanisms | $ | 6.0 | $ | 11.5 | ||||
| Income Taxes (Note 9) | 47.6 | 47.0 | ||||||
Other | 0.4 | — | ||||||
Total Regulatory Liabilities | 54.0 | 58.5 | ||||||
Less: Current Portion of Regulatory Liabilities | 7.4 | 11.5 | ||||||
Regulatory Liabilities—noncurrent | $ | 46.6 | $ | 47.0 | ||||
Common Equity | Retained Earnings | Total | ||||||||||
Balance at January 1, 2019 | $ | 279.1 | $ | 72.0 | $ | 351.1 | ||||||
Net Income for 2019 | 44.2 | 44.2 | ||||||||||
Dividends ($1.48 per Common Share) | (22.1 | ) | (22.1 | ) | ||||||||
Shares Issued Under Stock Plans | 2.3 | 2.3 | ||||||||||
Issuance of 20,065 Common Shares (See Note 5 ) | 1.1 | 1.1 | ||||||||||
Balance at December 31, 2019 | 282.5 | 94.1 | 376.6 | |||||||||
Net Income for 2020 | 32.2 | 32.2 | ||||||||||
Dividends ($1.50 per Common Share) | (22.6 | ) | (22.6 | ) | ||||||||
Shares Issued Under Stock Plans | 1.7 | 1.7 | ||||||||||
Issuance of 23,658 Common Shares (See Note 5 ) | 1.1 | 1.1 | ||||||||||
Balance at December 31, 2020 | 285.3 | 103.7 | 389.0 | |||||||||
Net Income for 2020 | 36.1 | 36.1 | ||||||||||
Dividends ($1.52 per Common Share) | (23.6 | ) | (23.6 | ) | ||||||||
Shares Issued Under Stock Plans | 1.3 | 1.3 | ||||||||||
Issuance of 942,316 Common Shares (See Note 5 ) | 45.5 | 45.5 | ||||||||||
Balance at December 31, 2021 | $ | 332.1 | $ | 116.2 | $ | 448.3 | ||||||
(The accompanying Notes are an integral part of these consolidated financial statements.)
43
Note 1: Summary of Significant Accounting Policies
Nature of Operations
—
The Company’s earnings are seasonal and are typically higher in the first and fourth quarters when customers use natural gas for heating purposes.
Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has 3 distribution
utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively, the distribution utilities).
Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to 3 major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.
A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, on May 1, 2003 Unitil Power ceased being the wholesale supplier of Unitil Energy and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. In the period since, Unitil Power continued to flow revenues and expenses from remaining contracts to Unitil Energy under the Amended Unitil System Agreement. The last of those contracts expired October 31, 2020, and the Company no longer has material revenues or expenses associated
with those contracts.
Unitil also has 3 other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned
non-regulated
subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource), which the Company divested in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. Usource provided energy brokering and advisory services to large commercial and industrial customers in the northeastern United States.Divestiture of Non-Regulated Business Subsidiary
—
million on this divestiture in the first quarter of 2019. The pre-tax net gain of approximately
million on this divestiture is included in Other Income (Expense), Net on the Consolidated Statements of Earnings for the year-ended December 31, 2019, while the income taxes associated with this transaction of
million are included in the Provision For Income Taxes.
4
4
Basis of Presentation
Principles of Consolidation
—
Use of Estimates
—
Fair Value
—
| Inputs are quoted prices (unadjusted) in active markets for | ||
Level 2— | Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or | |
Level 3— | Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. | |
To the extent valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.
There have been no changes in the valuation techniques used during the current period.
Utility Revenue Recognition
—
Billed and unbilled revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are estimated each month based on estimated customer usage by class and applicable customer rates, taking into account current and historical weather data, assumptions pertaining to metering patterns, billing cycle statistics, and other estimates and assumptions, and are then reversed in the following month when billed to customers.
4
5
A majority of the Company’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customer monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer.
The Company’s billed and unbilled rev
e
nue meets the definition of “revenues from contracts with customers” as defined in Accounting Standards Codification (ASC) 606. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in ASC 980, as the Company has the ability to adjust rates in the future as a result of past activities or completed events. The rate adjustment mechanisms meet the criteria within ASC 980. In cases where allowable costs are greater than operating revenues billed in the current period for the individual rate adjustment mechanism additional operating revenue is recognized. In cases where allowable costs are less than operating revenues billed in the current period for the individual rate adjustment mechanism, operating revenue is reduced. ASC 606 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.In the following tables, revenue is classified by the types of goods/services rendered and market/customer type.
Twelve Months Ended December 31, 2021 | ||||||||||||
Electric and Gas Operating Revenues (millions): | Electric | Gas | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 135.1 | $ | 83.9 | $ | 219.0 | ||||||
Commercial & Industrial | 103.3 | 124.1 | 227.4 | |||||||||
Other | 10.1 | 9.6 | 19.7 | |||||||||
Total Billed and Unbilled Revenue | 248.5 | 217.6 | 466.1 | |||||||||
Rate Adjustment Mechanism Revenue | 0 | 7.2 | 7.2 | |||||||||
Total Electric and Gas Operating Revenues | $ | 248.5 | $ | 224.8 | $ | 473.3 | ||||||
Twelve Months Ended December 31, 2020 | ||||||||||||
Electric and Gas Operating Revenues (millions): | Electric | Gas | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 128.7 | $ | 73.1 | $ | 201.8 | ||||||
Commercial & Industrial | 91.4 | 104.5 | 195.9 | |||||||||
Other | 6.6 | 7.6 | 14.2 | |||||||||
Total Billed and Unbilled Revenue | 226.7 | 185.2 | 411.9 | |||||||||
Rate Adjustment Mechanism Revenue | 0.5 | 6.2 | 6.7 | |||||||||
Total Electric and Gas Operating Revenues | $ | 227.2 | $ | 191.4 | $ | 418.6 | ||||||
Twelve Months Ended December 31, 2019 | ||||||||||||
Electric and Gas Operating Revenues (millions): | Electric | Gas | Total | |||||||||
Billed and Unbilled Revenue: | ||||||||||||
Residential | $ | 121.5 | $ | 81.4 | $ | 202.9 | ||||||
Commercial & Industrial | 93.8 | 120.1 | 213.9 | |||||||||
Other | 7.8 | 10.6 | 18.4 | |||||||||
Total Billed and Unbilled Revenue | 223.1 | 212.1 | 435.2 | |||||||||
Rate Adjustment Mechanism Revenue | 10.8 | (8.7 | ) | 2.1 | ||||||||
Total Electric and Gas Operating Revenues | $ | 233.9 | $ | 203.4 | $ | 437.3 | ||||||
Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales.
The
46
difference
between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded as an increase or a decrease in the current portion of Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases that the Company files with the Massachusetts Department of Public Utilities (MDPU). The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.
The Company bills its customers for sales tax in Massachusetts and Maine. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings.
Other Operating Revenue—Non-regulated
—
Depreciation and Amortization
—
Stock-based Employee Compensation
—
Income Taxes
—
Provisions
for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.
Dividends
y
the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2021 the Company paid quarterly dividends of $0.38 per share, resulting in an annualized dividend rate of $1.52 per common share. For the years ended December 31, 2020 and 2019, the Company paid quarterly dividends of $0.375 and $0.37 per common share, respectively, resulting in47
annualized dividend rates of $1.50 and $1.48 per common share, respectively. At its January 2022 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.39 per share, an increase of $0.01 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.56 per share from $1.52 per share.
Cash and Cash Equivalents
—Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England(ISO-NE)
Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations toISO-NE.
Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately2-1/2
months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. On December 31, 2021 and 2020, the Unitil subsidiaries had deposited $2.7 million and $2.4 million, respectively, to satisfy theirISO-NE
obligations.Financial Instruments
—In June 2016, the Financial Accounting Standards Board issued ASU2016-13,
“Financial Instruments—Credit Losses (Topic 326)”, which provides a new model for recognizing credit losses on financial instruments based on an estimate of current expected credit losses. Under the new guidance, immediate recognition of all credit losses expected over the life of a financial instrument is required. The Company adopted this standard on the accounting for credit losses on its financial instruments, including accounts receivable, on January 1, 2020, and it did not have a material effect on the financial statements.Allowance for Doubtful Accounts
—
Accounts Receivable, Net includes $3.1 million and $3.1 million of the Allowance for Doubtful Accounts at December 31, 2021 and December 31, 2020, respectively. Unbilled Revenues, net (a component of Accrued Revenue) includes $0.2 million and $0.2 million of the Allowance for Doubtful Accounts at December 31, 2021 and December 31, 2020, respectively.
Accrued Revenue—
Accrued Revenue (millions) | December 31, | |||||||
2021 | 2020 | |||||||
Regulatory Assets—Current | $ | 47.4 | $ | 37.3 | ||||
Unbilled Revenues | 13.8 | 13.6 | ||||||
| Total Accrued Revenue | $ | 61.2 | $ | 50.9 | ||||
Exchange Gas Receivable
—
48
through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of December 31, 2021 and 2020.
Exchange Gas Receivable (millions) | December 31, | |||||||
2021 | 2020 | |||||||
Northern Utilities | $ | 6.7 | $ | 4.4 | ||||
Fitchburg | 0.7 | 0.5 | ||||||
| Total Exchange Gas Receivable | $ | 7.4 | $ | 4.9 | ||||
Gas Inventory
Gas Inventory (millions) | December 31, | |||||||
2021 | 2020 | |||||||
Natural Gas | $ | 0.5 | $ | 0.2 | ||||
Propane | 0.4 | 0.3 | ||||||
Liquefied Natural Gas & Other | 0.1 | 0.1 | ||||||
| Total Gas Inventory | $ | 1.0 | $ | 0.6 | ||||
The Company also has an inventory of Materials and Supplies in the amounts of $8.6 million and $8.5 million as of December 31, 2021 and December 31, 2020, respectively. These amounts are recorded at weighted average cost.
Utility Plant
Cost of additions consists of
labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 1.71%, 3.12% and 3.90% in 2021, 2020 and 2019, respectively.The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At December 31, 2021 and 2020, the Company has recorded cost of removal amounts of $107.5 million and $105.2 million, respectively, that have been collected in depreciation rates but have not yet been expended, and which represent regulatory liabilities. These amounts are recorded on the Consolidated Balance Sh
e
ets in Cost of Removal Obligations.49
Regulatory Accounting
—
following table.
The Company currently receives recovery in rates or expects to receive recovery of these hardship accounts in future rate cases.Regulatory Assets consist of the following (millions) | December 31, | |||||||
2021 | 2020 | |||||||
Retirement Benefits | $ | 86.4 | $ | 103.7 | ||||
Energy Supply & Other Rate Adjustment Mechanisms | 44.1 | 34.1 | ||||||
Deferred Storm Charges | 3.3 | 4.1 | ||||||
Environmental | 4.6 | 5.2 | ||||||
Income Taxes | 2.6 | 3.4 | ||||||
Other Deferred Charges | 15.3 | 14.2 | ||||||
Total Regulatory Assets | 156.3 | 164.7 | ||||||
Less: Current Portion of Regulatory Assets (1) | 47.4 | 37.3 | ||||||
Regulatory Assets—noncurrent | $ | 108.9 | $ | 127.4 | ||||
| (1) | Reflects amounts included in the Accrued Revenue on the |
Regulatory Liabilities consist of the following (millions) | December 31, | |||||||
2021 | 2020 | |||||||
Rate Adjustment Mechanisms | $ | 7.7 | $ | 4.1 | ||||
Income Taxes | 44.3 | 45.5 | ||||||
Other | 0.1 | 0.2 | ||||||
Total Regulatory Liabilities | 52.1 | 49.8 | ||||||
Less: Current Portion of Regulatory Liabilities | 9.5 | 5.5 | ||||||
Regulatory Liabilities—noncurrent | $ | 42.6 | $ | 44.3 | ||||
Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Included in Regulatory Assets as of December 31, 2021 are $8.5 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material effect on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived
assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regul
a
ted50
Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.
Leases
—The Company records assets and liabilities on the balance sheet for all leases with terms longer than 12 months. Leases are classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company has elected the practical expedient to not separatenon-lease
components from lease components and instead to account for both as a single lease component. The Company’s accounting policy election for leases with a lease term of 12 months or less is to recognize the lease payments as lease expense on a straight-line basis over the lease term. The Company recognizes those lease payments in the Consolidated Statements of Earnings on a straight-line basis ov
er the lease term. See additional discussion in the “Leases” section of Note4
(Debt and Financing Arrangements).Derivatives
—
The Company had no derivative assets or liabilities recorded on its Consolidated Balance Sheets as of December 31, 2021 and December 31, 2020. There were no losses / (gains) recognized in Regulatory Assets / Liabilities for the years ended December 31, 2021 and 2020. There were no losses / (gains) reclassified into the Consolidated Statements of Earnings for the years ended December 31, 2021, 2020 and 2019.
Fitchburg has entered into power purchase agreements for which contingencies exist (see “Fitchburg – Massachusetts RFP’s” section of Note 7 (Commitments and Contingencies). Until these contingencies are satisfied, these contracts will not qualify for derivative accounting. The Company believes that the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg.
Investments in Marketable Securities
—
9 (Retirement Benefit Plans)).
At December 31, 20192021 and 2018,2020, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.6$5.7 million and $4.8$5.7 million, respectively, as shown in the table below.
following table.
These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other (Income) Expense, Net.
Fair Value of Marketable Securities (millions) | December 31, | |||||||
2019 | 2018 | |||||||
Money Market Funds | $ | 5.6 | $ | 4.8 | ||||
Total Marketable Securities | $ | 5.6 | $ | 4.8 | ||||
Fair Value of Marketable Securities (millions) | December 31, | |||||||
2021 | 2020 | |||||||
Money Market Funds | $ | 5.7 | $ | 5.7 | ||||
| Total Marketable Securities | $ | 5.7 | $ | 5.7 | ||||
The Company also sponsors the Unitil Corporation Deferred Compensation Plan (the “DC Plan”)DC Plan). The DC Plan is a
non-qualified
deferred compensation plan that provides a vehicle for participants to accumulatetax-deferred
savings to supplement retirement income. The DC Plan, which was effective January 1,51
participants to defer up to 85
At December 31
31, 2021 and 2020, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets,
were $0.2$
0.6, respectively, as
million and $0$
0.5Level 1
as they
are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other (Income) Expense, Net.
Fair Value of Marketable Securities (millions) | December 31 , | |||||||
2019 | 2018 | |||||||
Equity Funds | $ | 0.1 | $ | — | ||||
Money Market Funds | 0.1 | — | ||||||
Total Marketable Securities | $ | 0.2 | $ | — | ||||
Fair Value of Marketable Securities (millions) | December 31, | |||||||
2021 | 2020 | |||||||
Equity Funds | $ | 0.2 | $ | 0.2 | ||||
Money Market Funds | 0.4 | 0.3 | ||||||
| Total Marketable Securities | $ | 0.6 | $ | 0.5 | ||||
Energy Supply Obligations
December 31, | ||||||||
Energy Supply Obligations consist of the following: (millions) | 2019 | 2018 | ||||||
Current: | ||||||||
Exchange Gas Obligation | $ | 5.5 | $ | 7.5 | ||||
Renewable Energy Portfolio Standards | 4.7 | 5.6 | ||||||
Power Supply Contract Divestitures | 0.3 | 0.3 | ||||||
Total Energy Supply Obligations—Current | 10.5 | 13.4 | ||||||
Noncurrent: | ||||||||
Power Supply Contract Divestitures | 0.3 | 0.6 | ||||||
Total Energy Supply Obligations | $ | 10.8 | $ | 14.0 | ||||
December 31, | ||||||||
Energy Supply Obligations consist of the following: (millions) | 2021 | 2020 | ||||||
Renewable Energy Portfolio Standards | $ | 7.8 | $ | 5.7 | ||||
Exchange Gas Obligation | 6.7 | 4.4 | ||||||
Power Supply Contract Divestitures | 0 | 0.3 | ||||||
Total Energy Supply Obligations | $ | 14.5 | $ | 10.4 | ||||
Renewable Energy Portfolio Standards—Standards
retail electricity suppliers, including public utilities, to demonstrate that required percentages of their sales are met with power generated from certain types of resources or technologies. Compliance is demonstrated by purchasing and retiring Renewable Energy Certificates (REC) generated by facilities approved by the state as qualifying for REC treatment. Unitil Energy and Fitchburg purchase RECs in compliance with RPS legislation in New Hampshire and Massachusetts for supply provided to default service customers. RPS compliance costs are a supply cost that is recovered in customer default service rates. Unitil Energy and Fitchburg collect RPS compliance costs from customers throughout the year and demonstrate compliance for each calendar year on the following July 1
are recorded in thewithin Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.
