| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
2020
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Each Classeach class Name of Each Exchange on Which RegisteredCommon Stock, No Par Value
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of RegulationS-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form10-K or any amendment to thisForm 10-K. ☒
$663,233,171.
Item | Description | Page | ||||
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1. | 3 | |||||
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| 9 | ||||||
| 10 | ||||||
| 12 | ||||||
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1A. | 14 | |||||
1B. | 20 | |||||
2. | 20 | |||||
3. | 21 | |||||
4. | 22 | |||||
| PART II | ||||||
5. | 23 | |||||
6. | 26 | |||||
7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) | 27 | ||||
7A. | 42 | |||||
8. | 43 | |||||
9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 91 | ||||
9A. | 91 | |||||
9B. | 91 | |||||
| PART III | ||||||
10. | 92 | |||||
11. | 92 | |||||
12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 92 | ||||
13. | Certain Relationships and Related Transactions, and Director Independence | 92 | ||||
14. | 92 | |||||
| PART IV | ||||||
15. | 93 | |||||
| SIGNATURES | ||||||
| 99 | ||||||
Item | Description | Page | ||
PART I | ||||
1. | 3 | |||
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| 7 | ||||
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1A. | 8 | |||
1B. | 15 | |||
2. | 15 | |||
3. | 16 | |||
4. | 16 | |||
PART II | ||||
5. | 17 | |||
6. | 20 | |||
7. | 21 | |||
7A. | 37 | |||
8. | 38 | |||
9. | 86 | |||
9A. | 86 | |||
9B. | 86 | |||
PART III | ||||
10. | 87 | |||
11. | 87 | |||
12. | 87 | |||
13. | 87 | |||
14. | 87 | |||
PART IV | ||||
15. | 88 | |||
SIGNATURES | ||||
| 95 | ||||
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increased competition.
Item 1. |
and was incorporated under the laws of the State of New Hampshire in 1984. The following companies are wholly-owned subsidiaries of Unitil:
Organization NH - 1901 Electric Distribution Utility MA - 1852 Electric & Natural Gas Distribution Utility NH - 1979 Natural Gas Distribution Utility NH - 1955 Natural Gas Transmission Pipeline NH - 1984 Wholesale Electric Power Utility NH - 1984 Utility Service Company NH - 1986 Real Estate Management NH - 1993 Usource, Inc. and Usource, L.L.C. (collectively Usource)DE - 2000Energy Brokering Services
| Customers Served as of December 31, 2018 | ||||||||||||
| Residential | Commercial & Industrial (C&I) | Total | ||||||||||
Electric: | ||||||||||||
Unitil Energy | 64,934 | 11,127 | 76,061 | |||||||||
Fitchburg | 25,603 | 3,907 | 29,510 | |||||||||
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Total Electric | 90,537 | 15,034 | 105,571 | |||||||||
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Natural Gas: | ||||||||||||
Northern Utilities | 50,335 | 16,451 | 66,786 | |||||||||
Fitchburg | 14,269 | 1,704 | 15,973 | |||||||||
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Total Natural Gas | 64,604 | 18,155 | 82,759 | |||||||||
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Total Customers Served | 155,141 | 33,189 | 188,330 | |||||||||
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Customers Served as of December 31, 2020 | ||||||||||||
Residential | Commercial & Industrial (C&I) | Total | ||||||||||
Electric: | ||||||||||||
Unitil Energy | 65,955 | 11,249 | 77,204 | |||||||||
Fitchburg | 25,865 | 4,008 | 29,873 | |||||||||
Total Electric | 91,820 | 15,257 | 107,077 | |||||||||
Natural Gas: | ||||||||||||
Northern Utilities | 52,863 | 16,541 | 69,404 | |||||||||
Fitchburg | 14,462 | 1,708 | 16,170 | |||||||||
Total Natural Gas | 67,325 | 18,249 | 85,574 | |||||||||
Total Customers Served | 159,145 | 33,506 | 192,651 | |||||||||
formerly functioned as the full requirements wholesale power supply provider for Unitil Energy, but
The Company’s GAAP Gas Gross Margin was $92.8 million in 2020. The Company’s Gas Adjusted Gross Margin (a
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$6.5 million for 2018.in 2020. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and to third-party suppliers.
The Company’s GAAP Electric Gross Margin was $69.1 million in 2020. The Company’s Electric Adjusted Gross Margin (a
the northeastern United States. See additional discussion of the divestiture of Usource in “Divestiture of
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 3 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report.
Tax Cuts and Jobs Act of 2017
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 percent, 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, has issued procedural orders directing how the tax law changes are to be reflected in rates, including requiring that the companies provide certain filings and calculations. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC has opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State (described below). More recently, on November 15, 2018, the FERC issued a Notice of Proposed Rulemaking and a Policy Statement to address the TCJA’s effects on the Accumulated Deferred Income Taxes (ADIT) on transmission rates. Under the proposed rules all public utilities with transmission formula rates, including Fitchburg, would be required to: (1) include mechanisms to deduct any excess ADIT from or add any deficient ADIT to their rate bases; (2) include mechanisms in those rates that would raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (3) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. The Company believes that these matters are substantially resolved and will not have a material impact on its financial position, operating results, or cash flows.
In Maine, Northern Utilities’ Maine division recently completed a base rate case (described below). The Maine Public Utilities Commission’s (MPUC) final order in that docket incorporated the lower tax rates in the calculation of rates for the Company.
Similarly, in New Hampshire, Northern Utilities’ New Hampshire division recently completed a base rate case proceeding (described below). The New Hampshire Public Utilities Commission’s (NHPUC) final order in that docket approved a comprehensive settlement agreement among the Company, the Staff of the Public Utilities Commission and the Office of Consumer Advocate which included the effect of the tax changes in the calculation of the revenue requirement. With respect to Unitil Energy, on April 30, 2018 the NHPUC approved the Company’s annual step increase pursuant to the provisions of its last base rate case, which included adjustments to account for the TCJA’s income tax changes.
In Massachusetts, the Massachusetts Department of Public Utilities (MDPU) issued an order opening an investigation into the effect on rates of the decrease in the federal corporate income tax rate on the MDPU’s regulated utilities, and required each utility subject to its jurisdiction to submit proposals to address the effects of the TCJA and to reduce its rates as of January 1, 2018. The MDPU consolidated an earlier petition filed by the Attorney General requesting such an investigation into its order. On June 29, 2018, the MDPU issued an order accepting Fitchburg’s proposal to decrease the annual revenue requirement of both its gas and electric divisions by $0.8 million each. On December 21, 2018 the MDPU issued an order addressing the refund of excess ADIT in phase two of its investigation. Fitchburg was ordered to make a filing by January 4, 2019, for rates effective February 1, 2019, to refund $10.1 million for the electric division amortized over 15 years and $10.4 million for the gas division amortized over 14 years. The filing establishes a “Tax Act Credit Factor” for Fitchburg’s gas and electric divisions effective February 1, 2019 in accordance with the order. To the extent any of the regulatory liability above includes excess ADIT amounts specifically associated with reconciling mechanisms, Fitchburg shall return those amounts through the respective reconciling mechanism and adjust the regulatory liability amount accordingly. The MDPU approved this filing on January 16, 2019.
On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which accounted for the effects of the TCJA in its rates. The settlement was approved by FERC on June 27, 2018, and complies with and satisfies the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reduction under the TCJA.