Fitchburg has enterede
n
tered into long-term renewable contracts for the purchase of clean energy and/orRECs pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (“Green(Green Communities Act”,Act, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (“Energy(Energy Diversity Act”,Act, 2016). The generating facilities associated with fourten of these contracts have been constructed and are now operating. Since 2017,Three approved contracts are currently under development. These include two long-term contracts filed with the Company has participatedMDPU in two major statewide procurements which resulted in contracts2018, one for offshore wind generation and one for imported hydroelectric power and associated transmission, which were approved in 2019 and another for offshore wind generation. Thegeneration contracts were approved byfiled with the MDPU induring the secondfirst quarter of 2019.
52
Exchange Gas Obligation
—
Power Supply Contract Divestitures—
o
ice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. As of December 31, 2019,2021, Fitchburg has fully-recovered itsand Unitil Energy have fully recovered their power supply-related stranded costs and Unitil Energy $0.6 million remaining to recover.costs. The obligations for prior periods related to these divestitures are recorded in Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets with a corresponding regulatory assetsasset recorded in Accrued Revenue (current portion) and Regulatory Assets (noncurrent portion).
Retirement Benefit Obligations
—The Company sponsors the Pension Plan, which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new
non-union
employees. For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union. The Company also sponsors a
non-qualified
retirement plan, the SERP, covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the PBOP Plan, primarily to provide health care and life insurance benefits to retired employees.
The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, reflecting ultimate recovery from customers through rates. The regulatory asset (or regulatory liability) is amortized as the actuarial gains and losses and prior service cost are amortized to recognizenet periodic benefit cost for the future collection of these obligations in electricPension and gas ratesPBOP plans. All amounts are remeasured annually. (See Note 10)9 Retirement Benefit Plans).
Commitments and Contingencies
7
(Commitments and Contingencies).
Environmental Matters
7
o
t recoverable in regulatory rate mechanisms.Subsequent Events
53
Note 2: Quarterly Financial Information (unaudited; millions, except per share data)
Three Months Ended | ||||||||||||||||||||||||||||||||
March 31, | June 30, | September 30, | December 31, | |||||||||||||||||||||||||||||
2019 | 2018 | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | |||||||||||||||||||||||||
Total Operating Revenues | $ | 152.1 | $ | 145.8 | $ | 84.4 | $ | 84.5 | $ | 85.3 | $ | 88.2 | $ | 116.4 | $ | 125.6 | ||||||||||||||||
Operating Income | $ | 28.8 | $ | 28.1 | $ | 12.3 | $ | 10.6 | $ | 10.0 | $ | 10.3 | $ | 22.0 | $ | 22.2 | ||||||||||||||||
Net Income Applicable to Common | $ | 26.5 | $ | 15.6 | $ | 4.0 | $ | 3.6 | $ | 2.3 | $ | 2.8 | $ | 11.4 | $ | 11.0 | ||||||||||||||||
Per Share Data: | ||||||||||||||||||||||||||||||||
Earnings Per Common Share | $ | 1.78 | $ | 1.06 | $ | 0.27 | $ | 0.24 | $ | 0.15 | $ | 0.19 | $ | 0.77 | $ | 0.74 | ||||||||||||||||
Dividends Paid Per Common Share | $ | 0.37 | $ | 0.365 | $ | 0.37 | $ | 0.365 | $ | 0.37 | $ | 0.365 | $ | 0.37 | $ | 0.365 | ||||||||||||||||
Unitil reports3 three segments: utility electric operations, utility gas operations utility electric operations and
non-regulated.
Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capitalregions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has 3three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine.
Granite State is an interstate natural gas transmission pip
pipeline company, operating 86
miles
of
underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection
to 3three majorn
natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transmission services provided to Northern Utilities and, to a lesser ext
Granite State is included in the Gas column below.utility gas operations segment.
Unitil Resources is the Company’s wholly-owned
non-regulated
subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource), which the Company divested of in the first quarter of 2019,Non-Regulated
Unitil Realty, Unitil Service and the holding company are included in the Other column of the table below.Other. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use.
The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies. Intersegment sales take place at cost and the effects of all intersegment and/or intercompany transactions are eliminated in the consolidated financial statements. Segment profit or loss is based on profit or loss from operations after income taxes and preferred stock dividends. Expenses used to determine operating income before taxes are charged directly to each segment or are allocated based on cost allocation factors included in rate applications approved by the FERC, NHPUC, MDPU, and MPUC. Assets allocated to each segment are based upon specific identification of such assets provided by Company records.
54
The following table providestables provide significant segment financial data for the years ended December 31, 2021, 2020 and 2019 2018 and 2017 (millions)
:
Year Ended December 31, 2019 | Gas | Electric | Non- Regulated | Other | Total | |||||||||||||||
Revenues: | ||||||||||||||||||||
Billed and Unbilled Revenue | $ | 212.1 | $ | 223.1 | $ | $ | $ | 435.2 | ||||||||||||
Rate Adjustment Mechanism Revenue | (8.7 | ) | 10.8 | — | — | 2.1 | ||||||||||||||
Other Operating Revenue— Non-Regulated | — | — | 0.9 | — | 0.9 | |||||||||||||||
Total Operating Revenues | 203.4 | 233.9 | 0.9 | — | 438.2 | |||||||||||||||
Interest Income | 1.2 | 0.9 | 0.2 | 0.6 | 2.9 | |||||||||||||||
Interest Expense | 14.4 | 9.4 | — | 2.8 | 26.6 | |||||||||||||||
Depreciation & Amortization Expense | 28.5 | 22.6 | — | 0.9 | 52.0 | |||||||||||||||
Income Tax Expense (Benefit) | 7.2 | 4.2 | 3.8 | (1.4 | ) | 13.8 | ||||||||||||||
Segment Profit | 19.1 | 11.5 | 10.2 | 3.4 | 44.2 | |||||||||||||||
Segment Assets | 823.3 | 529.3 | 0.3 | 17.9 | 1,370.8 | |||||||||||||||
Capital Expenditures | 74.0 | 39.6 | — | 5.6 | 119.2 | |||||||||||||||
Year Ended December 31, 2018 | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Billed and Unbilled Revenue | $ | 210.7 | $ | 228.7 | $ | — | $ | — | $ | 439.4 | ||||||||||
Rate Adjustment Mechanism Revenue | 5.4 | (5.4 | ) | — | — | — | ||||||||||||||
Other Operating Revenue— Non-Regulated | — | — | 4.7 | — | 4.7 | |||||||||||||||
Total Operating Revenues | 216.1 | 223.3 | 4.7 | — | 444.1 | |||||||||||||||
Interest Income | 0.8 | 0.8 | 0.2 | 0.6 | 2.4 | |||||||||||||||
Interest Expense | 14.2 | 9.0 | — | 3.2 | 26.4 | |||||||||||||||
Depreciation & Amortization Expense | 24.9 | 23.1 | 0.1 | 2.3 | 50.4 | |||||||||||||||
Income Tax Expense (Benefit) | 7.1 | 4.2 | 0.5 | (3.4 | ) | 8.4 | ||||||||||||||
Segment Profit | 18.8 | 11.4 | 1.3 | 1.5 | 33.0 | |||||||||||||||
Segment Assets | 764.1 | 484.2 | 6.9 | 43.1 | 1,298.3 | |||||||||||||||
Capital Expenditures | 70.8 | 28.4 | — | 3.2 | 102.4 | |||||||||||||||
Year Ended December 31, 2017 | ||||||||||||||||||||
Revenues | $ | 194.0 | $ | 206.2 | $ | 6.0 | $ | — | $ | 406.2 | ||||||||||
Interest Income | 0.7 | 1.0 | 0.1 | 0.6 | 2.4 | |||||||||||||||
Interest Expense | 13.7 | 8.8 | — | 3.0 | 25.5 | |||||||||||||||
Depreciation & Amortization Expense | 22.4 | 23.4 | 0.1 | 1.0 | 46.9 | |||||||||||||||
Income Tax Expense (Benefit) | 10.7 | 7.5 | 0.7 | (1.4 | ) | 17.5 | ||||||||||||||
Segment Profit | 16.4 | 11.9 | 1.2 | (0.5 | ) | 29.0 | ||||||||||||||
Segment Assets | 714.3 | 476.9 | 6.7 | 44.0 | 1,241.9 | |||||||||||||||
Capital Expenditures | 72.1 | 33.7 | — | 13.5 | 119.3 | |||||||||||||||
Year Ended December 31, 2021 | Electric | Gas | Non- Regulated | Other | Total | |||||||||||||||
Revenues: | ||||||||||||||||||||
Billed and Unbilled Revenue | $ | 248.5 | $ | 217.6 | $ | — | $ | — | $ | 466.1 | ||||||||||
Rate Adjustment Mechanism Revenue | 0 | 7.2 | — | — | 7.2 | |||||||||||||||
Total Operating Revenues | 248.5 | 224.8 | — | — | 473.3 | |||||||||||||||
Interest Income | 0.8 | 0.5 | — | 0.3 | 1.6 | |||||||||||||||
Interest Expense | 9.0 | 15.3 | — | 2.9 | 27.2 | |||||||||||||||
Depreciation & Amortization Expense | 25.9 | 32.6 | — | 1.0 | 59.5 | |||||||||||||||
Income Tax Expense (Benefit) | 4.5 | 7.7 | (0.1 | ) | (0.6 | ) | 11.5 | |||||||||||||
Segment Profit (Loss) | 14.0 | 23.2 | 0.1 | (1.2 | ) | 36.1 | ||||||||||||||
Segment Assets | 584.0 | 935.9 | — | 20.4 | 1,540.3 | |||||||||||||||
Capital Expenditures | 38.1 | 75.8 | — | 1.1 | 115.0 | |||||||||||||||
Year Ended December 31, 2020 | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Billed and Unbilled Revenue | $ | 226.7 | $ | 185.2 | $ | — | $ | — | $ | 411.9 | ||||||||||
Rate Adjustment Mechanism Revenue | 0.5 | 6.2 | — | — | 6.7 | |||||||||||||||
Total Operating Revenues | 227.2 | 191.4 | — | — | 418.6 | |||||||||||||||
Interest Income | 1.1 | 1.1 | — | 0.4 | 2.6 | |||||||||||||||
Interest Expense | 8.7 | 14.2 | — | 3.5 | 26.4 | |||||||||||||||
Depreciation & Amortization Expense | 23.8 | 29.8 | — | 0.9 | 54.5 | |||||||||||||||
Income Tax Expense (Benefit) | 4.7 | 7.3 | — | (1.8 | ) | 10.2 | ||||||||||||||
Segment Profit | 12.9 | 19.3 | — | — | 32.2 | |||||||||||||||
Segment Assets | 571.8 | 886.3 | — | 19.8 | 1,477.9 | |||||||||||||||
Capital Expenditures | 45.5 | 71.1 | — | 6.0 | 122.6 | |||||||||||||||
Year Ended December 31, 2019 | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Billed and Unbilled Revenue | $ | 223.1 | $ | 212.1 | $ | — | $ | — | $ | 435.2 | ||||||||||
Rate Adjustment Mechanism Revenue | 10.8 | (8.7 | ) | — | — | 2.1 | ||||||||||||||
Other Operating Revenue—Non-Regulated | — | — | 0.9 | — | 0.9 | |||||||||||||||
Total Operating Revenues | 233.9 | 203.4 | 0.9 | — | 438.2 | |||||||||||||||
Interest Income | 0.9 | 1.2 | 0.2 | 0.6 | 2.9 | |||||||||||||||
Interest Expense | 9.4 | 14.4 | — | 2.8 | 26.6 | |||||||||||||||
Depreciation & Amortization Expense | 22.6 | 28.5 | — | 0.9 | 52.0 | |||||||||||||||
Income Tax Expense (Benefit) | 4.2 | 7.2 | 3.8 | (1.4 | ) | 13.8 | ||||||||||||||
Segment Profit | 11.5 | 19.1 | 10.2 | 3.4 | 44.2 | |||||||||||||||
Segment Assets | 529.3 | 823.3 | 0.3 | 17.9 | 1,370.8 | |||||||||||||||
Capital Expenditures | 39.6 | 74.0 | — | 5.6 | 119.2 | |||||||||||||||
55
Note 4:3: Allowance for Doubtful AccountsAccount
s
Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2019
shut-off.
As of December 31, 20192021 and 2018,2020, the Company has recorded
$7.9 million and
$6.8 million, respectively, of hardship accounts in Regulatory Assets. The Company is currently receivingreceives recovery in rates or expects to receive recovery of these hardship accounts in
future
rate cases.Accounts Receivable, Net includes $3.1 million and $3.1 million of theAllowance for Doubtful Accounts at December 31, 2021 and December 31, 2020, respectively. Unbilled Revenues, net (a component of Accrued Revenue) includes $0.2 million and $0.2 million of the Allowance for Doubtful Accounts at December 31, 2021 and December 31, 2020, respectively.
The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2017
(millions):
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at Beginning of Period | Provision | Recoveries | Accounts Written Off | Regulatory Deferrals* | Balance at End of Period | |||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||
Electric | $ | 1.6 | $ | 3.3 | $ | 0.4 | $ | 3.4 | $ | 0.1 | $ | 2.0 | ||||||||||||||||||||||||||||||||
Gas | 1.7 | 2.3 | 0.4 | 3.1 | — | 1.3 | ||||||||||||||||||||||||||||||||||||||
Other | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||
$ | 3.3 | $ | 5.6 | $ | 0.8 | $ | 6.5 | $ | 0.1 | $ | 3.3 | |||||||||||||||||||||||||||||||||
Year Ended December 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||
Electric | $ | 0.6 | $ | 2.9 | $ | 0.3 | $ | 2.6 | $ | 0.4 | $ | 1.6 | ||||||||||||||||||||||||||||||||
Gas | 0.4 | 2.6 | 0.3 | 1.8 | 0.2 | 1.7 | ||||||||||||||||||||||||||||||||||||||
Other | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||
| $ | 1.0 | $ | 5.5 | $ | 0.6 | $ | 4.4 | $ | 0.6 | $ | 3.3 | |||||||||||||||||||||||||||||||||
Balance at Beginning of Period | Provision | Recoveries | Accounts Written Off | Balance at End of Period | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2019 | ||||||||||||||||||||||||||||||||||||||||||||
Electric | $ | 0.5 | $ | 3.0 | $ | 0.3 | $ | 3.2 | $ | 0.6 | $ | 0.5 | $ | 3.0 | $ | 0.3 | $ | 3.2 | $ | — | $ | 0.6 | ||||||||||||||||||||||
Gas | 0.8 | 1.9 | 0.5 | 2.8 | 0.4 | 0.8 | 1.9 | 0.5 | 2.8 | — | 0.4 | |||||||||||||||||||||||||||||||||
Other | — | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||
$ | 1.3 | $ | 4.9 | $ | 0.8 | $ | 6.0 | $ | 1.0 | $ | 1.3 | $ | 4.9 | $ | 0.8 | $ | 6.0 | $ | — | $ | 1.0 | |||||||||||||||||||||||
Year Ended December 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||
Electric | $ | 0.9 | $ | 3.2 | $ | 0.3 | $ | 3.9 | $ | 0.5 | ||||||||||||||||||||||||||||||||||
Gas | 0.6 | 2.9 | 0.3 | 3.0 | 0.8 | |||||||||||||||||||||||||||||||||||||||
Other | 0.1 | (0.1 | ) | — | — | — | ||||||||||||||||||||||||||||||||||||||
| $ | 1.6 | $ | 6.0 | $ | 0.6 | $ | 6.9 | $ | 1.3 | |||||||||||||||||||||||||||||||||||
Year Ended December 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||
Electric | $ | 0.8 | $ | 1.8 | $ | 0.3 | $ | 2.0 | $ | 0.9 | ||||||||||||||||||||||||||||||||||
Gas | 0.2 | 1.9 | 0.3 | 1.8 | 0.6 | |||||||||||||||||||||||||||||||||||||||
Other | 0.1 | — | — | — | 0.1 | |||||||||||||||||||||||||||||||||||||||
| $ | 1.1 | $ | 3.7 | $ | 0.6 | $ | 3.8 | $ | 1.6 | |||||||||||||||||||||||||||||||||||
| * | The Company has incurred greater than normal bad debt expense due to the coronavirus pandemic. Incremental bad debt expense amounts have been deferred as regulatory assets based on certain regulatory proceedings and management’s belief that such amounts are probable of recovery (See the “Financial Effects of COVID-19 Pandemic” section in Note7 (Commitments and Contingencies). The Company will track the collection of receivables and to the extent incremental bad debt amounts are collected in the future, such amounts will reduce the regulatory assets recorded. |
Note 5:4: Debt and Financing Arrangements
The Company funds a portion of its operations through the issuance of long-term debt, and through short-term borrowings under its revolving Credit Facility. The Company’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their machinery, vehicles and office equipment. Details regarding long-term debt, short-term debt and leases follow:
56
Long-Term Debt and Interest Expense
Long-Term Debt Structure and Covenants
—
The long-term debt of Unitil is issued under Unsecured Promissory Notes with negativepledge provisions. The long-term debt’s negative pledge provisions contain restrictions which, among other things,
limit the incursion of additional long-term debt. Accordingly, in order for Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s) must be satisfied, including that Unitil haveha
s
total funded indebtedness lessthan
70% of total
capitalization, and earnings available for interest equal to at least
two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under itsUnitil’s present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of certain Unitil subsidiaries or certain other actions against Unitil subsidiaries.
Substantially all of the property of Unitil Energy is subject to liens of indenture under which First Mortgage Bonds (FMB) have been issued. In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met;met, including that Unitil Energy have sufficient available net bondable plant to issue the securities and earnings available for interest charges equal to at least two times the annual interest requirement. The Unitil Energy agreements further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB. The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.
All of the long-term debt of Fitchburg, Northern Utilities and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term agreements of that subsidiary must be satisfied, including that the subsidiary have total funded indebtedness less than 65% of total capitalization. Additionally, to issue new long-term debt, Fitchburg must maintain earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State long-term debt agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary’s long-term debt agreements. None of the Fitchburg, Northern Utilities and Granite State default provisions are triggered by the actions or defaults of Unitil or any of its other subsidiaries.
The Unitil, Unitil Energy, Fitchburg, Northern Utilities and Granite State long-term debt instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets.
Unitil Energy, Fitchburg, Northern Utilities and Granite State pay common dividends to their sole common shareholder, Unitil Corporation and these common dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders. The long-term debt issued by the Company and its subsidiaries contains certain covenants that determine the amount that the Company and each of these subsidiary companies has available to pay for dividends. As of December 31, 2019,2021, in accordance with the covenants, these subsidiary companies had a combined amount of $308.4$358.7 million available for the payment of dividends
and Unitil Corporation had $123.1$166.9 million available for the payment of dividends
$116.2 million.
Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2021 for the payment of dividends.
57
Issuance of Long-Term Debt
purposes
.On September 15, 2020, Northern Utilities issued $40
million of Notes due 2040 at 3.78%. Fitchburg issued $27.5
million of Notes due 2040 at 3.78%. Unitil Energy issued $27.5 million of Bonds due 2040 at 3.58%. Northern Utilities, Fitchburg and Unitil Energy used the net proceeds from these offerings to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been recorded as a reduction to Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.On December 18, 2019, Unitil Corporation issued $
$30 million of Notes due
2029at
$0.2 million of costs associated with these issuances have been netted againstrecorded as a reduction to Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.
On September 12, 2019, Northern Utilities issued $40 million of Notes due 2049 at 4.04%. Northern Utilities used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.2 million of costs associated with these issuances have been netted againstrecorded as a reduction to Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.
Debt Repayment
and
The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 20192021 is: 20202022
– $
– $
– $
– $
– $
38.0 million$444.4 million.
Fair Value of Long-Term Debt
inputs (valuations based on quoted prices available in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are directly observable, and inputs derived principally from market data.)data). In estimating the fair value of the Company’s long-term debt, the assumed market yield reflects the Moody’s Baa Utility Bond Average Yield. Costs, including prepayment costs, associated with the early settlement of long-term debt are not taken into consideration in determining fair value.
Estimated Fair Value of Long-Term Debt (millions) | December 31, | |||||||
2019 | 2018 | |||||||
Estimated Fair Value of Long-Term Debt | $ | 518.7 | $ | 422.0 | ||||
Estimated Fair Value of Long-Term Debt (millions) | December 31, | |||||||
2021 | 2020 | |||||||
Estimated Fair Value of Long-Term Debt | $ | 584.9 | $ | 633.1 | ||||
58
Details on long-term debt at December 31,
2021 and 2018
2020 are shown below:
Long-Term Debt (millions) | December 31, | |||||||
2019 | 2018 | |||||||
Unitil Corporation: | ||||||||
6.33 % Senior Notes, Due May 1, 2022 | $ | 20.0 | $ | 20.0 | ||||
3.70 % Senior Notes, Due August 1, 2026 | 30.0 | 30.0 | ||||||
3.43% Senior Notes, Due December 18, 2029 | 30.0 | — | ||||||
Unitil Energy First Mortgage Bonds: | ||||||||
5.24 % Senior Secured Notes, Due March 2, 2020 | 5.0 | 10.0 | ||||||
8.49 % Senior Secured Notes, Due October 14, 2024 | 4.5 | 6.0 | ||||||
6.96 % Senior Secured Notes, Due September 1, 2028 | 18.0 | 20.0 | ||||||
8.00 % Senior Secured Notes, Due May 1, 2031 | 15.0 | 15.0 | ||||||
6.32 % Senior Secured Notes, Due September 15, 2036 | 15.0 | 15.0 | ||||||
4.18 % Senior Secured Notes, Due November 30, 2048 | 30.0 | 30.0 | ||||||
Fitchburg: | ||||||||
6.75 % Senior Notes, Due November 30, 2023 | 3.8 | 5.7 | ||||||
6.79 % Senior Notes, Due October 15, 2025 | 10.0 | 10.0 | ||||||
3.52 % Senior Notes, Due November 1, 2027 | 10.0 | 10.0 | ||||||
7.37 % Senior Notes, Due January 15, 2029 | 12.0 | 12.0 | ||||||
5.90 % Senior Notes, Due December 15, 2030 | 15.0 | 15.0 | ||||||
7.98 % Senior Notes, Due June 1, 2031 | 14.0 | 14.0 | ||||||
4.32 % Senior Notes, Due November 1, 2047 | 15.0 | 15.0 | ||||||
Northern Utilities: | ||||||||
5.29 % Senior Notes, Due March 2, 2020 | 8.2 | 16.6 | ||||||
3.52 % Senior Notes, Due November 1, 2027 | 20.0 | 20.0 | ||||||
7.72 % Senior Notes, Due December 3, 2038 | 50.0 | 50.0 | ||||||
4.42 % Senior Notes , Due October 15, 2044 | 50.0 | 50.0 | ||||||
4.32 % Senior Notes, Due November 1, 2047 | 30.0 | 30.0 | ||||||
4.04% Senior Notes, Due September 12, 2049 | 40.0 | — | ||||||
Granite State: | ||||||||
3.72 % Senior Notes , Due November 1, 2027 | 15.0 | 15.0 | ||||||
Total Long-Term Debt | 460.5 | 409.3 | ||||||
Less: Unamortized Debt Issuance Costs | 3.5 | 3.5 | ||||||
Total Long-Term Debt, net of Unamortized Debt Issuance Costs | 457.0 | 405.8 | ||||||
Less: Current Portion (1) | 19.5 | 18.4 | ||||||
Total Long-Term Debt, Less Current Portion | $ | 437.5 | $ | 387.4 | ||||
Long-Term Debt (millions) | December 31, | |||||||
2021 | 2020 | |||||||
Unitil Corporation: | ||||||||
6.33% Senior Notes, Due May 1, 2022 | $ | — | $ | 15.0 | ||||
3.70% Senior Notes, Due August 1, 2026 | 30.0 | 30.0 | ||||||
3.43% Senior Notes, Due December 18, 2029 | 30.0 | 30.0 | ||||||
Unitil Energy First Mortgage Bonds: | ||||||||
8.49% Senior Secured Notes, Due October 14, 2024 | 1.5 | 3.0 | ||||||
6.96% Senior Secured Notes, Due September 1, 2028 | 14.0 | 16.0 | ||||||
8.00% Senior Secured Notes, Due May 1, 2031 | 15.0 | 15.0 | ||||||
6.32% Senior Secured Notes, Due September 15, 2036 | 15.0 | 15.0 | ||||||
3.58% Senior Secured Notes, Due September 15, 2040 | 27.5 | 27.5 | ||||||
4.18% Senior Secured Notes, Due November 30, 2048 | 30.0 | 30.0 | ||||||
Fitchburg: | ||||||||
6.75% Senior Notes, Due November 30, 2023 | — | 1.9 | ||||||
6.79% Senior Notes, Due October 15, 2025 | 6.0 | 10.0 | ||||||
3.52% Senior Notes, Due November 1, 2027 | 10.0 | 10.0 | ||||||
7.37% Senior Notes, Due January 15, 2029 | 9.6 | 10.8 | ||||||
5.90% Senior Notes, Due December 15, 2030 | 15.0 | 15.0 | ||||||
7.98% Senior Notes, Due June 1, 2031 | 14.0 | 14.0 | ||||||
3.78% Senior Notes, Due September 15, 2040 | 27.5 | 27.5 | ||||||
4.32% Senior Notes, Due November 1, 2047 | 15.0 | 15.0 | ||||||
Northern Utilities: | ||||||||
3.52% Senior Notes, Due November 1, 2027 | 20.0 | 20.0 | ||||||
7.72% Senior Notes, Due December 3, 2038 | 50.0 | 50.0 | ||||||
3.78% Senior Notes, Due September 15, 2040 | 40.0 | 40.0 | ||||||
4.42% Senior Notes, Due October 15, 2044 | 50.0 | 50.0 | ||||||
4.32% Senior Notes, Due November 1, 2047 | 30.0 | 30.0 | ||||||
4.04% Senior Notes, Due September 12, 2049 | 40.0 | 40.0 | ||||||
Granite State: | ||||||||
3.72% Senior Notes, Due November 1, 2027 | 15.0 | 15.0 | ||||||
Unitil Realty Corp.: | ||||||||
2.64% Senior Secured Notes, Due December 18, 2030 | 4.5 | 4.7 | ||||||
Total Long-Term Debt | 509.6 | 535.4 | ||||||
Less: Unamortized Debt Issuance Costs | 3.6 | 3.8 | ||||||
Total Long-Term Debt, net of Unamortized Debt Issuance Costs | 506.0 | 531.6 | ||||||
Less: Current Portion (1) | 8.2 | 8.5 | ||||||
Total Long-Term Debt, Less Current Portion | $ | 497.8 | $ | 523.1 | ||||
| (1) | The Current Portion of Long-Term Debt includes sinking fund payments. |
Interest Expense,Net Net
d.
Unitil’s utility subsidiaries operate a number of reconciling rate mechanisms to recover specifically identified costs on a pass-through basis. These reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense.
59
Consistent with regulatory precedent, interest income is recorded on an under-collection of costs, which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded
on an over-collection of costs, which creates a regulatory liability to be
refunded
in future periods when rates are reset. A summary of interest expense and interest income is provided in the following table:Interest Expense, N et (millions) | ||||||||||||
2019 | 2018 | 2017 | ||||||||||
Interest Expense | ||||||||||||
Long-Term Debt | $ | 22.9 | $ | 23.1 | $ | 21.8 | ||||||
Short-Term Debt | 3.0 | 2.6 | 2.5 | |||||||||
Regulatory Liabilities | 0.7 | 0.7 | 1.2 | |||||||||
Subtotal Interest Expense | 26.6 | 26.4 | 25.5 | |||||||||
Interest Income | ||||||||||||
Regulatory Assets | (0.8 | ) | (0.8 | ) | (0.7 | ) | ||||||
AFUDC (1) and Other | (2.1 | ) | (1.6 | ) | (1.7 | ) | ||||||
Subtotal Interest Income | (2.9 | ) | (2.4 | ) | (2.4 | ) | ||||||
Total Interest Expense, N et | $ | 23.7 | $ | 24.0 | $ | 23.1 | ||||||
Interest Expense, Net (millions) | ||||||||||||
2021 | 2020 | 2019 | ||||||||||
Interest Expense | ||||||||||||
Long-Term Debt | $ | 26.0 | $ | 24.8 | $ | 22.9 | ||||||
Short-Term Debt | 0.8 | 1.4 | 3.0 | |||||||||
Regulatory Liabilities | 0.4 | 0.2 | 0.7 | |||||||||
Subtotal Interest Expense | 27.2 | 26.4 | 26.6 | |||||||||
Interest Income | ||||||||||||
Regulatory Assets | (0.5 | ) | (0.8 | ) | (0.8 | ) | ||||||
AFUDC (1) and Other | (1.1 | ) | (1.8 | ) | (2.1 | ) | ||||||
Subtotal Interest Income | (1.6 | ) | (2.6 | ) | (2.9 | ) | ||||||
Total Interest Expense, Net | $ | 25.6 | $ | 23.8 | $ | 23.7 | ||||||
| (1) | AFUDC—Allowance for Funds Used During Construction |
Credit Arrangements
On July 25, 2018, the Company entered
into a Second
Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit agreement, dated as of October 4, 2013, as amended. The Credit Facility extends toJuly 25, 2023, subject to two
one-year
extensions and has a borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal toone-month
London Interbank Offered Rate plus 1.125%. Provided there is no event of default, the Company may increase the borrowing limit under the Credit Facility by up to $50 million.The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were
$239.1 million
and
$248.9 million
for the years ended December 31, 20192021 and December 31, 2018,2020, respectively. Total gross repayments
were $276.9
$229.7 million and $221.1
$252.8 million
for the years ended December 31, 20192021 and December 31, 2018,2020, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 20192021 and December 31, 2018:2020:
Revolving Credit Facility (millions) | ||||||||
December 31, | ||||||||
201 9 | 201 8 | |||||||
Limit | $ | 120.0 | $ | 120.0 | ||||
Short-Term Borrowings Outstanding | $ | 58.6 | $ | 82.8 | ||||
Letters of Credit Outstanding | $ | 0.1 | $ | — | ||||
Available | $ | 61.3 | $ | 37.2 | ||||
Revolving Credit Facility (millions) | ||||||||
December 31, | ||||||||
2021 | 2020 | |||||||
Limit | $ | 120.0 | $ | 120.0 | ||||
Short-Term Borrowings Outstanding | $ | 64.1 | $ | 54.7 | ||||
Letters of Credit Outstanding | $ | — | $ | 0.1 | ||||
Available | $ | 55.9 | $ | 65.2 | ||||
The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 20192021 and
60
December 31, 2018,2020, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. The Company believes it
i
t has sufficient sources of working capital to fund its operations.The weighted average interest%1.2%, 3.3%1.7%, and 2.4%3.4% during,2018, and2017, respectively.
rates on all short-term borrowings were 3.4
2021, 2020, and 2019,
Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services. Unitil Corporation and Granite State are currently rated “Baa2”, and Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1” by Moody’s Investors Services.
In April 2014, Unitil Service Corp. entered into a financing arrangement, structured as acapital lease obligation, for various information systems and technology equipment. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of
Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was
$8.3 million and $8.4
$5.4 million
of natural gas storage inventory at December 31, 20192021 and 2018,2020, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2019,2021, which was payable in January 2020,2022, was $1.0$1.6 million and was recorded in Accounts Payable at December 31, 2019.2021. The amount of natural gas inventory released in December 2018,2020, which was payable in January 2019,
2021, was $0.9
$1.0 million
and was recorded in Accounts Payable at December 31, 2018.2020.
Contractual Obligations
The following table lists the Company’s contractual obligations for long-term debt as of December 31, 2021.
Payments Due by Period | ||||||||||||||||||||||||||||
Long-Term Debt Contractual Obligations (millions) as of December 31, 2021 | Total | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 & Beyond | |||||||||||||||||||||
Long-Term Debt | $ | 509.6 | $ | 8.4 | $ | 6.9 | $ | 6.9 | $ | 5.0 | $ | 38.0 | $ | 444.4 | ||||||||||||||
Interest on Long-Term Debt | 360.5 | 24.5 | 23.9 | 23.4 | 22.9 | 22.6 | 243.2 | |||||||||||||||||||||
Total | $ | 870.1 | $ | 32.9 | $ | 30.8 | $ | 30.3 | $ | 27.9 | $ | 60.6 | $ | 687.6 | ||||||||||||||
Leases
Unitil’s subsidiaries lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements.