Base Rate Activity
Unitil Energy—Base Rates—On April 20, 2017 the NHPUC approved a permanent increase of $4.1 million in electric base rates, and a three year rate plan with an additional rate step adjustment, effective May 1, 2017, of $0.9 million, followed by two rate step adjustments in May of 2018 and 2019 to recover the revenue requirements associated with annual capital expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s step adjustment filing. The filing incorporated the revenue requirement of $3.3 million for 2017 plant additions, a reduction of $2.2 million for the effect of the federal tax decrease pursuant to the TCJA, along with the termination of theone-year $1.4 million reconciliation adjustment which had recouped the difference between temporary rates and final rates. The net effect of the three adjustments resulted in a revenue decrease of $0.3 million.
Fitchburg—Base Rates—Electric—Fitchburg’s last base rate order from the MDPU, issued in April 2016, included the approval of an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. While a number of the capital cost recovery filings may remain pending fromyear-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. On June 28, 2018, Fitchburg filed its compliance report of capital investments for calendar year 2017. On November 1, 2018, Fitchburg filed its cumulative revenue requirement associated with the Company’s 2015, 2016 and 2017 capital expenditures and associated Capital Cost Adjustment Factors to become effective on January 1, 2019. On December 27, 2018, the Capital Cost Adjustment Factors were approved subject to further investigation and reconciliation. This matter remains pending.
Fitchburg—Electric Grid Modernization—On May 10, 2018, the MDPU issued an order approving a three year grid modernization investment plan for Fitchburg for the period 2018 through 2020 with a spending cap of $4.4 million. The order provides for a cost recovery mechanism for incremental capital investments and operation and maintenance (O&M) expenses. The electric distribution companies in Massachusetts jointly filed compliance filings in August 2018 including 1) revised proposed performance metrics designed to addresspre-authorized grid-facing investments, 2) a proposed evaluation plan for the three-year investment term, and 3) a model tariff for cost recovery including proposed protocol for identifying and tracking incremental O&M expenses. Approval of these filings is pending. The next three year investment plan is due July 1, 2020 for the period 2021 through 2023, and is required to include a five year strategic plan for 2021 – 2025.
Fitchburg—Solar Generation—On November 9, 2016, the MDPU approved Fitchburg’s petition to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts. Construction of the solar generating facility was completed and the facility began generating power on November 22, 2017. On April 2, 2018, Fitchburg submitted its first filing pursuant to its Solar Cost Adjustment tariff, by which the Company recovers its annual revenue requirement related to its investment in the solar generation facility. The filing sought a net amount of approximately $0.3 million for recovery effective June 1, 2018. The recovery of this amount in rates was approved by the MDPU on May 31, 2018, subject to further investigation and reconciliation. A final order is pending.
Fitchburg—Base Rates—Gas—Pursuant to the Company’s revenue decoupling adjustment clause tariff, as approved in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather and energy efficiency impacts to the Company’s revenues. The MDPU has consistently found that the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that they result in just and reasonable rates.
Fitchburg—Gas System Enhancement Program—Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain gas 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 31; and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably
and prudently incurred. While a number of the filings under the GSEP tariff may remain pending fromyear-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. Under this tariff, a revenue increase of $0.9 million went into effect on May 1, 2018, subject to the annual cap and reconciliation. On October 31, 2018, the MDPU approved the Company’s request for a waiver of the annual cap in order to recover its reconciliation adjustment of $0.4 million effective November 1, 2018 associated with its actual 2017 revenue requirement.
Northern Utilities—Base Rates—Maine—On February 28, 2018, the MPUC issued its Final Order (Order) in Northern Utilities’ pending base rate case. The Order provided for an annual revenue increase of $2.1 million before a reduction of $2.2 million to incorporate the effect of the lower federal income tax rate under the TCJA. The MPUC Order approved a return on equity of 9.5 percent and a capital structure reflecting 50 percent equity and 50 percent long-term debt. The Order also provides for a reduction in annual depreciation expense, reducing the Company’s annual operating costs by approximately $0.5 million, and addressed a number of other issues, including a change to therm billing, increases in other delivery charges, and cost recovery under the Company’s Targeted Area Build-out (TAB) program and Targeted Infrastructure Replacement Adjustment (TIRA) mechanism. The new rates and other changes became effective on March 1, 2018.
Northern Utilities—Targeted Infrastructure Replacement Adjustment—Maine—The settlement in Northern Utilities’ Maine division’s 2013 rate case allowed the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP). The TIRA had an initial term of four years and covered targeted capital expenditures in 2013 through 2016. In its Order in the current base rate case (see above), the MPUC approved an extension of the TIRA mechanism, with adjustment, for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. On May 7, 2018, the MPUC approved the Company’s request to increase its annual base rates by 2.4%, or $1.1 million, to recover the revenue requirements for 2017 eligible facilities.
Northern Utilities—Targeted AreaBuild-out Program—Maine—In December 2015, the MPUC approved a TAB program and associated rate surcharge mechanism. This program is designed to allow the economic extension of natural gas mains to new, targeted service areas in Maine. It allows customers in the targeted area the ability to pay a rate surcharge, instead of a large upfront payment or capital contribution to connect to the natural gas delivery system. The initial pilot of the TAB program was approved for the City of Saco, and is being built out over a period of three years, with the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco area. A second TAB program was approved for the Town of Sanford, and has the potential to add 2,000 new customers and approximately $2 million in annual distribution revenue in the Sanford area. In its base rate case Order (described above), the MPUC approved the inclusion of Saco TAB investments in rate base along with a cost recovery incentive mechanism for future TAB investments.
Northern Utilities—Base Rates—New Hampshire—On May 2, 2018, the NHPUC approved a settlement agreement providing for an annual revenue increase of $2.6 million, a reduction of annual revenue of $1.7 million to reflect the effect of the TCJA, and a step increase of $2.3 million to recover post-test year capital investments, all effective May 1, 2018 (with the revenue increase of $2.6 million reconciling to the date of temporary rates of August 1, 2017 and the revenue decrease for TCJA reconciling to January 1, 2018), for a net increase of approximately $3.2 million. Under the agreement, the Company may file for a second step increase for effect May 1, 2019 to recover eligible capital investments in 2018, up to a revenue requirement cap of $2.2 million. If the Company chooses the option to implement the second step increase, the next distribution base rate case will be based on an historic test year of no earlier than twelve months ending December 31, 2020.
Northern Utilities—Franchise Extensions—New Hampshire—On October 3, 2018, the NHPUC granted Northern Utilities authority to expand its natural gas service territory in the Towns of Kingston, New Hampshire and Atkinson, New Hampshire (where the Company already had a limited franchise) to serve new industrial, commercial and residential customers. Northern Utilities has also petitioned the NHPUC to extend its franchise into the Town of Epping, New Hampshire, where new commercial and residential developments present the Company with opportunities for growth. The franchise petition for service to the Town of Epping remains pending.
Granite State—Base Rates—On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which provided for no change in rates, and accounted for the effects of a capital step adjustment offset by the effect of the TCJA. The settlement was approved by FERC on June 27, 2018, and complies with the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reductions under the TCJA. The settlement also provides that Granite State may not file a general (Section 4) rate case prior to April 30, 2019.
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 purchases and manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.
Northern Utilities’ C&I customers are entitled
Fitchburg’s residential and C&I business customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many large and some medium C&I customers purchase their gas supply
from third-party suppliers while most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. As of December 2018, 85% of Unitil’s largest Massachusetts gas customers, representing 26% of Unitil’s Massachusetts gas therm sales, are purchasing gas supply from third-party suppliers. The approved costs associatedexcellence begins with natural gas supplied to customers 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 Consolidated Statements of Earnings.