Total rental expense under operating leases charged to operations for the years ended December 31, 2019, 20182021, 2020 and 2017 2019$1.4
amounted
to $1.9 million, $2.2
$1.8 million and $2.0
$1.4 million respectively.
The balance sheet classification of the Company’s lease obligations was as follows:
December 31, | ||||||||
Lease Obligations (millions) | 2019 | 2018 | ||||||
Operating Lease Obligations: | ||||||||
Other Current Liabilities (current portion) | $ | 1.2 | $ | — | ||||
Other Noncurrent Liabilities (long-term portion) | 2.8 | — | ||||||
Total Operating Lease Obligations | 4.0 | — | ||||||
Capital Lease Obligations: | ||||||||
Other Current Liabilities (current portion) | 0.2 | 3.1 | ||||||
Other Noncurrent Liabilities (long-term portion) | 0.3 | 2.7 | ||||||
Total Capital Lease Obligations | 0.5 | 5.8 | ||||||
Total Lease Obligations | $ | 4.5 | $ | 5.8 | ||||
December 31, | ||||||||
Lease Obligations (millions) | 2021 | 2020 | ||||||
Operating Lease Obligations: | ||||||||
Other Current Liabilities (current portion) | $ | 1.6 | $ | 1.5 | ||||
Other Noncurrent Liabilities (long-term portion) | 3.1 | 3.7 | ||||||
Total Operating Lease Obligations | 4.7 | 5.2 | ||||||
Capital Lease Obligations: | ||||||||
Other Current Liabilities (current portion) | 0.1 | 0.2 | ||||||
Other Noncurrent Liabilities (long-term portion) | 0.2 | 0.2 | ||||||
Total Capital Lease Obligations | 0.3 | 0.4 | ||||||
Total Lease Obligations | $ | 5.0 | $ | 5.6 | ||||
61
Cash paid for amounts included in the measurement of operating lease obligations for the twelve months ended December 31, 2019 was $1.42021 and 2020 wwas$1.8 million, respectively and w
as
$1.9 million and as
included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.Assets under capital leases amounted to approximately $1.2
$0.7 million and $15.0
$1.0 million as of December 31, 20192021 and 2018,2020, respectively, less accumulated amortization of $0.6
$0.3 million and $1.7
$0.5 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.Sheet
s.
The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2019.2021. The payments for capitaloperating leases consist of
$1.6 million of current Capital Lease Obligations,operating lease obligations, which are included in Other Current Liabilities and $0.3
$3.1 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2021. The payments for capital leases consist of $0.1 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $0.2 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2019.2021.
Lease Payments ($000’s) Year Ending December 31, | Operating Leases | Capital Leases | ||||||
2022 | $ | 1,695 | $ | 150 | ||||
2023 | 1,399 | 107 | ||||||
2024 | 1,069 | 52 | ||||||
2025 | 503 | 19 | ||||||
2026 | 199 | — | ||||||
2027-2031 | 121 | — | ||||||
Total Payments | 4,986 | 328 | ||||||
Less: Interest | 316 | 12 | ||||||
Amount of Lease Obligations Recorded on Consolidated Balance Sheets | $ | 4,670 | $ | 316 | ||||
Lease Payments ($000’s) Year Ending December 31, | Operating Leases | Capital Leases | ||||||
2020 | $ | 1,355 | $ | 262 | ||||
2021 | 1,185 | 161 | ||||||
2022 | 904 | 97 | ||||||
2023 | 604 | 55 | ||||||
2024 | 274 | — | ||||||
2025 | 139 | — | ||||||
Total Payments | 4,461 | 575 | ||||||
Less: Interest | 435 | 29 | ||||||
Amount of Lease Obligations Recorded on Consolidated Balance Sheets | $ | 4,026 | $ | 546 | ||||
Operating lease obligations are based on the net present value of the remaining lease payments
over the remaining lease term. In determining the present value of lease payments, the Company used the interest rate stated in each lease agreement. As of December 31, 2019,2021, the weighted average remaining lease term is 3.9
3.5 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.2
3.9%.Lease Payments ($000’s) Year Ending December 31, | Operating Leases | Capital Leases | ||||||
2019 | $ | 1,372 | $ | 3,069 | ||||
2020 | 1,138 | 2,535 | ||||||
2021 | 969 | 93 | ||||||
2022 | 689 | 32 | ||||||
2023 | 390 | 14 | ||||||
2024 | 120 | — | ||||||
Total Payments | $ | 4,678 | $ | 5,743 | ||||
Guarantees
The Company provides limited guarantees oncertain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of December 31,2019, 2021, there were approximately $6.2
$0.7 million of guarantees outstanding.outstanding with a duration of less than one year.
Note 5: Equity
The Company has common stock outstanding and one of our subsidiaries has preferred stock outstanding. Details regarding these forms of capitalization follow:
Common Stock
The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”. The Company had 14,876,955
15,977,766 and 14,930,170
15,012,310 shares of common stock outstanding at December 31,
2021 and December 31,
shares of common stock authorized as of December 31,
2021 and December 31,
Unitil Corporation Common Stock Offering
62
The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $31.7 million and was$38.6 million. The proceeds were used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay short-term debt and for other general corporate purposes.
As part of the Offering, the Company granted the underwriters a—During 2019,2021, the Company sold 20,06522,316 shares of its common stock, at an average price of $57.37$46.98 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k)401(k) plans resulting in net proceeds of $1.1$1.0 million. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock. During 2018,2019, the Company raised $1.2$1.1 million and $1.3$1.1 million, respectively, through the issuance of 25,93223,658 and 26,25620,065 shares, respectively, of its common stock in connection with its DRP and 401(k)401(k) plans.
30-day
option to purchase additional shares. The underwriters exercised the option and purchased an additional 120,000 shares of the Company’s common stock on September 8, 2021. The Company’s net increase to Common Equity and Cash proceeds from the exercise of the option was approximately $5.9 million. The proceeds were used to make equity capital contributions to the Company’s regulated utility subsidiaries, to repay debt and for other general corporate purposes. Overall, the results of operations and earnings reflect the higher number of average shares outstanding period over period.
Dividend Reinvestment and Stock Purchase Plan
2020 and 2017
Common Shares Repurchased, Cancelled and Retired
10b5-1
under the Securities Exchange Act of 1934,2021, 2020 and 2017
10b5-1
trading plan. The expense recognized by the Company for these repurchases was $0.4 million, $0.5 million, and $0.2 million During 2019
2021, 2020 and 2017
Stock-Based Compensation Plans
Stock Plan
Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee
of the Board of Directors to receive awards under the Stock Plan, including awards of restricted shares
The maximum number of shares available for awards to participants under the Stock Plan is 677,500
Restricted Shares
Outstanding awards of Restricted Shares fully vest over a period of four years
at a rate of 25
63
participant’s account. The Company may deduct or withhold, or require a participant to remit to the Company, an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with anaward. award.
Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death.
orretirement retirement.
Restricted Shares issued for 20172019 – 20192021 in conjunction with the Stock Plan are presented in the following table:
Issuance Date | Shares | Aggregate Market Value (millions) | ||
1/30/17 | 34,930 | $1.6 | ||
1/29/18 | 37,510 | $1.6 | ||
1/29/19 | 33,150 | $1.6 |
Issuance Date | Shares | Aggregate Market Value (millions) | ||
1/29/19 | 33,150 | $1.6 | ||
1/28/20 | 28,630 | $1.8 | ||
7/28/20 | 3,000 | $0.1 | ||
1/26/21 | 23,140 | $0.9 |
There were 32,95037,621 and 29,25239,426
non-vested
shares under the Stock Plan as of December 31, 2021 and 2018
2021, 2020 and 2017
0
restricted shares cancelled under the Stock Plan duringmarket value of $1.8$1.7 million.
Restricted Stock Units
Restricted Stock Units, which are issued tomembers of the Company’s Board of Directors, earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units.
The equity portion of Restricted Stock Units activity during 2019
2021 and 2018
2020 in conjunction with the Stock Plan are presented in the following table:
Restricted Stock Units (Equity Portion) | ||||||||||||||||
2019 | 2018 | |||||||||||||||
Units | Weighted Average Stock Price | Units | Weighted Average Stock Price | |||||||||||||
Beginning Restricted Stock Units | 61,789 | $ | 38.25 | 52,224 | $ | 36.22 | ||||||||||
Restricted Stock Units Granted | 6,943 | $ | 63.50 | 7,892 | $ | 49.63 | ||||||||||
Dividend Equivalents Earned | 1,632 | $ | 58.15 | 1,673 | $ | 47.85 | ||||||||||
Restricted Stock Units Settled | — | — | — | — | ||||||||||||
Ending Restricted Stock Units | 70,364 | $ | 41.20 | 61,789 | $ | 38.25 | ||||||||||
Restricted Stock Units (Equity Portion) | ||||||||||||||||
2021 | 2020 | |||||||||||||||
Units | Weighted Average Stock Price | Units | Weighted Average Stock Price | |||||||||||||
Beginning Restricted Stock Units | 43,192 | $ | 41.34 | 70,364 | $ | 41.20 | ||||||||||
Restricted Stock Units Granted | 4,519 | $ | 43.35 | 3,743 | $ | 39.26 | ||||||||||
Dividend Equivalents Earned | 1,471 | $ | 46.34 | 1,507 | $ | 47.34 | ||||||||||
Restricted Stock Units Settled | — | $ | — | (32,422 | ) | $ | 41.09 | |||||||||
Ending Restricted Stock Units | 49,182 | $ | 41.67 | 43,192 | $ | 41.34 | ||||||||||
Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2021 and 2020, 2019includeand 2018are $1.9
$1.0 million and $1.3
$0.8 million, respectively, representing the fair value of liabilities associatedass
o
ciated with the portion of fully vested RSUs that will be settled in cash.Preferred Stock
There werewere $0.2
million, or 1,887
1,861 shares, of Unitil Energy’s 6.00
64
Preferred Stock outstanding as of December 31, 2020. There were less than $0.1
million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31,
2021 and December 31, 2020, respectively.
Earnings Per Share
The following table reconciles basic and diluted earnings per share (EPS).
(Millions except shares and per share data) | 2019 | 2018 | 2017 | |||||||||
Earnings Available to Common Shareholders | $ | 44.2 | $ | 33.0 | $ | 29.0 | ||||||
Weighted Average Common Shares Outstanding—Basic (000’s) | 14,894 | 14,824 | 14,095 | |||||||||
Plus: Diluted Effect of Incremental Shares (000’s) | 6 | 5 | 7 | |||||||||
Weighted Average Common Shares Outstanding—Diluted (000’s) | 14,900 | 14,829 | 14,102 | |||||||||
Earnings per Share—Basic and Diluted | $ | 2.97 | $ | 2.23 | $ | 2.06 | ||||||
(Millions except shares and per share data) | 2021 | 2020 | 2019 | |||||||||
Earnings Available to Common Shareholders | $ | 36.1 | $ | 32.2 | $ | 44.2 | ||||||
Weighted Average Common Shares Outstanding—Basic (000’s) | 15,373 | 14,951 | 14,894 | |||||||||
Plus: Diluted Effect of Incremental Shares (000’s) | 3 | 1 | 6 | |||||||||
Weighted Average Common Shares Outstanding—Diluted (000’s) | 15,376 | 14,952 | 14,900 | |||||||||
Earnings per Share—Basic and Diluted | $ | 2.35 | $ | 2.15 | $ | 2.97 | ||||||
The following table shows the number of weighted average
non-vested
restricted shares that were not included in the above computation of EPS because the effect would have been antidilutive.2019 | 2018 | 2017 | ||||||||||
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation | — | 6,102 | 8,733 | |||||||||
2021 | 2020 | 2019 | ||||||||||
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation | 23,636 | 42,813 | — | |||||||||
Note 7:6: Energy Supply
ELECTRIC POWER SUPPLY
Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England
(ISO-NE)
markets for the purpose of facilitating wholesale electric power supply transactions, which are necessary to serve Unitil’s electric customers with their supply of electricity.Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers. As of December 2021, nearly 77% of Unitil’s largest New Hampshire customers, representing 22% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales, and 80% of Unitil’s largest Massachusetts customers, representing 34% of Unitil’s Massachusetts electric kWh sales, purchased their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 17% of Fitchburg’s customer base, and customers in Ashby comprise another 4%. On December 31, 2020, the City of Fitchburg filed with the MDPU for approval of its Aggregation Plan. The aggregation is anticipated to be implemented in mid-2022. The City of Fitchburg comprises about 69% of Company sales. As of December 2021, 27% of Unitil’s residential customers in Massachusetts purchased their electricity from a third-party supplier.
In New Hampshire, the percentage of residential customers purchasing electricity from a third-party supplier in 2021 is 7.8%, down
0.5
% from 8.3% in 2020 and reflecting a downward trend from a high of 13% in 2015. Most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs. Municipal aggregation is now provided for in New Hampshire, but no aggregations have begun in Unitil Energy’s service area.
Regulated Electric Power Supply
To provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts to purchase electric supply from various wholesale suppliers.
6
5Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 100% of the supply requirements.
Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. MDPU policy establishes the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential and for small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s
ISO-NE
settlement account, where Fitchburg procures electric supply throughISO-NE’s
real-time market. In 2021, Fitchburg adjusted its procurement schedule in response to the impending City of Fitchburg municipal aggregation. In its most recent solicitation, Fitchburg solicited for 100% of default service supply for a limited six month period beginning December 1, 2021 to May 31, 2022.The NHPUC and MDPU regularly review alternatives to their procurement policy, which may lead to future changes in this regulated power supply procurement structure.
Regional Electric Transmission and Power Markets
Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the
ISO-NE
markets.ISO-NE
is the Regional Transmission Organization (RTO) in New England. The purpose ofISO-NE
is to assure reliable operation of the bulk power system in the most economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. TheISO-NE
tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and associated support payments. The most notable benefits of theISO-NE
are coordinated, reliable power system operation and a supportive business environment for the development of competitive electric markets.Electric Power Supply Divestiture
In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.
In connection with the implementation of retail choice, Unitil purchasesPower, which formerly functioned as the wholesale power supply provider for Unitil Energy, and manages gasFitchburg divested their long-term power supply for customers served by Northern Utilitiescontracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.
accordance with their approved restructuring plans.
Electric Power Supply Divestiture
In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.
Unitil purchases and manages gas supply for customers served by Northern Utilities in Maine and New Hampshire, and by Fitchburg has entered into long-term renewable contracts for thein Massachusetts.
Northern Utilities’ Commercial and Industrial (C&I) customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of clean energy and/or RECs pursuantNorthern Utilities’ large, and some of its medium, C&I customers purchase their gas supply from third-party suppliers. Most small C&I customers, and all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. As of December 2021, 74% of Unitil’s largest New Hampshire gas customers, representing 39% of Unitil’s New Hampshire gas therm sales, and 63% of Unitil’s largest Maine customers, representing 24% of Unitil’s Maine gas therm sales, purchased their gas supply from a third-party supplier.
Fitchburg’s residential and C&I business customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Fitchburg’s large, and some of its medium, C&I
customers,
66
purchase their gas supply from third-party suppliers. Most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. As of December 2021, 67% of Unitil’s largest Massachusetts legislation, specifically, An Act Relativegas customers, representing 27% of Unitil’s Massachusetts gas therm sales, purchased their gas supply from third-party suppliers. The approved costs associated with natural gas supplied to Green Communities (“Green Communities Act”, 2008), An Act Relative to Competitively Priced Electricitycustomers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically adjusted rates, and are included in Cost of Gas Sales in the Commonwealth (2012)Consolidated Statements of Earnings.
Regulated Natural Gas Supply
Northern Utilities purchases the majority of its natural gas from U.S. domestic and An ActCanadian suppliers largely under contracts of one year or less, and on occasion from producers and marketers on the spot market. Northern Utilities arranges for gas transportation and delivery to Promote Energy Diversity (“Energy Diversity Act”, 2016). The generating facilities associated with six of these contracts have been constructed and are now operating. In 2018, the Company filed twoits system through its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply contracts delivered to its system, or in the MDPU,case of liquefied natural gas (LNG), via trucking of supplies to storage facilities within Northern Utilities’ service territory.
Northern Utilities has available under firm contract 122,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 4.3 billion cubic feet (BCF) of underground storage. As a supplement to pipeline natural gas, Northern Utilities owns an LNG storage and vaporization facility. This plant is used principally during peak load periods to augment the supply of
pipeline
natural gas.Fitchburg purchases natural gas under contracts from producers and marketers largely under contracts of one year or less, and occasionally on the spot market. Fitchburg arranges for offshore wind generationgas transportation and another for imported hydroelectric powerdelivery to its system through its own long-term contracts with Tennessee Gas Pipeline, through peaking supply contracts delivered to its system, or in the case of LNG or liquefied propane gas (LPG), via trucking of supplies to storage facilities within Fitchburg’s service territory.
Fitchburg has available under firm contract 14,439 MMbtu per day of year-round transportation and associated transmission. Those contracts were approved in 2019. In 2019,0.4 BCF of underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the Company participated in an additional statewide procurement for offshore wind generation and the resulting contract will be filed for approval with the MDPU duringthe first quartersupply of2020. Additional long-term clean energy contracts are anticipated in compliance with An Act to Promote a Clean Energy Future (2018). Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism. pipeline natural gas.
Note 8:7: Commitments and ContingenciesContingencie
s
Regulatory Matters
Overview
—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities are provided the opportunity to recover the cost of providing
distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms.
Most of Unitil’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers are entitled to purchase their natural gas supplies from third-party suppliers at this time. Most small and each continued to approve these reconciling rate mechanisms which allow Fitchburg, Unitil Energy and Northern Utilities to recover their actual wholesale energy costs for electric power and natural gas.
medium-sized
customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted. The MDPU, the NHPUC and the MPUC each haveIn connection with the implementation of retail choice, Unitil Power and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts.
67
Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. These assetsAs of December 31, 2021, Fitchburg and Unitil Energy have been principallyfully recovered as of
their power supply-related stranded costs. The remaining balance ofobligations for prior periods related to these assets is
Energy Supply Obligations on the Company’s Consolidated Balance Sheet projected to be recovered in the nextyearand
Sheets with a corresponding regulatory asset recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the
distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire that demonstratedemonstrating their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.
Ta
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law. Among other things, the TCJA substantially reduced the corporate income tax rate to 21%21
%, effective January 1, 2018. Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, issued orders directing how the tax law changes were to be reflected in rates. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC issued a Notice of Proposed Rulemaking that would allow it to determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax reduction. This matter has beenwas resolved for Granite State in its May 2, 2018 uncontested rate settlement filing, which accounted for the effect of the TCJA.
On November 21
, 2019, the FERC issued Order No. 864, a final rule on Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes. The new rule requires public utilities with formula transmission rates to revise their formula rates to include a transparent methodology to address the impacts of the TCJA and future tax law changes on customer rates by accounting for “excess” or “deficient” Accumulated Deferred Income Taxes (ADIT). The FERC also required transmission providers with stated rates to account for theTCJA’s effect on ADIT impacts of the TCJA in their next rate case. The Company believes that complianceis complying with the new rule will not have aand there is no material impacteffect on its financial position, operating results, or cash flows.
Rate Case Activity
Northern Utilities—Base Rates—Maine—Maine
debt. As part of the order and increase in base revenue, the MPUC provided for recovery of some, but not all, of the Company’s implementation costs associated with its customer information system pending the completion of an investigation, including a third-party audit. On March 9, 2021, the MPUC opened a new docket to implement a multi-year alternative rate mechanism (“Capital Investment Recovery Adjustment” or “CIRA”)investigate the amount of customer information system costs that will allowbe allowed in rates. On January 27, 2022, the Company and the Maine Office of the Public Advocate filed a stipulation in this docket. The stipulation includes no finding of imprudence or asset disallowance. The terms of the stipulation provide for future changesrecovery of the revenue requirement related to the Company’s distributioncustomer information system in base rates and mitigate the need to file a general rate case. The CIRA is designed to recover the costs of replacing andrelocating existingfacilities and other operational and safety-related system improvements. The first annual adjustment is proposed forstarting November 1, 2020, to recover2022, which coincides with the timing of the Company’s 2019 investmentwinter cost of eligible facilities and improvements. This matter remains pending.gas rate change. The stipulation is subject to approval by the MPUC.
Northern Utilities—Targeted Infrastructure Replacement Adjustment (TIRA)—Maine—Maine
Northern Utilities—Base Rates—New Hampshire
68
which represents an increase of 8.1% over total annual revenue at present rates. The multi-year rate filing includes a revenue decoupling mechanism and an Arrearage Management Program for financial hardship customers. Northern Utilities also requested implementation of temporary rates for service rendered on and after October 1, 2021. On September 30, 2021, the NHPUC approved a settlement providing for a temporary rate increase of $2.6 million, effective October 1, 2021. As provided by statute, once a final order on permanent rates is issued, the permanent rate level is reconciled back to the effective date of the temporary
rates
.Unitil Energy—Base Rates—New Hampshire—
The Company and an initial step increaseall parties to recover post-test year capital investments. The Company’s second step increase of approximately $1.4 million of annual revenue was approved bythe case filed a motion on January 25, 2022 advising the NHPUC effective May 1, 2019,that, as a result of settlement negotiations, they have reached a comprehensive settlement agreement in principle on final rates. On January 26, 2022, the NHPUC suspended certain elements of the procedural schedule to recover eligible capital investments in 2018. Accordingallow the parties an opportunity to finalize and file the terms ofagreement. Once the settlement agreement Northern Utilities’ next distribution base rate case shall be based on an historic test year of no earlier thanhas been finalized and filed, it is subject to approval by the twelve months ending December 31, 2020.NHPUC.
Fitchburg—Base Rates—Electric—Electric
issued. On October 29, 2019, Fitchburg filed its cumulative revenue requirement of $1.11.4
million associated with the Company’s 2015-2018 capital expenditures. On December 16, 2019,22, 2020, final approval of the filing was approved,issued. On November 2, 2020, Fitchburg filed its cumulative revenue requirement of $
million associated with its 2019 capital expenditures. The Department allowed the associated rate increase to become effective on January 1, 2020,2021, subject to further investigation and reconciliation. FinalOn June 15, 2021, final approval of the filing was issued. On November 2, 2021, Fitchburg filed its cumulative revenue requirement of $
1.6 million associated with its 2019 filing remains pending.and 2020 capital expenditures. The Department allowed the associated rate increase to become effective on January 1, 2022, subject to further investigation and reconciliation.
On April 17, 2020, the MDPU approved a settlement agreement entered into by the Company and the Massachusetts Office of the Attorney General providing for a distribution increase of $1.1 million, effective November 1, 2020. The Company’s subsequent Compliance Filing reflected an adjusted distribution increase of $0.9 million, a decrease of $0.2 million from the original settlement amount. On May 21, 2020, the MDPU approved the Company’s Compliance Filing. The agreement provides for a Return on Equity of 9.7% and a capital structure reflecting 52.45% equity and 47.55% long-term debt. Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to November 1,
69
2023, though the Company may seek cost recovery for certain exogenous events that meet a $2.7 million increase in its electric base revenue decoupling target, which representsthreshold of $0.1 million. The agreement also provides for the implementation of a 4.1% increase over 2018 test year operating electric revenues. The filing included
Fitchburg—Base Rates—Gas—Gas
—
On December 17, 2019, Fitchburg filedFebruary 28, 2020, the MDPU approved a settlement agreement between the Company and the Massachusetts Office of the Attorney General. The agreement provides for an annual distribution revenue increase of $4.6 million to be phased in over two years: (1) an increase of $3.7 million, which became effective on March 1, 2020; and (2) an increase of $0.9 million, which became effective on March 1, 2021. Under the agreement, the Company will not increase or redesign base distribution rates to become effective prior to March 1, 2023, though the Company may seek cost recovery for certain exogenous events that meet a revenue effect threshold of $40,000. The agreement provides for a $7.3 million increase in its gas base revenue decoupling target, which representsReturn on Equity of 9.7% and a 20.8% increase over 2018 test year total gas operating revenues. By statute, the MDPU is afforded ten months to act on a request for a rate increase. A decision is expected by the end of October, 2020.capital structure reflecting 52.45% equity and 47.55% long-term debt.
Fitchburg—Gas System Enhancement Program—Program
—
infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October
Granite State—Base Rates—Rates
Settlement. Under the
On August 24, 2021, the FERC Noticeaccepted Granite State’s first limited Section 4 rate adjustment pursuant to the Settlement Agreement, for an annual revenue increase of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reductions under the TCJA.$0.1 million, effective September 1, 2021.
Other Matters
Fitchburg—Grid Modernization
,
which focuses on foundational investments to facilitate the interconnection and integration of distributed energy resources, optimizing system performance through command and control and self-healing measures, and optimizing system demand by facilitating consumer price-responsiveness. The GMP is subject to review and approval by the MDPU and remains pending.7
0
Fitchburg—Independent Statewide ExaminationGrid Modernization Cost Recovery Factor
—
Fitchburg—Investigation into the role of gas LDCs to achieve Commonwealth 2050 climate goals—
net-zero
greenhouse gas (GHG) emissions. In its Order opening the inquiry, the MDPU stated it is required to consider new policies and structures as the Commonwealth reduces reliance on fossil fuels, including natural gas, which may require LDCs to make significant changes to their planning processes and business models. The LDCs, including Fitchburg, have engaged net-zero
GHG goal. The study is to include anFinancial Effects of COVID-19 Pandemic
—
Northern Utilities / Granite State—Firm Capacity Contract
—
one-year
extension of its12-month
contract for firm pipeline capacity reservation, with an evergreen provision and three-month termination notification requirement. On 7
1
Reconciliation Filings—Filings
—
recovery of the ongoing costs of storm repairs incurred by Unitil Energy; and the actual wholesale energy costs for electric power and natural gas incurred by each of the three companies. Fitchburg, Unitil Energy and Northern Utilities have been, and remain in full compliance with all directives and orders regarding these filings. The Company considers these to be routine regulatory proceedings, and there are no material issues outstanding.
Fitchburg—Massachusetts RFPs—Request for Proposals (RFPs)—
The EDCs issued the RFP for Section 83D Long-Term Contracts for Qualified Clean Energy Projects in March 2017, and after selection of final projects and negotiation, final contracts for 9,554,940to 2.75
MWh of Qualified Clean Energy and associated Environmental Attributes from Hydro-Quebec Energy Services (U.S.), Inc. for hydroelectric generation were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the power purchase agreements, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE wholesale market and to credit or charge the difference between the contract costs and the ISO-NE market costs to customers. The MDPU also determined that the EDCs’ request for remuneration equal
% of the contract payments is reasonable and in the public interest and approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Massachusetts Supreme Judicial Court upheld the MDPU’s approval in an opinion dated September 3, 2020. The Company believes the power purchase obligations under these long-term contracts will have a material effect on the contractual obligations of Fitchburg, once certain conditions and contingencies are met.
The EDCs issued the RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation in June 2017. The EDCs selected an 800 MW project submitted by Vineyard Wind in May 2018, contracts were signed in July 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed two long-term contracts, each for 400 MW of offshore wind energy generation with the MDPU for approval. On April 12, 2019, the MDPU approved the offshore wind energy generation power purchase agreements, including the EDCs’ proposal to sell the energy procured under the contract into theinterest. Also, the MDPUinterest and approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes that the power purchase obligations under these long-term contracts will have a material impacteffect on the contractual obligations and regulatory assets of Fitchburg, once certain conditions and contingencies are met.
ISO-NE
wholesale market and to credit or charge the difference between the contract costs and theISO-NE
market costs to customers. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75% of the contract payments is reasonable and in the public The EDCs issued thea second RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation in June 2017. Final selectionon May 23, 2019. This solicitation sought to procure the obligation remaining under 83C at the time, an additional 800 MW of projects was made in May 2018,offshore wind energy generation. The EDCs selected an 800 MW project submitted by Mayflower Wind Energy LLC and contracts were signed in July 2018 andexecuted on July 23, 2018,January 10, 2020. A filing with the EDCs, including Fitchburg, filedMDPU for approval of two long-term contracts, each for 400MW400 MW of offshore wind energy generation, withtheMDPU for approval.was made on February 10, 2020. On April 12, 2019,November 5, 2020, the MDPU approved the Offshore Wind Energy Generation power purchase agreements, including the EDCs’ proposal to sell the energy procured under the contract into theISO-NEwholesale market and to credit or charge the difference between the contract costs and theISO-NEmarket costs to customers.agreements. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75% is reasonable and in the public interest. Also, the MDPU approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes that the power
72
purchase obligations under these long-term contracts will have a material impacteffect on the contractual obligations of Fitchburg,
In accordance with theMDPU’s approval requirement of Chapter 227 of the Vineyard Wind contractsActs of 2018, An Act to Advance Clean Energy, signed August 9, 2018, Massachusetts Department of Energy Resources (MDOER) prepared a report on the necessity, benefits and costs of requiring the EDCs to competitively conduct offshore windwill follow.
generation RFPs for 800 up to an additional
1,600MW. The MDOER filed its report with the Legislature in May,
2019, recommending that, “the EDCs should proceed with additional offshore wind solicitations for up to
1,600MW of offshore wind energy generation asin
2022and
2024and only enter into contracts if found to be cost-effective.” On March
10,
2021, Fitchburg, along with the other EDCs, filed a resultpetition with the MDPU for approval of the firsta proposed timetable and method of solicitation the remaining obligation under 83C isand execution of long-term contracts for up to procure an additional 800
1,600MW of off shore wind generation. On May
5,
2021, the DPU approved the proposed timetable and method for the solicitation, and the RFP was issued on May
7,
2021. On December
17,
2021, the EDCs selected a
1,600MW portfolio of offshore wind energy generation. The EDCs selected an 800 generation that includes a
1,200MW project submitted by Vineyard Wind and a
400MW project submitted by Mayflower Wind and contractsWind. Contract negotiations are expected to be executedcompleted by January 10, 2020. A filing with the end of
March 2022and submitted for approval to the MDPU by the end
of
April 2022.
Section 83C of Chapter 169 of the Acts of 2008 was recently amended by the Acts of 2021 to increase the aggregate amount of offshore wind capacity to be procured to 5,600 MW not later than June 30, 2027.
After considering
the two approved offshore wind contracts of 800 MW each and the most recent selection of 1,600 MWthere is
another 2,400 MW of offshore wind capacity to be procured in the future.FERC Transmission Formula Rate Proceedings—
Proceedings—
of the Federal Power Act, there are several pending proceedings before the FERC concerning the justness and reasonableness of the Return on Equity (ROE) component of the
ISO-New
England, Inc. Participating Transmission Owners’
Regional Network Service and Local Network Service formula rates. On April
14,
2017,
15,
2018,
21,
2019
the FERC issued an order in
EL14-12, Midcontinent Independent System Operator ROE, in which FERC outlined a new methodology for calculating the ROE. On December
14-12, the New England Transmission Owners (NETOs) filed a motion to reopen the record, and submittedwhich has been granted. This matter remains pending. The Company does not believe these proceedings will have a supplemental brief. Responses to that filing are due January
ISO-New
England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these resume hearing procedures. On May 24, 2019 the judge appointed a Dispute Resolution Facilitator to aid parties in settlement negotiations. The procedural schedule was suspended September 24, 2019 in order to allow participants to focus on settlement negotiations. On October 24, 2019, the NETO’sNETOs filed an unopposed motion to suspend the procedural schedule and waiver of answer period indicating that the NETO’s,NETOs, Municipal PTFPool Transmission Facility Owners and the Commission Trial Staff have reached agreement in principle on the terms of a settlement to resolve all open issues in the proceeding. On June 15, 2020 a settlement was filed. The FERC approved the settlement agreement on December 28, 2020. Pursuant to the terms of the settlement agreement, the negotiated formula rates took effect on January 1, 2022. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that these proceedings result in any changes to the rates being charged, a retroactive reconciliation may be required. The Company does not believe that these proceedings will have a material adverse impacteffect on the Company’sits financial condition or results of operations.
7
3
Contractual Obligations
The following table below lists the Company’s known specified gas and electric supply contractual obligations as of December 31, 2019.2021.