Regulated Natural Gas Supply
Northern Utilities purchases a majority of its natural gas from U.S. domestic and Canadian 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 its 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 case of liquefied natural gas (LNG), via over the road trucking of supplies to storage facilities within Northern Utilities’ service territory.
Northern Utilities has available under firm contract 115,000 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 gas transportation and delivery 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 14,057 MMbtu per day of year-round transportation and 0.33 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 supply of pipeline natural gas.
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 2018, 77% of Unitil’s largest New Hampshire customers, representing 24% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales and 81% of Unitil’s largest Massachusetts customers, representing 32% of Unitil’s Massachusetts electric kWh sales, are purchasing 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%. Buoyed by the municipal aggregations, 31% of Unitil’s residential customers in Massachusetts purchase their electricity from a third-party supplier as of December 2018.
In New Hampshire, the percentage of residential customers purchasing electricity from a third-party supplier stands at 10%, down slightly relative to prior years when 13% of Unitil’s residential customers in New Hampshire purchased their supply from third-party suppliers. Most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs.
Regulated Electric Power Supply
In order 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.
Unitil 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 dictates 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’sISO-NE settlement account where Fitchburg procures electric supply throughISO-NE’s real-time market.
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 theISO-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 support payments associated therewith. 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.
Long-Term Renewable Contracts
Fitchburg has entered into long-term renewable contracts for the purchase of clean energy and/or renewable energy certificates (RECs) pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (“Green Communities Act”, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (“Energy Diversity Act”, 2016). The generating facilities associated with four of these contracts have been constructed and are now operating. Since 2017, the Company has participated in two major statewide procurements which resulted in contracts for imported hydroelectric power and associated transmission and for offshore wind generation. The contracts were filed with MDPU in 2018 and approvals remain pending.
Additional long-term clean energy contracts are expected in compliance with the Energy Diversity Act and An Act to Promote a Clean Energy Future (2018). Fitchburg recovers the costs associated withlong-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.
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, 2018, 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’s 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—Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites, which were operated from themid-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 to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of all sites, though on site monitoring continues and it is possible that future activities may be required.
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 succeedingfive-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—Fitchburg has worked with the Massachusetts Department of Environmental Protection to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring will continue and it is possible that future activities may be required.
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.
Also, seeEnvironmental Matters in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on Environmental Matters.
employees. As of December 31, 2018,2020, the Company and its subsidiaries had 520512 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.
Employees Covered | CBA Expiration | |||||||
Fitchburg | 05/31/ | |||||||
Northern Utilities NH Division | 06/ | |||||||
Northern Utilities ME Division | 03/31/2021 | |||||||
Granite State | 4 | 03/31/2021 | ||||||
Unitil Energy | 05/31/2023 | |||||||
Unitil Service | 5 | 05/31/2023 | ||||||
College Station, TX 77842-3170
505005
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Item 1A. |
Risks Relating
The Company is subject to comprehensive regulation, which could adversely impact 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 and results of operations.
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 ratesor that the Company can charge customers,currently believes are immaterial may also impair business operations and financial results. If any of the following risks actually occur, 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 impact on itsbusiness, financial condition and results of operations from the regulatory activities of any of these regulatory authorities. Changes in regulations, the imposition of additional regulations 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 and results of operations.
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, then the Company’s financial condition and results or operations 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 and results of operations.
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 and results of operations.
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 and results or operations. 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, then our revenues would be reduced and our future growth prospects would be limited. In addition, a period of prolonged economic weakness could impact 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/or cash flows.
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, 2018, the Company had approximately $82.8 million in short-term debt outstanding under its revolving credit facility. Additionally, if the lending counterparties under the Company’s current credit facility are unwilling or unable to meet their funding obligations, then the Company may be unable to, or limited in its ability to, incur short-term debt under its credit facility. This could hinder or prevent the Company from meeting its current and future capital needs, which could correspondingly adversely affect the Company’s financial condition and results or operations.
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 and results of operations. 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 and results of operations.
In addition, 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 and results of operations.
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” above. 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 suchtax-related developments which could have a negative impact on the financial results. Additionally, 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 othertax-related assumptions may cause actual financial results to deviate from previous estimates. (See Note 9 to the Consolidated Financial Statements).
Declines in the valuation of capital markets 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, then the Company’s financial condition and results of operations could be adversely affected.
The amount of cash contributions In such case, 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 the valuation of the capital markets 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 and results of operations if the Company is unable to recover such costs in rates or if such recovery is significantly delayed. Please see the section entitledCritical Accounting Policies—Retirement Benefit Obligations in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 10 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements for a more detailed discussion of the Company’ pension obligations.
The termstrading price 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 and results of operations. See the sections entitledLiquidity, Commitments and Capital Requirements in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements for a more detailed discussion of these restrictions.
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 and results of operations. 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 and results of operations. 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.
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 dividendscould decline and other payments received from its subsidiariesinvestors could lose all or part of their investment. The risk factors below are categorized by operational, regulatory, financial 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 has to satisfy its debt obligations and comply with any statutory or contractual limitations.
As of January 30, 2019, the Company’s current effective annualized dividend is $1.48 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 above, and the Company cannot assure the amount of dividends, if any, that may be paid in the future.
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 and results of operations.
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 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.
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 electric or natural gas to its customers for an extended period, which could affect customer satisfaction and adversely affect the Company’s financial condition and results of operations. If customers, legislators, or regulators develop a negative opinion of the Company, this could result in increased regulatory oversight and could affect the returns on equity that the Company is allowed to earn. Also, if the Company is unable to recover a significant amount of costs associated with catastrophic events in its rates, or if the Company’s recovery of such costs in its rates is significantly delayed, then the Company’s financial condition and results or operations may be adversely affected.
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.
operations, and cash flows.
The financial performance of the Company’snon-regulated energy brokering business, Usource, may be adversely affected if suppliers and/or customers default in their performance under multi-year energy brokering contracts or by competition from other energy brokers.
Usource provides energy brokering and consulting services to a national client base of large commercial and industrial customers. Revenues from this business are primarily derived from brokering fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts. Usource’s customers and/or the suppliers providing energy to Usource’s customers may default in their performance under multi-year energy brokering contracts, which could adversely affect the Company’s financial condition and results of operations. In addition, Usource may lose market share to other energy brokers which could adversely affect the Company’s financial condition and results of operations.
Item 1B. |
Item 2. |
| Northern Utilities | Fitchburg | Granite State | Total | |||||||||||||||||
Description | NH | ME | ||||||||||||||||||
Underground Natural Gas Mains—Miles | 544 | 589 | 274 | — | 1,407 | |||||||||||||||
Natural Gas Transmission Pipeline—Miles | — | — | — | 86 | 86 | |||||||||||||||
Service Pipes | 23,642 | 22,481 | 11,074 | — | 57,197 | |||||||||||||||
Northern Utilities | Fitchburg | Granite State | Total | |||||||||||||||||
Description | NH | ME | ||||||||||||||||||
Underground Natural Gas Mains—Miles | 568 | 604 | 274 | — | 1,446 | |||||||||||||||
Natural Gas Transmission Pipeline—Miles | — | — | — | 86 | 86 | |||||||||||||||
Service Pipes | 24,240 | 23,216 | 11,193 | — | 58,649 | |||||||||||||||
Description | Unitil Energy | Fitchburg | Total | |||||||||
Primary Transmission and Distribution Pole Miles—Overhead | 1,278 | 445 | 1,723 | |||||||||
Conduit Distribution Bank Miles—Underground | 231 | 67 | 298 | |||||||||
Transmission and Distribution Substations | 34 | 16 | 50 | |||||||||
Transformer Capacity of Transmission and Distribution Substations (MVA) | 549.5 | 608.2 | 1,157.7 | |||||||||
Description | Unitil Energy | Fitchburg | Total | |||||||||
Primary Transmission and Distribution Pole Miles—Overhead | 1,293 | 454 | 1,747 | |||||||||
Conduit Distribution Bank Miles—Underground | 235 | 68 | 303 | |||||||||
Transmission and Distribution Substations | 34 | 16 | 50 | |||||||||
Transformer Capacity of Transmission and Distribution Substations (MVA) | 467.6 | 433.2 | 900.8 | |||||||||
FG&E’s
Item 3. |
In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court, (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint sought an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The Massachusetts Supreme Judicial Court issued an order denying class certification status in July 2016, though the plaintiffs’ individual claims remained pending. The Company resolved this matter by settlement in the fall of 2018 and there was no material impact on the Company’s financial position, operating results or cash flows.
Item 4. |
Item 5. |
|
Our
Dividends per Common Share | 2018 | 2017 | ||||||
1st Quarter | $ | 0.365 | $ | 0.360 | ||||
2nd Quarter | 0.365 | 0.360 | ||||||
3rd Quarter | 0.365 | 0.360 | ||||||
4th Quarter | 0.365 | 0.360 | ||||||
|
|
|
| |||||
Total for Year | $ | 1.46 | $ | 1.44 | ||||
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|
|
| |||||
Dividends per Common Share | 2020 | 2019 | ||||||
1st Quarter | $ | 0.375 | $ | 0.370 | ||||
2nd Quarter | 0.375 | 0.370 | ||||||
3rd Quarter | 0.375 | 0.370 | ||||||
4th Quarter | 0.375 | 0.370 | ||||||
Total for Year | $ | 1.50 | $ | 1.48 | ||||
.
following table.
(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 not approved by security holders | — | — | — | |||||||||
| ||||||||||||
Total | — | — | 213,817 | |||||||||
| (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 |
2015.
| (1) | The graph above assumes $100 invested on December 31, |
2020.
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 | ||||||||||||
10/1/18 – 10/31/18 | — | — | — | $ | 75,366 | |||||||||||
11/1/18 – 11/30/18 | — | — | — | $ | 75,366 | |||||||||||
12/1/18 – 12/31/18 | 319 | $ | 50.330 | 319 | $ | 59,311 | ||||||||||
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| |||||||||||||
Total | 319 | $ | 50.330 | 319 | ||||||||||||
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|
| |||||||||||||
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 | ||||||||||||
10/1/20 – 10/31/20 | 13,194 | $ | 39.048 | 13,194 | $ | 808 | ||||||||||
11/1/20 – 11/30/20 | — | — | — | $ | 808 | |||||||||||
12/1/20 – 12/31/20 | — | — | — | $ | 808 | |||||||||||
Total | 13,194 | $ | 39.048 | 13,194 | ||||||||||||
Item 6. |
| For the Years Ended December 31, (all data in millions except customers served, shares, % and per share data) | ||||||||||||||||||||
| 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||||
Customers Served(Year-End): | ||||||||||||||||||||
Electric: | ||||||||||||||||||||
Residential | 90,537 | 90,009 | 89,400 | 88,444 | 88,012 | |||||||||||||||
Commercial & Industrial | 15,034 | 14,969 | 14,872 | 14,825 | 14,740 | |||||||||||||||
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| |||||||||||
Total Electric | 105,571 | 104,978 | 104,272 | 103,269 | 102,752 | |||||||||||||||
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Natural Gas: | ||||||||||||||||||||
Residential | 64,604 | 63,441 | 62,284 | 61,270 | 60,236 | |||||||||||||||
Commercial & Industrial | 18,155 | 17,868 | 17,654 | 17,479 | 17,624 | |||||||||||||||
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|
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| |||||||||||
Total Natural Gas | 82,759 | 81,309 | 79,938 | 78,749 | 77,860 | |||||||||||||||
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| |||||||||||
Total Customers Served | 188,330 | 186,287 | 184,210 | 182,018 | 180,612 | |||||||||||||||
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| |||||||||||
Electric and Gas Sales: | ||||||||||||||||||||
Electric Distribution Sales (kWh) | 1,675.8 | 1,624.1 | 1,628.8 | 1,667.7 | 1,679.0 | |||||||||||||||
Firm Natural Gas Distribution Sales (Therms) | 231.1 | 213.8 | 205.7 | 219.4 | 216.2 | |||||||||||||||
Consolidated Statements of Earnings: | ||||||||||||||||||||
Operating Revenue | $ | 444.1 | $ | 406.2 | $ | 383.4 | $ | 426.8 | $ | 425.8 | ||||||||||
Operating Income | 71.2 | 75.4 | 70.2 | 68.0 | 63.5 | |||||||||||||||
Interest Expense, net | 24.0 | 23.1 | 22.5 | 21.9 | 20.9 | |||||||||||||||
Other Expense (Income), net | 5.8 | 5.8 | 5.2 | 4.4 | 3.9 | |||||||||||||||
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| |||||||||||
Income Before Income Taxes | 41.4 | 46.5 | 42.5 | 41.7 | 38.7 | |||||||||||||||
Income Taxes | 8.4 | 17.5 | 15.4 | 15.4 | 14.0 | |||||||||||||||
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| |||||||||||
Net Income | 33.0 | 29.0 | 27.1 | 26.3 | 24.7 | |||||||||||||||
Dividends on Preferred Stock | — | — | — | — | — | |||||||||||||||
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| |||||||||||
Earnings Applicable to Common Shareholders | $ | 33.0 | $ | 29.0 | $ | 27.1 | $ | 26.3 | $ | 24.7 | ||||||||||