Payments Due by Period | ||||||||||||||||||||||||||||
Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2019 | Total | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 & Beyond | |||||||||||||||||||||
Gas Supply Contracts | $ | 584.8 | $ | 45.6 | $ | 48.7 | $ | 48.0 | $ | 45.5 | $ | 36.5 | $ | 360.5 | ||||||||||||||
Electric Supply Contracts | 14.2 | 2.0 | 1.2 | 1.2 | 1.2 | 1.2 | 7.4 | |||||||||||||||||||||
Total | $ | 599.0 | $ | 47.6 | $ | 49.9 | $ | 49.2 | $ | 46.7 | $ | 37.7 | $ | 367.9 | ||||||||||||||
Payments Due by Period | ||||||||||||||||||||||||||||
Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2021 | Total | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 & Beyond | |||||||||||||||||||||
Gas Supply Contracts | $ | 523.9 | $ | 58.5 | $ | 50.6 | $ | 38.8 | $ | 37.3 | $ | 36.9 | $ | 301.8 | ||||||||||||||
Electric Supply Contracts | 14.2 | 1.2 | 1.2 | 1.2 | 1.3 | 1.3 | 8.0 | |||||||||||||||||||||
Total | $ | 538.1 | $ | 59.7 | $ | 51.8 | $ | 40.0 | $ | 38.6 | $ | 38.2 | $ | 309.8 | ||||||||||||||
The Company and its subsidiaries have material energy supply commitments that are discussed in(see Note 7 to the accompanying Consolidated Financial Statements.
6
(Energy Supply)). Cash outlays for the purchase of electricity and natural gas to serve customers are subject to reconciling recovery through periodic changes in rates, with carrying charges on deferred balances. From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time. Rate recovery mechanisms are typically designed to collect theunder-recovered cash or refund the over-collected cash over subsequent periods of less than a year.Legal Proceedings
The Company is involved in legal and administrative proceedings and claims of various types,
including those
which arise in the ordinary course of business. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these claims will not have a material impacteffect on its financial position, operating results or cash flows.
Environmental Matters
The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of December 31, 2019,2021, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. Based on the Company’sits current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.
Northern Utilities Manufactured Gas Plant Sites—Sites
mid-1800s
through themid-1900s.
In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough.Northern Utilities has worked with the Maine Department of Environmental Protection and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have completed remediation activities at all sites; however, on site monitoring continues at several sites which may result in future remedial actions as directed by the applicable regulatory agency.
In July 2019, the NH DES requested that Northern Utilities review modeled expectations for groundwater contaminants against observed data at the Rochester site. The resultsIn June 2020, the NH DES
coupled the submittal of the review along with recommendations regarding remedial action, will beto a proposed extension of the gas distribution system by Northern Utilities. Northern Utilities submitted tothe review in January 2022. In anticipation of the NH DES in January 2020. While any recommendation is subject to approval byof the NH DES,work plan, the Company has accrued $0.7$0.8 million for estimated costs to complete the remediation at the Rochester site, which is included in the Environmental Obligations table below.Obligations.
74
The NHPUC and MPUC have approved regulatory mechanisms for the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding seven-year periods. For Northern Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five-year periods.
The Environmental Obligations table below shows the amounts accrued for Northern Utilities related to estimated future cleanup costs associated with Northern Utilities’ environmental remediation obligations for former MGP sites. Corresponding Regulatory Assets were recorded to reflect that the future recovery of these environmental remediation costs is expected based on regulatory precedent and established practices.
Fitchburg’s Manufactured Gas Plant Site—Site
In August 2021, the Mass DEP issued a Notice of Non-compliance to FGE following a November 2020 audit of the September 2015 Response Action Outcome on the MGP site. Mass DEP directed Fitchburg to further define the extent of MGP site contaminants in the sediment and riverbank of an abutting watercourse. FGE began the investigation in November 2021 with an anticipated completion by June 2022. The Company does not believe this investigation will have a material adverse effect on its financial condition, results of operations or cash flows.
Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods.
Unitil Energy—Kensington Distribution Operations Center
The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the current and long-term portions of the Company’s environmental obligations, which are included in Other Current Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s Consolidated Balance Sheets as ofyears-ended December 31, 20192021 and 2018.2020.
Environmental Obligations ($ millions)
(millions) | ||||||||||||||||||||||||
Fitchburg | Northern Utilities | Total | ||||||||||||||||||||||
2019 | 2018 | 2019 | 2018 | 2019 | 2018 | |||||||||||||||||||
Total Balance at Beginning of Period | $ | — | $ | 0.1 | $ | 2.0 | $ | 2.0 | $ | 2.0 | $ | 2.1 | ||||||||||||
Additions | — | — | 0.9 | 0.3 | 0.9 | 0.3 | ||||||||||||||||||
Less: Payments / Reductions | — | 0.1 | 0.2 | 0.3 | 0.2 | 0.4 | ||||||||||||||||||
Total Balance at End of Period | $ | — | $ | — | $ | 2.7 | $ | 2.0 | $ | 2.7 | $ | 2.0 | ||||||||||||
Less: Current Portion | — | — | 0.6 | 0.6 | 0.6 | 0.6 | ||||||||||||||||||
Noncurrent Balance at December 31, | $ | — | $ | — | $ | 2.1 | $ | 1.4 | $ | 2.1 | $ | 1.4 | ||||||||||||
December 31, | ||||||||
2021 | 2020 | |||||||
Total Balance at Beginning of Period | $ | 2.1 | $ | 2.7 | ||||
Additions | 0.9 | 0.2 | ||||||
Less: Payments / Reductions | 0.3 | 0.8 | ||||||
Total Balance at End of Period | 2.7 | 2.1 | ||||||
Less: Current Portion | 0.5 | 0.3 | ||||||
Noncurrent Balance at End of Period | $ | 2.2 | $ | 1.8 | ||||
75
Note 9:8: Income Taxes
Provisions for Federal anda
State Income Taxes reflectedas operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2019, 2018 2021, 2020and 20172019 are shown in the table below:following table:
,
($000’s) | ||||||||||||
2019 | 2018 | 2017 | ||||||||||
Current Income Tax Provision | ||||||||||||
Federal | $ | — | $ | — | $ | — | ||||||
State | 351 | 355 | — | |||||||||
Total Current Income Taxes | $ | 351 | $ | 355 | $ | — | ||||||
Deferred Income Provision | ||||||||||||
Federal | $ | 9,340 | $ | 5,032 | $ | 13,675 | ||||||
State | 4,117 | 3,006 | 3,862 | |||||||||
Total Deferred Income Taxes | 13,457 | 8,038 | 17,537 | |||||||||
Total Income Tax Expense | $ | 13,808 | $ | 8,393 | $ | 17,537 | ||||||
(in millions) | ||||||||||||
2021 | 2020 | 2019 | ||||||||||
Current Income Tax Provision | ||||||||||||
Federal | $ | — | $ | 0.3 | $ | — | ||||||
State | 0.7 | 0.6 | 0.3 | |||||||||
Total Current Income Taxes | $ | 0.7 | $ | 0.9 | $ | 0.3 | ||||||
Deferred Income Tax Provision | ||||||||||||
Federal | $ | 7.3 | $ | 6.5 | $ | 9.4 | ||||||
State | 3.5 | 2.8 | 4.1 | |||||||||
Total Deferred Income Taxes | 10.8 | 9.3 | 13.5 | |||||||||
Total Income Tax Expense | $ | 11.5 | $ | 10.2 | $ | 13.8 | ||||||
The differences between the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below:in the following table:
2019 | 2018 | 2017 | ||||||||||
Statutory Federal Income Tax Rate | 21 | % | 21 | % | 34 | % | ||||||
Income Tax Effects of: | ||||||||||||
State Income Taxes, net | 6 | 6 | 6 | |||||||||
Utility Plant Differences | (3 | ) | (7 | ) | (1 | ) | ||||||
Tax Credits | — | — | (1 | ) | ||||||||
Other, net | — | — | — | |||||||||
Effective Income Tax Rate | 24 | % | 20 | % | 38 | % | ||||||
2021 | 2020 | 2019 | ||||||||||
Statutory Federal Income Tax Rate | 21 | % | 21 | % | 21 | % | ||||||
Income Tax Effects of: | ||||||||||||
State Income Taxes, net | 6 | 6 | 6 | |||||||||
Utility Plant Differences | (3 | ) | (4 | ) | (3 | ) | ||||||
Other, net | — | 1 | — | |||||||||
Effective Income Tax Rate | 24 | % | 24 | % | 24 | % | ||||||
Temporary differences which gave rise to deferred tax assets and liabilities in 20192021 and 20182020 are shown below:in the following table:
Temporary Differences (000’s) | 2019 | 2018 | ||||||
Deferred Tax Assets | ||||||||
Retirement Benefit Obligations | $ | 36,551 | $ | 32,249 | ||||
Net Operating Loss Carryforwards | 1,609 | 10,773 | ||||||
Tax Credit Carryforwards | 1,489 | 2,704 | ||||||
Other, net | 1,589 | 1,571 | ||||||
Total Deferred Tax Assets | $ | 41,238 | $ | 47,297 | ||||
Deferred Tax Liabilities | ||||||||
Utility Plant Differences | $ | 134,011 | $ | 132,682 | ||||
Regulatory Assets & Liabilities | 5,239 | 6,429 | ||||||
Other, net | 5,539 | 5,964 | ||||||
Total Deferred Tax Liabilities | 144,789 | 145,075 | ||||||
Net Deferred Tax Liabilities | $ | 103,551 | $ | 97,778 | ||||
Temporary Differences (in millions) | 2021 | 2020 | ||||||
Deferred Tax Assets | ||||||||
Retirement Benefit Obligations | $ | 34.1 | $ | 40.7 | ||||
Net Operating Loss Carryforwards | 4.1 | — | ||||||
Tax Credit Carryforwards | 0.7 | 0.3 | ||||||
Other, net | 1.3 | 1.3 | ||||||
Total Deferred Tax Assets | $ | 40.2 | $ | 42.3 | ||||
Deferred Tax Liabilities | ||||||||
Utility Plant Differences | 157.4 | $ | 143.8 | |||||
Regulatory Assets & Liabilities | 9.4 | 6.2 | ||||||
Other, net | 1.1 | 1.3 | ||||||
Total Deferred Tax Liabilities | 167.9 | 151.3 | ||||||
Net Deferred Tax Liabilities | $ | 127.7 | $ | 109.0 | ||||
FASB Codification, and has concluded that no adjustment for recognition,
de-recognition,
settlement or foreseeable future76
Income tax filings
for the year ended December 31, 2020 have been filed with the IRS, Massachusetts Department of Revenue, the Maine Revenue Service, and the New Hampshire Department of Revenue Administration. In the Company’s federal tax returns for the year ended December 31, 2020 which were filed with the IRS in October 2021, the Company generated federal Net Operating Loss Carryforward (NOLC) assets of $7.7 0.7 million of cumulative state tax credit carryforwards to offset future income taxes payable. If unused, the Company’s state tax credit carryforwards will begin to expire in 2024.
million, principally due to tax repairs expense and tax depreciation. As of December 31, 2021, the Company recognized the utilization of approximately
$3.6 million of the NOLC asset to offset current taxes payable. In addition, at December 31, 2021, the Company had $In March 2020, the Coronavirus Aid, Relief and Economic Security (CARES) Act was signed into law. The CARES Act included several tax changes as part of its economic package. These changes principally related to expanded Net Operating Loss carryback periods, increases to interest deductibility limitations, and accelerated Alternative Minimum Tax refunds. The Company has evaluated these items and determined that the items do not have a material effect on the Company’s financial statements as of December 31, 2021. Additionally, the CARES Act enacted the Employee Retention Credit (ERC) to incentivize companies to retain employees. The ERC is a 50% credit on employee wages for employees that are retained and cannot perform their job duties at 100% capacity as a result of coronavirus pandemic restrictions.
In December 2020, the Consolidated Appropriations Act, 2021 (CAA) was signed into law. The CAA included additional funding through tax credits as part of its economic package for 2021. These changes include the temporary removal of deduction limitations on business meals through December 2022 and additional funding for the ERC with expanded benefits extended through June 30, 2021. The expanded ERC is a 70% credit on employee wages for employees that are retained and cannot perform their job duties at 100% capacity as a result of coronavirus pandemic restrictions.
In March 2021, the American Rescue Plan Act of 2021 (ARPA) was signed into law. The ARPA included certain provisions that provide economic relief for the
ongoing COVID-19
pandemic, such as extending the ERC through December 31, 2021, and other future governmental revenue producing provisions, such as expanding the scope for deduction limitations on executive compensation in future years.The Company has evaluated each of the CARES, CAA and ARPAprovisions and determined that they do not have a material effect on the Company’s financial statements as of December 31, 2021. The Company has recorded a reduction in payroll taxes related to the ERC for $0.4 million in 2021 and $0.6 million in 2020. These credits were recorded as a reduction to payroll tax expense which is recorded in Taxes Other Than Income Taxes in the Consolidated Statements of Earnings.
In December 2017,
million at December 31,
as a result of the ADIT revaluation. The Company expects to flow through to customers $47.1 million of excess ADIT in utility base rates. Approximately $1.8 million of excess ADIT was created through reconciling mechanisms at December 31, 2017, which had not been previously collected from customers through utility rates. The Company reconciled these excess ADIT amounts through the specific reconciliation mechanisms in each of those individual reconciling mechanisms which were reviewed by state regulators. In addition to the $48.9 million of net excess ADIT, as of December 31, 2018, there was $2.0 million of remaining excess ADIT created by the recognition of NOLC, and related to the implementation of the new federal tax rate of the TCJA, which had not been previously included in utility rates. The Company recognized the benefit of this excess ADIT in accordance with the regulatory treatment of excess ADIT for each jurisdiction. In 2019, the Company recognized $1.7 million of this amount and the remaining $0.3 million was recognized in
2020.
Based on communications received by the Company from its state regulators in rate cases and other regulatory proceedings in the first quarter of 2018
and as prescribed in the TCJA, the recent FERC guidance noted above and IRS normalization rules;rules, the benefit of these protected excess ADIT amounts will be subject to flow back to customers in future utility rates according to the Average Rate Assumption Method (ARAM). ARAM reconciles excess ADIT at the reversal rate of the underlying book/tax temporary timing differences. The Company estimates the ARAM flow back period for protected and unprotected excess ADIT to be
between
fifteen
and
twenty
years over
the remaining life of the related utility plant. Subject to regulatory approval, the Company expects to flow back to customers a
net $47.1
million
of protected excess ADIT created as a result of the lowering of the statutory tax rate by the TCJA over periods estimated to be fifteen to twenty years.
finalized
Note 10:9: Retirement Benefit Plans
The Company sponsors the following retirement benefit plans to provide certain pension and post-retirement benefits for its retirees and current employees as follows:
The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan. Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service. Effective January 1, 2010, the Pension Plan was closed to new non-union employees. For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union.
The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees. The Company has established Voluntary Employee Benefit Trusts, into which it funds contributions to the PBOP Plan.
The Unitil Corporation Supplemental Executive Retirement Plan (SERP)—The SERP is a
non-qualified
retirement plan, with participation limited to executives selected by the Board of Directors.The following table includes the key assumptions used in determining the Company’s benefit plan costs and obligations:
2019 | 2018 | 2017 | ||||||||||
Used to Determine Plan costs for years ended December 31: | ||||||||||||
Discount Rate | 4.25 | % | 3.60 | % | 4.10 | % | ||||||
Rate of Compensation Increase | 3.00 | % | 3.00 | % | 3.00 | % | ||||||
Expected Long-term rate of return on plan assets | 7.50 | % | 7.75 | % | 7.75 | % | ||||||
Health Care Cost Trend Rate Assumed for Next Year | 7.00 | % | 7.50 | % | 8.00 | % | ||||||
Ultimate Health Care Cost Trend Rate | 4.50 | % | 4.50 | % | 4.00 | % | ||||||
Year that Ultimate Health Care Cost Trend Rate is reached | 2024 | 2024 | 2025 | |||||||||
Used to Determine Benefit Obligations at December 31: | ||||||||||||
Discount Rate | 3.25 | % | 4.25 | % | 3.60 | % | ||||||
Rate of Compensation Increase | 3.00 | % | 3.00 | % | 3.00 | % | ||||||
Health Care Cost Trend Rate Assumed for Next Year | 7.00 | % | 7.00 | % | 7.50 | % | ||||||
Ultimate Health Care Cost Trend Rate | 4.50 | % | 4.50 | % | 4.50 | % | ||||||
Year that Ultimate Health Care Cost Trend Rate is reached | 2029 | 2024 | 2024 | |||||||||
2021 | 2020 | 2019 | ||||||||||
Used to Determine Plan costs for years ended December 31: | ||||||||||||
Discount Rate | 2.50 | % | 3.25 | % | 4.25 | % | ||||||
Rate of Compensation Increase | 3.00 | % | 3.00 | % | 3.00 | % | ||||||
Expected Long-term rate of return on plan assets | 7.50 | % | 7.40 | % | 7.50 | % | ||||||
Health Care Cost Trend Rate Assumed for Next Year | 6.60 | % | 7.00 | % | 7.00 | % | ||||||
Ultimate Health Care Cost Trend Rate | 4.50 | % | 4.50 | % | 4.50 | % | ||||||
Year that Ultimate Health Care Cost Trend Rate is reached | 2029 | 2029 | 2024 | |||||||||
Used to Determine Benefit Obligations at December 31: | ||||||||||||
Discount Rate | 2.85 | % | 2.50 | % | 3.25 | % | ||||||
Rate of Compensation Increase | 3.00 | % | 3.00 | % | 3.00 | % | ||||||
Health Care Cost Trend Rate Assumed for Next Year | 6.20 | % | 6.60 | % | 7.00 | % | ||||||
Ultimate Health Care Cost Trend Rate | 4.50 | % | 4.50 | % | 4.50 | % | ||||||
Year that Ultimate Health Care Cost Trend Rate is reached | 2029 | 2029 | 2029 | |||||||||
The Discount Rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For 2019,2021, a change in the discount rate of 0.25
78
The following table provides the components of the Company’s Retirement plan costs (000’s):
Pension Plan | PBOP Plan | SERP | ||||||||||||||||||||||||||||||||||
2019 | 2018 | 2017 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | ||||||||||||||||||||||||||||
Service Cost | $ | 3,104 | $ | 3,393 | $ | 3,295 | $ | 2,304 | $ | 2,933 | $ | 2,974 | $ | 247 | $ | 487 | $ | 460 | ||||||||||||||||||
Interest Cost | 6,484 | 5,878 | 6,057 | 3,426 | 3,404 | 3,913 | 567 | 404 | 392 | |||||||||||||||||||||||||||
Expected Return on Plan Assets | (8,475 | ) | (7,785 | ) | (7,306 | ) | (1,645 | ) | (1,635 | ) | (1,347 | ) | — | — | — | |||||||||||||||||||||
Prior Service Cost Amortization | 320 | 324 | 263 | 1,213 | 1,309 | 1,399 | 56 | 189 | 189 | |||||||||||||||||||||||||||
Actuarial Loss Amortization | 4,324 | 5,786 | 4,662 | 227 | 1,383 | 2,098 | 628 | 486 | 295 | |||||||||||||||||||||||||||
Sub-total | 5,757 | 7,596 | 6,971 | 5,525 | 7,394 | 9,037 | 1,498 | 1,566 | 1,336 | |||||||||||||||||||||||||||
Amounts Capitalized or Deferred | (2,227 | ) | (3,465 | ) | (3,122 | ) | (2,317 | ) | (3,416 | ) | (4,515 | ) | (430 | ) | (451 | ) | (397 | ) | ||||||||||||||||||
NPBC Recognized | $ | 3,530 | $ | 4,131 | $ | 3,849 | $ | 3,208 | $ | 3,978 | $ | 4,522 | $ | 1,068 | $ | 1,115 | $ | 939 | ||||||||||||||||||
Pension Plan | PBOP Plan | SERP | ||||||||||||||||||||||||||||||||||
2021 | 2020 | 2019 | 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||
Service Cost | $ | 3,472 | $ | 3,322 | $ | 3,104 | $ | 3,034 | $ | 2,698 | $ | 2,304 | $ | 354 | $ | 283 | $ | 247 | ||||||||||||||||||
Interest Cost | 5,003 | 5,776 | 6,484 | 2,740 | 3,121 | 3,426 | 458 | 549 | 567 | |||||||||||||||||||||||||||
Expected Return on Plan Assets | (9,693 | ) | (9,019 | ) | (8,475 | ) | (2,508 | ) | (2,063 | ) | (1,645 | ) | — | — | — | |||||||||||||||||||||
Prior Service Cost Amortization | 301 | 320 | 320 | 1,208 | 1,210 | 1,213 | 56 | 57 | 56 | |||||||||||||||||||||||||||
Actuarial Loss Amortization | 8,089 | 6,472 | 4,324 | 1,045 | 744 | 227 | 1,489 | 1,036 | 628 | |||||||||||||||||||||||||||
Sub-total | 7,172 | 6,871 | 5,757 | 5,519 | 5,710 | 5,525 | 2,357 | 1,925 | 1,498 | |||||||||||||||||||||||||||
Amounts Capitalized or Deferred | (3,384 | ) | (3,083 | ) | (2,227 | ) | (3,136 | ) | (2,865 | ) | (2,317 | ) | (712 | ) | (579 | ) | (430 | ) | ||||||||||||||||||
NPBC Recognized | $ | 3,788 | $ | 3,788 | $ | 3,530 | $ | 2,383 | $ | 2,845 | $ | 3,208 | $ | 1,645 | $ | 1,346 | $ | 1,068 | ||||||||||||||||||
The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reducesvolatility. This market-related valuation recognizes investment gainsgaimpactedaffected as previously deferred gains or losses are recognized. TheCompany’s pension expense for the years 2019,
year-to-year
i
ns or lossesover a three-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be $7.2 million, $
$6.9 million and $
$5.8 million,
respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2019, 20182021, 2020 and 20172019 would have been $
$6.1 million, $
$6.5 million and $
$7.3 million respectively, prior to amounts capitalized or deferred.
79
The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s)
:
Pension Plan | PBOP Plan | SERP | ||||||||||||||||||||||
Change in Plan Assets: | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||||
Plan Assets at Beginning of Year | $ | 107,808 | $ | 102,315 | $ | 21,109 | $ | 20,234 | $ | — | $ | — | ||||||||||||
Actual Return on Plan Assets | 17,908 | (6,149 | ) | 3,808 | (1,085 | ) | — | — | ||||||||||||||||
Employer Contributions | 6,916 | 16,628 | 4,000 | 4,000 | 610 | 401 | ||||||||||||||||||
Participant Contributions | — | — | 121 | 153 | — | — | ||||||||||||||||||
Benefits Paid | (6,877 | ) | (4,986 | ) | (1,758 | ) | (2,193 | ) | (610 | ) | (401 | ) | ||||||||||||
Plan Assets at End of Year | $ | 125,755 | $ | 107,808 | $ | 27,280 | $ | 21,109 | $ | — | $ | — | ||||||||||||
Change in PBO: | ||||||||||||||||||||||||
PBO at Beginning of Year | $ | 156,197 | $ | 166,921 | $ | 81,005 | $ | 94,122 | $ | 13,754 | $ | 11,723 | ||||||||||||
Service Cost | 3,104 | 3,393 | 2,304 | 2,933 | 247 | 487 | ||||||||||||||||||
Interest Cost | 6,484 | 5,878 | 3,426 | 3,404 | 567 | 404 | ||||||||||||||||||
Participant Contributions | — | — | 121 | 153 | — | — | ||||||||||||||||||
Plan Amendments | — | — | — | — | 225 | — | ||||||||||||||||||
Benefits Paid | (6,877 | ) | (4,986 | ) | (1,758 | ) | (2,193 | ) | (610 | ) | (401 | ) | ||||||||||||
Actuarial (Gain) or Loss | 23,227 | (15,009 | ) | 10,559 | (17,414 | ) | 3,576 | 1,541 | ||||||||||||||||
PBO at End of Year | $ | 182,135 | $ | 156,197 | $ | 95,657 | $ | 81,005 | $ | 17,759 | $ | 13,754 | ||||||||||||
Funded Status: Assets vs PBO | $ | (56,380 | ) | $ | (48,389 | ) | $ | (68,377 | ) | $ | (59,896 | ) | $ | (17,759 | ) | $ | (13,754 | ) | ||||||
Pension Plan | PBOP Plan | SERP | ||||||||||||||||||||||
Change in Plan Assets: | 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||
Plan Assets at Beginning of Year | $ | 137,406 | $ | 125,755 | $ | 32,847 | $ | 27,280 | $ | — | $ | — | ||||||||||||
Actual Return on Plan Assets | 16,989 | 13,024 | 3,586 | 3,739 | — | — | ||||||||||||||||||
Employer Contributions | 4,100 | 4,665 | 8,903 | 4,156 | 637 | 654 | ||||||||||||||||||
Participant Contributions | — | — | 220 | 240 | — | — | ||||||||||||||||||
Benefits Paid | (6,489 | ) | (6,038 | ) | (2,905 | ) | (2,568 | ) | (637 | ) | (654 | ) | ||||||||||||
Plan Assets at End of Year | $ | 152,006 | $ | 137,406 | $ | 42,651 | $ | 32,847 | $ | — | $ | — | ||||||||||||
Change in PBO: | ||||||||||||||||||||||||
PBO at Beginning of Year | $ | 206,092 | $ | 182,135 | $ | 106,831 | $ | 95,657 | $ | 20,225 | $ | 17,759 | ||||||||||||
Service Cost | 3,472 | 3,322 | 3,034 | 2,698 | 354 | 283 | ||||||||||||||||||
Interest Cost | 5,003 | 5,776 | 2,740 | 3,121 | 458 | 549 | ||||||||||||||||||
Participant Contributions | — | — | 220 | 240 | — | — | ||||||||||||||||||
Plan Amendments | 674 | 732 | — | — | — | — | ||||||||||||||||||
Benefits Paid | (6,489 | ) | (6,038 | ) | (2,905 | ) | (2,568 | ) | (637 | ) | (654 | ) | ||||||||||||
Actuarial (Gain) or Loss | (9,334 | ) | 20,165 | 2,167 | 7,683 | (2,686 | ) | 2,288 | ||||||||||||||||
PBO at End of Year | $ | 199,418 | $ | 206,092 | $ | 112,087 | $ | 106,831 | $ | 17,714 | $ | 20,225 | ||||||||||||
Funded Status: Assets vs PBO | $ | (47,412 | ) | $ | (68,686 | ) | $ | (69,436 | ) | $ | (73,984 | ) | $ | (17,714 | ) | $ | (20,225 | ) | ||||||
The increasedecrease in the PBO for the Pension plan as of DecemberDece20192021 compared to December 31, 20182020 primarily reflects a decreasean increase in the assumed discount rate as of December 31, 2019. The increase in the PBO for the PBOP plan as of December 31, 2019 compared to December 31, 2018 reflects a decrease in the assumed discount rate as of December 31, 2019.2021.
m
ber 31, The funded status of the Pension, PBOP and SERP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets and is recorded on the balance sheets as an asset or a liability. Because the Company recovers the retiree benefit costs from customers through rates, regulatory assets are recorded in lieu of an adjustment to Accumulated Other Comprehensive Income/(Loss).
The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets, net of deferred tax benefits, of $88.9$86.4 million and $72.0$103.7 million at December 31, 20192021 and 2018,2020, respectively, to account for the future collection of these plan obligations in electric and gas rates.
The Accumulated Benefit Obligation (ABO) is required to be disclosed for all plans where the ABO is in excess of plan assets. The difference between the PBO and the ABO is that the PBO includes projected compensation increases. The ABO for the Pension Plan was $166.5
$185.1 million and $142.8
$189.4 million as of
December 31, 20192021 and 2018,2020, respectively. The ABO for the SERP was $13.6
$17.5 million and $10.8
$16.7 million as of December 31, 20192021 and 2018,2020, respectively. For the PBOP Plan, the ABO and PBO are the
same. (See Note 1 (Summary of Significant Accounting Policies) for further discussion of SERP
funding.)
The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 20202022 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension Plan costs.
8880
The following table represents employer contributions, participant contributions and benefit payments (000’s)(
000
’s).
Pension Plan | PBOP Plan | SERP | ||||||||||||||||||||||||||||||||||
2019 | 2018 | 2017 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | ||||||||||||||||||||||||||||
Employer Contributions | $ | 6,916 | $ | 16,628 | $ | 4,100 | $ | 4,000 | $ | 4,000 | $ | 4,000 | $ | 610 | $ | 401 | $ | 34 | ||||||||||||||||||
Participant Contributions | $ | — | $ | — | $ | — | $ | 121 | $ | 153 | $ | 126 | $ | — | $ | — | $ | — | ||||||||||||||||||
Benefit Payments | $ | 6,877 | $ | 4,986 | $ | 5,574 | $ | 1,758 | $ | 2,193 | $ | 2,405 | $ | 610 | $ | 401 | $ | 34 | ||||||||||||||||||
Pension Plan | PBOP Plan | SERP | ||||||||||||||||||||||||||||||||||
2021 | 2020 | 2019 | 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||
Employer Contributions | $ | 4,100 | $ | 4,665 | $ | 6,916 | $ | 8,903 | $ | 4,156 | $ | 4,000 | $ | 637 | $ | 654 | $ | 610 | ||||||||||||||||||
Participant Contributions | $ | — | $ | — | $ | — | $ | 220 | $ | 240 | $ | 121 | $ | — | $ | — | $ | — | ||||||||||||||||||
Benefit Payments | $ | 6,489 | $ | 6,038 | $ | 6,877 | $ | 2,905 | $ | 2,568 | $ | 1,758 | $ | 637 | $ | 654 | $ | 610 | ||||||||||||||||||
The following table represents estimated futurebenefitpayments (000’s).
Estimated Future Benefit Payments | ||||||||||||
Pension | PBOP | SERP | ||||||||||
2020 | $ | 6,706 | $ | 2,774 | $ | 653 | ||||||
2021 | 7,192 | 3,035 | 653 | |||||||||
2022 | 6,903 | 3,167 | 651 | |||||||||
2023 | 7,687 | 3,341 | 650 | |||||||||
2024 | 8,622 | 3,622 | 648 | |||||||||
2025 - 2029 | 49,511 | 21,761 | 6,037 | |||||||||
Estimated Future Benefit Payments | ||||||||||||
Pension | PBOP | SERP | ||||||||||
2022 | $ | 7,040 | $ | 3,151 | $ | 637 | ||||||
2023 | 8,046 | 3,448 | 636 | |||||||||
2024 | 8,497 | 3,559 | 635 | |||||||||
2025 | 8,702 | 3,862 | 1,090 | |||||||||
2026 | 9,804 | 4,158 | 1,144 | |||||||||
2027—2031 | 54,565 | 23,853 | 5,583 | |||||||||
The Expected Long-Term Rate of Return on Pension Plan assets assumption used by the Company is developed based on input from actuaries and investment managers. The Company’s Expected Long-Term Rate of Return on Pension Plan assets is based on target investment allocation of 53
following tables.
Pension Plan | Target Allocation 2020 | Actual Allocation at December 31, | Target Allocation 2022 | Actual Allocation at December 31, | ||||||||||||||||||||||||||||
2019 | 2018 | 2017 | ||||||||||||||||||||||||||||||
Target Allocation 2022 | 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||
Equity Funds | 53 | % | 54 | % | 49 | % | 49 | % | 56 | % | 57 | % | 58 | % | 54 | % | ||||||||||||||||
Debt Funds | 37 | % | 36 | % | 40 | % | 34 | % | 39 | % | 38 | % | 37 | % | 36 | % | ||||||||||||||||
Real Estate Fund | 10 | % | 9 | % | 10 | % | 10 | % | 5 | % | 4 | % | 4 | % | 9 | % | ||||||||||||||||
Asset Allocation Fund (1) | — | — | — | 6 | % | |||||||||||||||||||||||||||
Other | — | 1 | % | 1 | % | 1 | % | — | 1 | % | 1 | % | 1 | % | ||||||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||||||||||||||
| (1) |
PBOP Plan | Target Allocation 2020 | Actual Allocation at December 31, | ||||||||||||||
2019 | 2018 | 2017 | ||||||||||||||
Equity Funds | 55 | % | 56 | % | 53 | % | 56 | % | ||||||||
Debt Funds | 45 | % | 44 | % | 47 | % | 42 | % | ||||||||
Other (1) | — | — | — | 2 | % | |||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Represents investments being held in cash equivalents as of December 31, |
PBOP Plan | Target Allocation 2022 | Actual Allocation at December 31, | ||||||||||||||
2021 | 2020 | 2019 | ||||||||||||||
Equity Funds | 55 | % | 56 | % | 55 | % | 56 | % | ||||||||
Debt Funds | 45 | % | 44 | % | 45 | % | 44 | % | ||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 7.50
The target rate of return for the Plans has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class.