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|
|
| |||||||||||
Earnings Per Average Share: | $ | 2.23 | $ | 2.06 | $ | 1.94 | $ | 1.89 | $ | 1.79 | ||||||||||
Common Stock—(Diluted Weighted Average Outstanding, 000’s) | 14,829 | 14,102 | 13,996 | 13,920 | 13,847 | |||||||||||||||
Dividends Declared Per Share | $ | 1.46 | $ | 1.44 | $ | 1.42 | $ | 1.40 | $ | 1.38 | ||||||||||
Book Value Per Share(Year-End) | $ | 23.60 | $ | 22.72 | $ | 20.82 | $ | 20.20 | $ | 19.62 | ||||||||||
Balance Sheet Data (as of December 31,): | ||||||||||||||||||||
Utility Plant | $ | 1,369.3 | $ | 1,279.2 | $ | 1,173.4 | $ | 1,080.6 | $ | 988.8 | ||||||||||
Capital Lease Obligations(1) | $ | 5.8 | $ | 8.8 | $ | 11.3 | $ | 14.1 | $ | 8.0 | ||||||||||
Total Assets | $ | 1,298.3 | $ | 1,241.9 | $ | 1,128.2 | $ | 1,038.8 | $ | 997.0 | ||||||||||
Capitalization: | ||||||||||||||||||||
Common Stock Equity | $ | 351.1 | $ | 336.6 | $ | 292.9 | $ | 282.6 | $ | 273.1 | ||||||||||
Preferred Stock | 0.2 | 0.2 | 0.2 | 0.2 | 0.2 | |||||||||||||||
Long-Term Debt, less current portion | 387.4 | 376.3 | 316.8 | 305.5 | 326.0 | |||||||||||||||
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| |||||||||||
Total Capitalization | $ | 738.7 | $ | 713.1 | $ | 609.9 | $ | 588.3 | $ | 599.3 | ||||||||||
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| |||||||||||
Current Portion of Long-Term Debt | $ | 18.4 | $ | 29.8 | $ | 16.8 | $ | 17.1 | $ | 3.7 | ||||||||||
Short-Term Debt | $ | 82.8 | $ | 38.3 | $ | 81.9 | $ | 42.0 | $ | 29.3 | ||||||||||
Capital Structure Ratios (as of December 31,): | ||||||||||||||||||||
Common Stock Equity | 48 | % | 47 | % | 48 | % | 48 | % | 46 | % | ||||||||||
Long-Term Debt, less current portion | 52 | % | 53 | % | 52 | % | 52 | % | 54 | % | ||||||||||
For the Years Ended December 31, (all data in millions except customers served, shares, % and per share data) | ||||||||||||||||||||
2020 | 2019 (2) | 2018 | 2017 | 2016 | ||||||||||||||||
Customers Served (Year-End): | ||||||||||||||||||||
Electric: | ||||||||||||||||||||
Residential | 91,820 | 90,983 | 90,537 | 90,009 | 89,400 | |||||||||||||||
Commercial & Industrial | 15,257 | 15,146 | 15,034 | 14,969 | 14,872 | |||||||||||||||
Total Electric | 107,077 | 106,129 | 105,571 | 104,978 | 104,272 | |||||||||||||||
Natural Gas: | ||||||||||||||||||||
Residential | 67,325 | 65,836 | 64,604 | 63,441 | 62,284 | |||||||||||||||
Commercial & Industrial | 18,249 | 18,075 | 18,155 | 17,868 | 17,654 | |||||||||||||||
Total Natural Gas | 85,574 | 83,911 | 82,759 | 81,309 | 79,938 | |||||||||||||||
Total Customers Served | 192,651 | 190,040 | 188,330 | 186,287 | 184,210 | |||||||||||||||
Electric and Gas Sales: | ||||||||||||||||||||
Electric Distribution Sales (kWh) | 1,595.9 | 1,595.7 | 1,675.8 | 1,624.1 | 1,628.8 | |||||||||||||||
Firm Natural Gas Distribution Sales (Therms) | 214.8 | 232.1 | 231.1 | 213.8 | 205.7 | |||||||||||||||
Consolidated Statements of Earnings: | ||||||||||||||||||||
Operating Revenue | $ | 418.6 | $ | 438.2 | $ | 444.1 | $ | 406.2 | $ | 383.4 | ||||||||||
Operating Income | 71.4 | 73.1 | 71.2 | 75.4 | 70.2 | |||||||||||||||
Interest Expense, Net | 23.8 | 23.7 | 24.0 | 23.1 | 22.5 | |||||||||||||||
Other Expense (Income), Net | 5.2 | (8.6 | ) | 5.8 | 5.8 | 5.2 | ||||||||||||||
Income Before Income Taxes | 42.4 | 58.0 | 41.4 | 46.5 | 42.5 | |||||||||||||||
Income Taxes | 10.2 | 13.8 | 8.4 | 17.5 | 15.4 | |||||||||||||||
Net Income | 32.2 | 44.2 | 33.0 | 29.0 | 27.1 | |||||||||||||||
Dividends on Preferred Stock | — | — | — | — | — | |||||||||||||||
Earnings Applicable to Common Shareholders | $ | 32.2 | $ | 44.2 | $ | 33.0 | $ | 29.0 | $ | 27.1 | ||||||||||
Earnings Per Average Share: | $ | 2.15 | $ | 2.97 | $ | 2.23 | $ | 2.06 | $ | 1.94 | ||||||||||
Common Stock—(Diluted Weighted Average Outstanding, 000’s) | 15,000 | 14,900 | 14,829 | 14,102 | 13,996 | |||||||||||||||
Dividends Declared Per Share | $ | 1.50 | $ | 1.48 | $ | 1.46 | $ | 1.44 | $ | 1.42 | ||||||||||
Book Value Per Share (Year-End) | $ | 25.91 | $ | 25.22 | $ | 23.60 | $ | 22.72 | $ | 20.82 | ||||||||||
Balance Sheet Data (as of December 31,): | ||||||||||||||||||||
Net Utility Plant | $ | 1,193.2 | $ | 1,111.5 | $ | 1,036.8 | $ | 971.5 | $ | 883.4 | ||||||||||
Lease Obligations (1) | $ | 5.6 | $ | 4.5 | $ | 5.8 | $ | 8.8 | $ | 11.3 | ||||||||||
Total Assets | $ | 1,477.9 | $ | 1,370.8 | $ | 1,298.3 | $ | 1,241.9 | $ | 1,128.2 | ||||||||||
Capitalization: | ||||||||||||||||||||
Common Stock Equity | $ | 389.0 | $ | 376.6 | $ | 351.1 | $ | 336.6 | $ | 292.9 | ||||||||||
Preferred Stock | 0.2 | 0.2 | 0.2 | 0.2 | 0.2 | |||||||||||||||
Long-Term Debt, less current portion | 523.1 | 437.5 | 387.4 | 376.3 | 316.8 | |||||||||||||||
Total Capitalization | $ | 912.3 | $ | 814.3 | $ | 738.7 | $ | 713.1 | $ | 609.9 | ||||||||||
Current Portion of Long-Term Debt | $ | 8.5 | $ | 19.5 | $ | 18.4 | $ | 29.8 | $ | 16.8 | ||||||||||
Short-Term Debt | $ | 54.7 | $ | 58.6 | $ | 82.8 | $ | 38.3 | $ | 81.9 | ||||||||||
Capital Structure Ratios (as of December 31,): | ||||||||||||||||||||
Common Stock Equity | 43 | % | 46 | % | 48 | % | 47 | % | 48 | % | ||||||||||
Long-Term Debt, less current portion | 57 | % | 54 | % | 52 | % | 53 | % | 52 | % | ||||||||||
| (1) | Includes amounts due within one year. Amounts for 2020 and 2019 include amounts of $5.2 million and $4.0 million, respectively, of operating lease obligations. See the “Leases” section of Note 5 to the accompanying Consolidated Financial Statements. |
| (2) | See “Divestiture of Non-Regulated Business Subsidiary” in Note 1 to the Consolidated Financial Statements. |
188,300192,700 customers throughout its service territory in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities: i)
| ii) | Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts; and |
| iii) | Northern Utilities, which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland and the Lewiston-Auburn area. |
territories. The distribution utilities are local “pipes and wires” operating companies.
The distribution utilities are local “pipes and wires” operating companies, and
revenue, is a meaningful measure to inform investors of the Company’s profitability from gas and electric sales in the period.