Following is a description of the valuation methodologies used for assets measured at fair value. There have been no changes in the methodologies used at December 31, 20192021 and 2018.2020. Please also see Note 1 (Summary of Significant Accounting Policies) for a discussion of the Company’s fair value accounting policy.
8
1
Equity, Fixed Income, Index and Asset Allocation Funds
These investments are valued based on quoted prices from active markets. These securities are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.
Cash Equivalents
These investments are valued at cost, which approximates fair value, and are categorized in Level 1.
Real Estate Fund
These investments are valued at net asset value per unit based on a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity. In accordance with FASB Codification Topic 820, “Fair Value Measurement”, these investments have not been classified in the fair value hierarchy. The fair value amounts presented in the tables below for the Real Estate Fund are intended to permit reconciliation of the fair value hierarchy tothe “Plan Assets at End of Year” line item shown in the “Change in Plan Assets” table above.
Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 20192021 and 20182020 are as follows (000’s):
Fair Value Measurements at Reporting Date Using | ||||||||||||||||
Description | Balance as of December 31, | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | ||||||||||||
2019 | ||||||||||||||||
Pension Plan Assets: | ||||||||||||||||
Mutual Funds: | ||||||||||||||||
Equity Funds | $ | 68,848 | $ | 68,848 | $ | — | $ | — | ||||||||
Fixed Income Funds | 44,980 | 44,980 | — | — | ||||||||||||
Total Mutual Funds | 113,828 | 113,828 | — | — | ||||||||||||
Cash Equivalents | 750 | 750 | ||||||||||||||
Total Assets in the Fair Value Hierarchy | $ | 114,578 | $ | 114,578 | $ | — | $ | — | ||||||||
Real Estate Fund–Measured at Net Asset Value | 11,177 | |||||||||||||||
Total Assets | $ | 125,755 | ||||||||||||||
2018 | ||||||||||||||||
Pension Plan Assets: | ||||||||||||||||
Mutual Funds: | ||||||||||||||||
Equity Funds | $ | 52,884 | $ | 52,884 | $ | — | $ | — | ||||||||
Fixed Income Funds | 43,281 | 43,281 | — | — | ||||||||||||
Total Mutual Funds | 96,165 | 96,165 | — | — | ||||||||||||
Cash Equivalents | 1,202 | 1,202 | ||||||||||||||
Total Assets in the Fair Value Hierarchy | $ | 97,367 | $ | 97,367 | $ | — | $ | — | ||||||||
Real Estate Fund–Measured at Net Asset Value | 10,441 | |||||||||||||||
Total Assets | $ | 107,808 | ||||||||||||||
Fair Value Measurements at Reporting Date Using | ||||||||||||||||
Description | Balance as of December 31, | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | ||||||||||||
2021 | ||||||||||||||||
Pension Plan Assets: | ||||||||||||||||
Mutual Funds: | ||||||||||||||||
Equity Funds | $ | 86,356 | $ | 86,356 | $ | — | $ | — | ||||||||
Fixed Income Funds | 57,883 | 57,883 | — | — | ||||||||||||
Total Mutual Funds | 144,239 | 144,239 | — | — | ||||||||||||
Cash Equivalents | 912 | 912 | ||||||||||||||
Total Assets in the Fair Value Hierarchy | $ | 145,151 | $ | 145,151 | $ | — | $ | — | ||||||||
Real Estate Fund–Measured at Net Asset Value | 6,855 | |||||||||||||||
Total Assets | $ | 152,006 | ||||||||||||||
2020 | ||||||||||||||||
Pension Plan Assets: | ||||||||||||||||
Mutual Funds: | ||||||||||||||||
Equity Funds | $ | 79,690 | $ | 79,690 | $ | — | $ | — | ||||||||
Fixed Income Funds | 50,622 | 50,622 | — | — | ||||||||||||
Total Mutual Funds | 130,312 | 130,312 | — | — | ||||||||||||
Cash Equivalents | 1,277 | 1,277 | ||||||||||||||
Total Assets in the Fair Value Hierarchy | $ | 131,589 | $ | 131,589 | $ | — | $ | — | ||||||||
Real Estate Fund–Measured at Net Asset Value | 5,817 | |||||||||||||||
Total Assets | $ | 137,406 | ||||||||||||||
Redemptions of the Real Estate Fund are subject to a sixty-five day notice period and the fund is valued quarterly. There are no unfunded commitments.
8
2
Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 20192021 and 20182020 are as follows (000’s):
Fair Value Measurements at Reporting Date Using | ||||||||||||||||
Description | Balance as of December 31, | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | ||||||||||||
2019 | ||||||||||||||||
PBOP Plan Assets: | ||||||||||||||||
Mutual Funds: | ||||||||||||||||
Fixed Income Funds | $ | 11,888 | $ | 11,888 | $ | — | $ | — | ||||||||
Equity Funds | 15,392 | 15,392 | — | — | ||||||||||||
Total Assets | $ | 27,280 | $ | 27,280 | $ | — | $ | — | ||||||||
2018 | ||||||||||||||||
PBOP Plan Assets: | ||||||||||||||||
Mutual Funds: | ||||||||||||||||
Fixed Income Funds | $ | 9,905 | $ | 9,905 | $ | — | $ | — | ||||||||
Equity Funds | 11,204 | 11,204 | — | — | ||||||||||||
Total Assets | $ | 21,109 | $ | 21,109 | $ | — | $ | — | ||||||||
Fair Value Measurements at Reporting Date Using | ||||||||||||||||
Description | Balance as of December 31, | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | ||||||||||||
2021 | ||||||||||||||||
PBOP Plan Assets: | ||||||||||||||||
Mutual Funds: | ||||||||||||||||
Fixed Income Funds | $ | 18,882 | $ | 18,882 | $ | — | $ | — | ||||||||
Equity Funds | 23,769 | 23,769 | — | — | ||||||||||||
Total Assets | $ | 42,651 | $ | 42,651 | $ | — | $ | — | ||||||||
2020 | ||||||||||||||||
PBOP Plan Assets: | ||||||||||||||||
Mutual Funds: | ||||||||||||||||
Fixed Income Funds | $ | 14,716 | $ | 14,716 | $ | — | $ | — | ||||||||
Equity Funds | 18,131 | 18,131 | — | — | ||||||||||||
Total Assets | $ | 32,847 | $ | 32,847 | $ | — | $ | — | ||||||||
Employee 401(k) Tax Deferred Savings Plan—
The Company’s contributions to the 401(k) Plan were $2.8
$3.3 million, $2.7
$3.0 million and $2.4
$2.8 million for the years ended December 31, 2021, 2020 and 2019, 2018 and 2017, respectively.
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
Item 9A. | Controls and Procedures |
Disclosure Controls and Procedures
Management of the Company, under the supervision and with the participation of the Company’s Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of December 31, 2019.2021. Based on this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer concluded as of December 31, 20192021 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules
13a-15(e)
and15d-15(e))
were effective.Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules
13a-15(f)
and15d-15(f).
Under the supervision and with the participation of management, including the Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, Unitil management has evaluated the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019,2021, based upon criteria established in the “Internal Control–Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).Commission. Based on this evaluation, Unitil management concluded that Unitil’s internal control over financial reporting was effective as of December 31, 2019.2021.
Deloitte & Touche LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2019,2021, as stated in their report which appears in Part II, Item 8 herein.
Changes in Internal Control over Financial Reporting
There have been no changes in Unitil’s internal control over financial reporting (as defined in Exchange Act Rules20192021 that have materially affected, or are reasonably likely to materially affect, Unitil’s internal control over financial reporting.
13a-15(f)
and15d-15(f))
during the fiscal quarter ended December 31, Item 9B. | Other Information |
On January 30, 2020,February 1, 2022, the Company issued a press release announcing its results of operations for the quarter and year ended December 31, 2019.2021. The press release is furnished with this Annual Report on Form
10-K
as Exhibit 99.1.Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections. |
Not applicable.
84
PART III
Item 10. | Directors, Executive Officers and Corporate Governance |
Information required by this Item is set forth in the “Proposal 1: Election of Directors” section and the “Description of Management” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 29, 2020.27, 2022. Information regarding compliance with Section 16(a) of the Securities Exchange Act of 1934, is set forth in the “Corporate Governance and Policies of the Board—Section 16(a) Beneficial Ownership Reporting Compliance” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 29, 2020.27, 2022. Information regarding the Company’s Audit Committee is set forth in the “Committees of the Board—Audit Committee” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 29, 2020.27, 2022. Information regarding the Company’s Code of Ethics is set forth in the “Corporate Governance and Policies of the Board—Code of Ethics” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 29, 2020.27, 2022. Information regarding procedures by which shareholders may recommend nominees to the Company’s Board of Directors is set forth in the “Corporate Governance and Policies of the Board—Nominations” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 29, 2020.27, 2022.
Item 11. | Executive Compensation |
Information required by this Item is set forth in the “Compensation Discussion and Analysis” and “Compensation of Named Executive Officers” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 29, 2020.27, 2022.
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Information required by this Item is set forth in the “Beneficial Ownership” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 29, 2020,27, 2022, as well as the Equity Compensation Plan Information table in Part II, Item 5 of this Form
10-K.
Item 13. | Certain Relationships and Related Transactions, and Director Independence |
Information required by this Item is set forth in the “Corporate Governance and Policies of the Board—Transactions with Related Persons” and the “Corporate Governance and Policies of the Board—Director Independence” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 29, 2020.27, 2022.
Item 14. | Principal Accountant Fees and Services |
Information required by this Item is set forth in the “Audit Committee Report—Principal Accountant Fees and Services” and the “Audit Committee Report—Audit Committee29, 2020.27, 2022.
Pre-Approval
Policy” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 85
PART IV
Item 15. | Exhibits and Financial Statement Schedules |
(a) (1) and (2)—
LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
The following financial statements are included herein under Part II, Item 8, Financial Statements and Supplementary Data:
Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP; PCAOB ID No. 34)
Consolidated Statements of Earnings for the years ended December 31, 2019, 20182021, 2020 and 20172019
Consolidated Balance Sheets—December 31, 20192021 and 20182020
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 20182021, 2020 and 20172019
Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2019, 20182021, 2020 and 20172019
Notes to Consolidated Financial Statements
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions, are not applicable, or information required is included in the financial statements or notes thereto and, therefore, have been omitted.
(3)—
LIST OF EXHIBITS
Exhibit Number | Description of Exhibit | Reference* | ||||||
| 3.1 | Articles of Incorporation of Unitil Corporation. | Exhibit 3.1 to Form S-14 Registration Statement No. 2-93769 dated October 12, 1984 (P) | ||||||
| 3.2 | Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on March 4, 1992. | Exhibit 3.2 to Form 10-K for 1991 (SEC FileNo. 1-8858) (P) | ||||||
| 3.3 | ||||||||
| 3.4 | ||||||||
| 3.5 | ||||||||
| 4.1 | ||||||||
| 4.2 | Fitchburg Note Agreement dated November 1, 1993 for the 6.75% Notes due November 30, 2023. | Exhibit 4.18 to Form 10-K for 1993 (SEC FileNo. 1-8858) (P) | ||||||
86
Exhibit Number | Description of Exhibit | Reference* | ||||||
4.3 | ||||||||
4.4 | ||||||||
4.5 | ||||||||
4.6 | Fitchburg Note Agreement dated December 21, 2005 for the 5.90% Notes due December 15, 2030. | ** | ||||||
4.7 | Thirteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of September 26, 2006. | ** | ||||||
4.8 | Unitil Corporation Note Purchase Agreement, dated as of May 2, 2007, for the 6.33% Senior Notes due May 1, 2022. | ** | ||||||
4.9 | ||||||||
4.10 | ||||||||
| 4.18 | ||||||
87
Exhibit Number | Description of Exhibit | Reference* | ||||||
| 4.19 | ||||||||
88
89
Exhibit Number | Description of Exhibit | Reference* | ||||
| 4.49 | Mortgage Loan Note dated December 18, 2020 issued to TD Bank, N.A. | Exhibit 4.50 to Form 10-K for 2020 (SEC File No. 1-8858) | ||||
| 4.50 | Description of Registrant’s Securities | Filed herewith | ||||
10.1*** | Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement. | |||||
| 10.2*** | ||||||
| 10.3*** | ||||||
| 10.4*** | ||||||
| 10.5*** | ||||||
| 10.6*** | Severance Agreement dated March 23, 2020, between the Company and Daniel J. Hurstak. | Exhibit 10.1 to Form 8-K dated March 19, 2020 (SEC File No. 1-8858) | ||||
| 10.8*** | ||||||
| 10.10*** | ||||||
| 10.11*** | ||||||
| 10.12*** | ||||||
| 10.13*** | ||||||
| Exhibit 4.7 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012 | ||||||
90
Exhibit Number | Description of Exhibit | |||||||
Reference* | ||||||||
10.14*** | ||||||||
10.17*** | ||||||||
10.19*** | ||||||||
10.20*** | ||||||||
10.21*** | ||||||||
10.22 | ||||||||
11.1 | ||||||||
21.1 | ||||||||
23.1 | ||||||||
31.1 | ||||||||
31.2 | ||||||||
31.3 | ||||||||
32.1 | ||||||||
91
Exhibit Number | Description of Exhibit | Reference* | ||||
| 99.1 | Unitil Corporation Press Release Dated February 1, 2022 Announcing Earnings For the Year Ended December 31, 2021. | Furnished herewith | ||||
Inline XBRL Instance Document – The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | Filed herewith | |||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document. | Filed herewith | ||||
Inline XBRL Taxonomy Extension Calculation Linkbase Document. | Filed herewith | |||||
| 101.DEF | ||||||
Inline XBRL Taxonomy Extension Definition Linkbase Document. | Filed herewith | |||||
| 101.LAB | ||||||
Inline XBRL Taxonomy Extension Label Linkbase Document. | Filed herewith | |||||
| 101.PRE | ||||||
Inline XBRL Taxonomy Extension Presentation Linkbase Document. | Filed herewith | |||||
| 104 | ||||||
Cover Page Interactive Data File – The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document. | Filed herewith | |||||
| * | The exhibits referred to in this column by specific designations and dates have heretofore been filed with or furnished to the Securities and Exchange Commission under such designations and are hereby incorporated by reference. |
| ** | In accordance with Item 601(b)(4)(iii)(A) of Regulation S-K, the instrument defining the debt of the Registrant and its subsidiary, described above, has been omitted but will be furnished to the Commission upon request. |
| *** | These exhibits represent a management contract or compensatory plan. |
| **** | This Note or Bond (each, an “Instrument”) is substantially identical in all material respects to other Instruments that are otherwise required to be filed as exhibits, except as to the registered payee of such Instrument, the identifying number of such Instrument, and the principal amount of such Instrument. In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed a copy of only one of such Instruments, with a schedule identifying the other Instruments omitted and setting forth the material details in which such Instruments differ from the Instrument that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any Instruments so omitted. |
| (P) | Paper exhibit. |
92
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| U NITIL CORPORATION | ||||||
| By | / S / THOMAS P. MEISSNER , JR . | |||||
Thomas P. Meissner, Jr. | ||||||
Chairman of the Board of Directors, Chief Executive Officer and President | ||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature | Capacity | Date | ||||
/ R .Thomas P. Meissner, Jr. | Principal Executive Officer; Director | February 1, 2022 | ||||
/ OBERT B. HEVERT Robert B. Hevert | Principal Financial Officer | February 1, 2022 | ||||
/ ANIEL J. HURSTAK Daniel J. Hurstak | Principal Accounting Officer | February 1, 2022 | ||||
/ ICHAEL B. GREEN Michael B. Green | Director | February 1, 2022 | ||||
/ BEN S. MOULTON Eben S. Moulton | Director | February 1, 2022 | ||||
/ DWARD F. GODFREY Edward F. Godfrey | Director | February 1, 2022 | ||||
/ INFIELD S. BROWN Winfield S. Brown | Director | February 1, 2022 | ||||
/ ISA CRUTCHFIELD Lisa Crutchfield | Director | February 1, 2022 | ||||
/ AVID A. WHITELEY David A. Whiteley | Director | February 1, 2022 | ||||
/ OSTER Suzanne Foster | Director | February 1, 2022 | ||||
/ USTINE VOGEL Justine Vogel | Director | February 1, 2022 | ||||
/ ARK H. COLLIN Mark H. Collin | Director | |||||
93