Twelve Months Ended December 31, 2020 ($ millions) | ||||||||||||||||
Gas | Electric | Non-Regulated and Other | Total | |||||||||||||
Total Operating Revenue | $ | 191.4 | $ | 227.2 | $ | — | $ | 418.6 | ||||||||
Less: Cost of Sales | (68.8 | ) | (134.3 | ) | — | (203.1 | ) | |||||||||
Less: Depreciation and Amortization | (29.8 | ) | (23.8 | ) | (0.9 | ) | (54.5 | ) | ||||||||
GAAP Gross Margin | 92.8 | 69.1 | (0.9 | ) | 161.0 | |||||||||||
Depreciation and Amortization | 29.8 | 23.8 | 0.9 | 54.5 | ||||||||||||
Adjusted Gross Margin | $ | 122.6 | $ | 92.9 | $ | — | $ | 215.5 | ||||||||
Twelve Months Ended December 31, 2019 ($ millions) | ||||||||||||||||
Gas | Electric | Non-Regulated and Other | Total | |||||||||||||
Total Operating Revenue | $ | 203.4 | $ | 233.9 | $ | 0.9 | $ | 438.2 | ||||||||
Less: Cost of Sales | (81.2 | ) | (142.0 | ) | — | (223.2 | ) | |||||||||
Less: Depreciation and Amortization | (28.5 | ) | (22.6 | ) | (0.9 | ) | (52.0 | ) | ||||||||
GAAP Gross Margin | 93.7 | 69.3 | — | 163.0 | ||||||||||||
Depreciation and Amortization | 28.5 | 22.6 | 0.9 | 52.0 | ||||||||||||
Adjusted Gross Margin | $ | 122.2 | $ | 91.9 | $ | 0.9 | $ | 215.0 | ||||||||
Twelve Months Ended December 31, 2018 ($ millions) | ||||||||||||||||
Gas | Electric | Non-Regulated and Other | Total | |||||||||||||
Total Operating Revenue | $ | 216.1 | $ | 223.3 | $ | 4.7 | $ | 444.1 | ||||||||
Less: Cost of Sales | (99.2 | ) | (131.4 | ) | — | (230.6 | ) | |||||||||
Less: Depreciation and Amortization | (24.9 | ) | (23.1 | ) | (2.4 | ) | (50.4 | ) | ||||||||
GAAP Gross Margin | 92.0 | 68.8 | 2.3 | 163.1 | ||||||||||||
Depreciation and Amortization | 24.9 | 23.1 | 2.4 | 50.4 | ||||||||||||
Adjusted Gross Margin | $ | 116.9 | $ | 91.9 | $ | 4.7 | $ | 213.5 | ||||||||
2018
Natural gas sales margin was $116.9 million in 2018, an increase of $7.2$0.4 million compared to 2017. Gas sales margin in 20182019. The increase was positively affecteddriven by higher natural gas distribution rates of $7.1$5.1 million which was partially offset by the reduction in rates of $3.7 million due to the lower corporate income tax rate of 21% under the TCJA. Gas margin in 2018 reflects the positive effect of colder winter weather and customer growth onof $1.8 million, largely offset by unfavorable effects of $4.4 million from lower sales volume of $3.8 million.
Natural gas
Electric These positive effects on 2020 electric kWh sales margin was $91.9 million in 2018, a decrease of $0.3 million compared to 2017. Electric sales margin in 2018 was positively affected by higher electric distribution rates of $2.9 million,were partially offset by the reductionwarmer winter weather in rates2020 which adversely affected the usage of $2.6 millionelectricity for heating purposes. The decrease in 2018 duesales to C&I customers reflects lower usage as a result of the lower corporate income tax rate of 21% undereconomic slowdown caused by the TCJA. Electric sales margincoronavirus pandemic, and the warmer winter weather in the current period was also positively affected by warmer-than-average summer temperatures and customer growth of $0.8 million. These positive impacts on electric sales margin were2020, partially offset by the absence in the current period of aone-year $1.4 million temporary rate reconciliation adjustment recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.
Electric kilowatt-hour (kWh) sales increased 3.2% in 2018 compared to 2017 reflecting customer growth and warmer-than-average summer temperatures in 2018.growth. Based on weather data collected in the Company’s electric service areas, there were 42.2%37.9% more Cooling Degree Days (CDD) in 20182020, on average, compared to 2017. As of December 31, 2018, the number of electric customers served has increased by 593 over the last year.
O&M2019.
reflect lower employee benefit costs.
Taxes Other Than Income Taxes increased $1.3 million in 2018 compared to 2017, primarily reflecting higher local property tax rates on higher levels of utility plant in service and higher amortization of software.
taxes in 2020 reflecting the recognition of $0.6 million of payroll tax credits associated with the CARES Act in 2020.
debt, largely offset by lower rates on short-term debt and lower interest expense on regulatory liabilities.
expense of $5.2 million in 2020, a net change of $13.8 million. This change primarily reflects a
period.
2017
A more detailed discussion of the Company’s 2018 and 2017 results of operations and ayear-to-year comparison of changes in financial position are presented below.
Therm Sales (millions) | Change | |||||||||||||||||||||||||||
| 2018 vs. 2017 | 2017 vs. 2016 | |||||||||||||||||||||||||||
| 2018 | 2017 | 2016 | Therms | % | Therms | % | ||||||||||||||||||||||
Residential | 48.7 | 43.4 | 40.6 | 5.3 | 12.2 | % | 2.8 | 6.9 | % | |||||||||||||||||||
Commercial & Industrial | 182.4 | 170.4 | 165.1 | 12.0 | 7.0 | % | 5.3 | 3.2 | % | |||||||||||||||||||
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Total Therm Sales | 231.1 | 213.8 | 205.7 | 17.3 | 8.1 | % | 8.1 | 3.9 | % | |||||||||||||||||||
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Therm Sales (millions) | Change | |||||||||||||||||||||||||||
2020 vs. 2019 | 2019 vs. 2018 | |||||||||||||||||||||||||||
2020 | 2019 | 2018 | Therms | % | Therms | % | ||||||||||||||||||||||
Residential | 44.7 | 48.0 | 48.7 | (3.3 | ) | (6.9 | %) | (0.7 | ) | (1.4 | %) | |||||||||||||||||
Commercial & Industrial | 170.1 | 184.1 | 182.4 | (14.0 | ) | (7.6 | %) | 1.7 | 0.9 | % | ||||||||||||||||||
Total Therm Sales | 214.8 | 232.1 | 231.1 | (17.3 | ) | (7.5 | %) | 1.0 | 0.4 | % | ||||||||||||||||||
Gas Operating Revenues and Sales Margin (millions) | ||||||||||||||||||||||||||||
| Change | ||||||||||||||||||||||||||||
| 2018 vs. 2017 | 2017 vs. 2016 | |||||||||||||||||||||||||||
| 2018 | 2017 | 2016 | $ | % | $ | % | ||||||||||||||||||||||
Gas Operating Revenue: | ||||||||||||||||||||||||||||
Residential | $ | 86.0 | $ | 77.3 | $ | 71.0 | $ | 8.7 | 11.3 | % | $ | 6.3 | 8.9 | % | ||||||||||||||
Commercial & Industrial | 130.1 | 116.7 | 110.2 | 13.4 | 11.5 | % | 6.5 | 5.9 | % | |||||||||||||||||||
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Total Gas Operating Revenue | $ | 216.1 | $ | 194.0 | $ | 181.2 | $ | 22.1 | 11.4 | % | $ | 12.8 | 7.1 | % | ||||||||||||||
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Cost of Gas Sales | $ | 99.2 | $ | 84.3 | $ | 77.6 | $ | 14.9 | 17.7 | % | $ | 6.7 | 8.6 | % | ||||||||||||||
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Gas Sales Margin | $ | 116.9 | $ | 109.7 | $ | 103.6 | $ | 7.2 | 6.6 | % | $ | 6.1 | 5.9 | % | ||||||||||||||
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The Company analyzes operating results using
Gas Operating Revenues and Gas Adjusted Gross Margin (millions) | ||||||||||||||||||||||||||||
Change | ||||||||||||||||||||||||||||
2020 vs. 2019 | 2019 vs. 2018 | |||||||||||||||||||||||||||
2020 | 2019 | 2018 | $ | % | $ | % | ||||||||||||||||||||||
Gas Operating Revenue: | ||||||||||||||||||||||||||||
Residential | $ | 78.0 | $ | 81.2 | $ | 86.0 | $ | (3.2 | ) | (3.9 | %) | $ | (4.8 | ) | (5.6%) | |||||||||||||
Commercial & Industrial | 113.4 | 122.2 | 130.1 | (8.8 | ) | (7.2 | %) | (7.9 | ) | (6.1%) | ||||||||||||||||||
Total Gas Operating Revenue | $ | 191.4 | $ | 203.4 | $ | 216.1 | $ | (12.0 | ) | (5.9 | %) | $ | (12.7 | ) | (5.9%) | |||||||||||||
Cost of Gas Sales | $ | 68.8 | $ | 81.2 | $ | 99.2 | $ | (12.4 | ) | (15.3 | %) | $ | (18.0 | ) | (18.1%) | |||||||||||||
�� | ||||||||||||||||||||||||||||
Gas Adjusted Gross Margin | $ | 122.6 | $ | 122.2 | $ | 116.9 | $ | 0.4 | 0.3 | % | $ | 5.3 | 4.5% | |||||||||||||||
Natural gas sales margin
utility, the Company recognized concurrentnon-recurring adjustments to increase both Gas Operating Revenues and O&M expenses by $1.2 million in the second quarter of 2018 to reconcile permanent rates and deferred costs to the temporary rates which were effective July 1, 2017. Gas margin in 2018 reflects the positive effect of colder winter weather and customer growth on sales volume of $3.8 million.
Natural gascustomers, and lower sales marginvolumes.
a $1.2 million adjustment recognized in the second quarter of 2018 to increase gas revenue and operating expenses in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility.
customers and the adjustment recognized in the second quarter of 2018, discussed above, partially offset by higher gas sales volumes and higher rates.
kWh Sales (millions) | Change | |||||||||||||||||||||||||||
| 2018 vs. 2017 | 2017 vs. 2016 | |||||||||||||||||||||||||||
| 2018 | 2017 | 2016 | kWh | % | kWh | % | ||||||||||||||||||||||
Residential | 685.5 | 649.4 | 651.3 | 36.1 | 5.6 | % | (1.9 | ) | (0.3 | %) | ||||||||||||||||||
Commercial & Industrial | 990.3 | 974.7 | 977.5 | 15.6 | 1.6 | % | (2.8 | ) | (0.3 | %) | ||||||||||||||||||
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Total kWh Sales | 1,675.8 | 1,624.1 | 1,628.8 | 51.7 | 3.2 | % | (4.7 | ) | (0.3 | %) | ||||||||||||||||||
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kWh Sales (millions) | Change | |||||||||||||||||||||||||||
2020 vs. 2019 | 2019 vs. 2018 | |||||||||||||||||||||||||||
2020 | 2019 | 2018 | kWh | % | kWh | % | ||||||||||||||||||||||
Residential | 690.6 | 648.2 | 685.5 | 42.4 | 6.5 | % | (37.3 | ) | (5.4 | %) | ||||||||||||||||||
Commercial & Industrial | 905.3 | 947.5 | 990.3 | (42.2 | ) | (4.5 | %) | (42.8 | ) | (4.3 | %) | |||||||||||||||||
Total kWh Sales | 1,595.9 | 1,595.7 | 1,675.8 | 0.2 | — | (80.1 | ) | (4.8 | %) | |||||||||||||||||||
Electric Operating Revenues and Sales Margin (millions) | ||||||||||||||||||||||||||||
| Change | ||||||||||||||||||||||||||||
| 2018 vs. 2017 | 2017 vs. 2016 | |||||||||||||||||||||||||||
| 2018 | 2017 | 2016 | $ | % | $ | % | ||||||||||||||||||||||
Electric Operating Revenue: | ||||||||||||||||||||||||||||
Residential | $ | 127.2 | $ | 115.5 | $ | 110.6 | $ | 11.7 | 10.1 | % | $ | 4.9 | 4.4 | % | ||||||||||||||
Commercial & Industrial | 96.1 | 90.7 | 85.5 | 5.4 | 6.0 | % | 5.2 | 6.1 | % | |||||||||||||||||||
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Total Electric Operating Revenue | $ | 223.3 | $ | 206.2 | $ | 196.1 | $ | 17.1 | 8.3 | % | $ | 10.1 | 5.2 | % | ||||||||||||||
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Cost of Electric Sales | $ | 131.4 | $ | 114.0 | $ | 108.0 | $ | 17.4 | 15.3 | % | $ | 6.0 | 5.6 | % | ||||||||||||||
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Electric Sales Margin | $ | 91.9 | $ | 92.2 | $ | 88.1 | $ | (0.3 | ) | (0.3 | %) | $ | 4.1 | 4.7 | % | |||||||||||||
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Electric Operating Revenues and Electric Adjusted Gross Margin (millions) | ||||||||||||||||||||||||||||
Change | ||||||||||||||||||||||||||||
2020 vs. 2019 | 2019 vs. 2018 | |||||||||||||||||||||||||||
2020 | 2019 | 2018 | $ | % | $ | % | ||||||||||||||||||||||
Electric Operating Revenue: | ||||||||||||||||||||||||||||
Residential | $ | 134.7 | $ | 133.8 | $ | 127.2 | $ | 0.9 | 0.7 | % | $ | 6.6 | 5.2 | % | ||||||||||||||
Commercial & Industrial | 92.5 | 100.1 | 96.1 | (7.6 | ) | (7.6 | %) | 4.0 | 4.2 | % | ||||||||||||||||||
Total Electric Operating Revenue | $ | 227.2 | $ | 233.9 | $ | 223.3 | $ | (6.7 | ) | (2.9 | %) | $ | 10.6 | 4.7 | % | |||||||||||||
Cost of Electric Sales | $ | 134.3 | $ | 142.0 | $ | 131.4 | $ | (7.7 | ) | (5.4 | %) | $ | 10.6 | 8.1 | % | |||||||||||||
Electric Adjusted Gross Margin | $ | 92.9 | $ | 91.9 | $ | 91.9 | $ | 1.0 | 1.1 | % | $ | — | — | |||||||||||||||
Electric sales marginAdjusted Gross Margin (a
reasons noted above.
Electric sales margin was $92.2 million in 2017, an increase of $4.1 million compared to 2016. Electric sales margin in 2017 was positively affected by higher electric distribution rates of $5.4 million and customer growth of $1.0 million,customers, partially offset by lower sales volumes due to the net impact of milder summer weather of $0.5 million and lower transmission revenues of $1.8 million. The higher electric distribution rates in 2017 include $1.4 million from aone-year $1.4 million temporary rate reconciliation adjustment, discussed above, recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.
The increase in Total Electric Operating Revenue of $10.1 million, or 5.2%, in 2017 compared to 2016 reflects higher electric distribution rates and higher cost of electric sales, which are tracked and reconciled costs as a pass-through to customers.
electricity.
Usource’s revenues decreased $1.3$0.9 million or 21.7%, in 20182020 compared to 20172019 and $0.1$3.8 million or 1.6%, in 20172019 compared to 2016. The decrease2018, reflecting the Company’s divestiture of Usource in 2018 compared to 2017 is primarily the result of the adoption of a new accounting standard.
In the first quarter of 2018, the Company adopted Accounting Standards Update (ASU)2014-09, and its subsequent clarifications and amendments outlined in ASU2015-14, ASU2016-08, ASU2016-10 and ASU2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018. ASU2014-09 requires that payments made by Usource to third parties (“Channel Partners”) for revenue sharing agreements are recognized as a reduction from revenue, where those payments were previously recognized as an operating expense. Therefore, beginning in 2018 and going forward, payments made by Usource to third parties for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU2014-09, payments by Usource to Channel Partners for revenue sharing agreements are included as “Operation and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. Those Channel Partner payments were $1.0 million, $1.1 million and $1.0 million in 2018, 2017 and 2016, respectively.
If ASU2014-09 had been in effect for 2017 and 2016, the result would have been corresponding reductions of $1.1 million and $1.0 million, respectively, in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings.
The following table details total Other Revenue for the last three years:
Other Revenue (millions) | ||||||||||||||||||||||||||||
| Change | ||||||||||||||||||||||||||||
| 2018 vs. 2017 | 2017 vs. 2016 | |||||||||||||||||||||||||||
| 2018 | 2017 | 2016 | $ | % | $ | % | ||||||||||||||||||||||
Usource | $ | 4.7 | $ | 6.0 | $ | 6.1 | $ | (1.3 | ) | (21.7 | %) | $ | (0.1 | ) | (1.6 | %) | ||||||||||||
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Total Other Revenue | $ | 4.7 | $ | 6.0 | $ | 6.1 | $ | (1.3 | ) | (21.7 | %) | $ | (0.1 | ) | (1.6 | %) | ||||||||||||
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gas.
suppliers, partially offset by lower sales of electricity.
In 2017, totalthe 2018 adjustment, discussed above; O&M expenses increased $3.1 million, or 5.0%, compared to 2016.were higher by $1.3 million. The change in O&M expenses reflects higher compensation and benefit costs of $1.2 million and higher utility operating costs of $1.9 million. Utility operating costs include$0.7 million, higher pass-through regulatory and vegetation managementlabor costs of $1.1$0.5 million, which are recovered on a reconciling basis in sales margins.
and higher professional fees of $0.1 million.
amortization.
In 2017, Taxes Other Than Income Taxes increased $1.5partially offset by $1.0 million or 7.7%, compared to 2016, primarily reflecting higher localof property tax rates on higher levels of utility plant assetsabatements received in service.
2019.
Net
calculated.
In 2017, debt, largely offset by lower rates on short-term debt and lower interest expense on regulatory liabilities.
borrowings.
change of $13.8 million. This change primarily reflects a
Accordingly,tax expense for all periods presented in the Consolidated Financial Statements in this Form10-K2019.
Income Taxes
In 2017,period.
Revolving Credit Facility (millions) | ||||||||
| December 31, | ||||||||
| 2018 | 2017 | |||||||
Limit | $ | 120.0 | $ | 120.0 | ||||
Short-Term Borrowings Outstanding | $ | 82.8 | $ | 38.3 | ||||
Letters of Credit Outstanding | $ | — | $ | 0 | ||||
Available | $ | 37.2 | $ | 81.7 | ||||
2019:
Revolving Credit Facility (millions) | ||||||||
December 31, | ||||||||
2020 | 2019 | |||||||
Limit | $ | 120.0 | $ | 120.0 | ||||
Short-Term Borrowings Outstanding | $ | 54.7 | $ | 58.6 | ||||
Letters of Credit Outstanding | $ | 0.1 | $ | 0.1 | ||||
Available | $ | 65.2 | $ | 61.3 | ||||
November 30, 2018December 18, 2020, Unitil Realty Corp. entered into a loan agreement in the amount of $4.7 million at 2.64%, with a maturity date of December 18, 2030. Less than $0.1 million of costs associated with this loan have been recorded as a reduction to the proceeds. Unitil Realty Corp. used the net proceeds from this loan for general corporate purposes.
2019.
The Company believes it has sufficient sources of working capital to fund its operations.
| Payments Due by Period | ||||||||||||||||||||
Contractual Obligations (millions) as of December 31, 2018 | Total | 2019 | 2020— 2021 | 2022— 2023 | 2024 & Beyond | |||||||||||||||
Long-Term Debt | $ | 409.3 | $ | 18.8 | $ | 28.4 | $ | 34.9 | $ | 327.2 | ||||||||||
Interest on Long-Term Debt | 303.9 | 22.3 | 41.4 | 36.7 | 203.5 | |||||||||||||||
Gas Supply Contracts | 489.9 | 41.2 | 69.1 | 70.5 | 309.1 | |||||||||||||||
Electric Supply Contracts | 14.1 | 1.7 | 2.7 | 2.2 | 7.5 | |||||||||||||||
Other (Including Capital and Operating Lease Obligations) | 10.4 | 4.5 | 4.7 | 1.1 | 0.1 | |||||||||||||||
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Total Contractual Cash Obligations | $ | 1,227.6 | $ | 88.5 | $ | 146.3 | $ | 145.4 | $ | 847.4 | ||||||||||
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2020.
Payments Due by Period | ||||||||||||||||||||
Contractual Obligations (millions) as of December 31, 2020 | Total | 2021 | 2022— 2023 | 2024— 2025 | 2026 & Beyond | |||||||||||||||
Long-Term Debt | $ | 535.4 | $ | 8.8 | $ | 30.3 | $ | 14.0 | $ | 482.3 | ||||||||||
Interest on Long-Term Debt | 387.8 | 26.3 | 49.1 | 46.6 | 265.8 | |||||||||||||||
Gas Supply Contracts | 556.2 | 55.9 | 95.8 | 73.8 | 330.7 | |||||||||||||||
Electric Supply Contracts | 15.6 | 1.3 | 2.7 | 2.8 | 8.8 | |||||||||||||||
Other (Including Capital and Operating Lease Obligations) | 6.1 | 1.9 | 2.9 | 1.1 | 0.2 | |||||||||||||||
Total Contractual Cash Obligations | $ | 1,501.1 | $ | 94.2 | $ | 180.8 | $ | 138.3 | $ | 1,087.8 | ||||||||||
2019.
| 2018 | 2017 | |||||||
Cash Provided by Operating Activities | $ | 78.5 | $ | 86.2 | ||||
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2019.
2020 | 2019 | |||||||
Cash Provided by Operating Activities | $ | 75.7 | $ | 104.9 | ||||
2019.
2020 Net Operating Loss Carryforward utilization against taxable income.
| 2018 | 2017 | |||||||
Cash (Used in) Investing Activities | $ | (102.4 | ) | $ | (119.3 | ) | ||
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$4.3 million.
2020 | 2019 | |||||||
Cash Used in Investing Activities | $ | (122.6 | ) | $ | (105.8 | ) | ||
| 2018 | 2017 | |||||||
Cash Provided by Financing Activities | $ | 22.8 | $ | 36.2 | ||||
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2020 | 2019 | |||||||
Cash Provided by (Used in) Financing Activities | $ | 47.7 | $ | (1.7 | ) | |||
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:
Policies).
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 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.
Allowance for Doubtful Accounts—The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takestaking into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount ofwritten-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulatorscurrent and historical weather data, assumptions pertaining to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, the electricmetering patterns, billing cycle statistics, and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected fromshut-off. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.
plan covering substantially allplan. 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 its employees.each union. The Company also sponsors a
Statements.)
statements.
Item 7A. |
As discussed above,
Item 8. |
Corporation:
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