10-K 1 d262254d10k.htm FORM 10-K

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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 December 31, 2016

OR

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

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, New Hampshire |  | 03842-1720
(Address of principal executive offices) |  | (Zip Code)

Registrant’s telephone number, including area code: (603) 772-0775

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class |  | Name of Each Exchange on Which Registered
Common Stock, No Par Value |  | 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes ☒ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-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 Form 10-K or any amendment to this Form 10-K. ☒

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐ Accelerated filer ☒ Non-accelerated filer ☐ Smaller reporting company ☐

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, 2016, the aggregate market value of common stock held by non-affiliates of the registrant was $586,061,044.

The number of shares of the registrant’s common stock outstanding was 14,066,399 as of January 30, 2017.

Documents Incorporated by Reference:

Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held on April 26, 2017 are incorporated by reference into Part III of this Report.

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UNITIL CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2016

Table of Contents

Item |  | Description |  | Page |
|  | PART I |  |  |  |
1. |  | Business |  |  | 2 |
|  | Unitil Corporation |  |  | 2 |
|  | Operations |  |  | 3 |
|  | Rates and Regulation |  |  | 5 |
|  | Natural Gas Supply |  |  | 7 |
|  | Electric Power Supply |  |  | 7 |
|  | Environmental Matters |  |  | 9 |
|  | Employees |  |  | 10 |
|  | Available Information |  |  | 10 |
|  | Investor Information |  |  | 10 |
1A. |  | Risk Factors |  |  | 11 |
1B. |  | Unresolved Staff Comments |  |  | 17 |
2. |  | Properties |  |  | 17 |
3. |  | Legal Proceedings |  |  | 18 |
4. |  | Mine Safety Disclosures |  |  | 18 |
|  | PART II |  |  |  |
5. |  | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  |  | 19 |
6. |  | Selected Financial Data |  |  | 22 |
7. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) |  |  | 23 |
7A. |  | Quantitative and Qualitative Disclosures about Market Risk |  |  | 42 |
8. |  | Financial Statements and Supplementary Data |  |  | 44 |
9. |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |  |  | 86 |
9A. |  | Controls and Procedures |  |  | 86 |
9B. |  | Other Information |  |  | 86 |
|  | PART III |  |  |  |
10. |  | Directors, Executive Officers and Corporate Governance |  |  | 87 |
11. |  | Executive Compensation |  |  | 87 |
12. |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |  |  | 87 |
13. |  | Certain Relationships and Related Transactions, and Director Independence |  |  | 87 |
14. |  | Principal Accountant Fees and Services |  |  | 87 |
|  | PART IV |  |  |  |
15. |  | Exhibits and Financial Statement Schedules |  |  | 88 |
|  | SIGNATURES |  |  |  |
|  | Signatures |  |  | 93 |

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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, Section 21E of the Securities Exchange Act of 1934, as amended, 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:

| • |  | the Company’s regulatory environment (including regulations relating to climate change, greenhouse gas emissions and other environmental matters), which could affect the rates the Company is able to charge, the Company’s authorized rate of return and the Company’s ability to recover costs in its rates;

| • |  | fluctuations in the supply of, demand for, and the prices of, gas and electric energy commodities and transmission and transportation capacity and the Company’s ability to recover energy supply costs in its rates;

| • |  | customers’ preferred energy sources;

| • |  | severe storms and the Company’s ability to recover storm costs in its rates;

| • |  | declines in the valuation of capital markets, 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;

| • |  | 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;

| • |  | restrictive covenants contained in the terms of the Company’s and its subsidiaries’ indebtedness, which restrict certain aspects of the Company’s business operations;

| • |  | 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;

| • |  | 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;

| • |  | catastrophic events;

| • |  | the Company’s ability to retain its existing customers and attract new customers; and

| • |  | increased competition.

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 these factors, nor can the Company assess the impact 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 Form 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 and was incorporated under the laws of the State of New Hampshire in 1984. The following companies are wholly-owned subsidiaries of Unitil:

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
Usource Inc. and Usource L.L.C. (collectively Usource) |  | DE - 2000 |  | Energy Brokering 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 approximately 184,200 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 approximately 104,300 electric customers and 79,900 natural gas customers.

|  | Customers Served as of December 31, 2016 |
|  | Residential |  |  | Commercial & Industrial (C&I) |  |  | Total |
Electric: |  |  |  |  |  |  |  |  |  |  |  |
Unitil Energy |  |  | 64,207 |  |  |  | 11,066 |  |  |  | 75,273 |
Fitchburg |  |  | 25,193 |  |  |  | 3,806 |  |  |  | 28,999 |
Total Electric |  |  | 89,400 |  |  |  | 14,872 |  |  |  | 104,272 |
Natural Gas: |  |  |  |  |  |  |  |  |  |  |  |
Northern Utilities |  |  | 48,155 |  |  |  | 15,989 |  |  |  | 64,144 |
Fitchburg |  |  | 14,129 |  |  |  | 1,665 |  |  |  | 15,794 |
Total Natural Gas |  |  | 62,284 |  |  |  | 17,654 |  |  |  | 79,938 |
Total Customers Served |  |  | 151,684 |  |  |  | 32,526 |  |  |  | 184,210 |

Unitil had an investment in Net Utility Plant of $883.4 million at December 31, 2016. Unitil’s total operating revenue was $383.4 million in 2016. Unitil’s operating revenue is substantially derived from regulated natural gas and electric distribution utility operations. A fifth utility subsidiary, Unitil Power,

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formerly functioned as the full requirements wholesale power supply provider for Unitil Energy, but currently has limited business and operating activities. In connection with the implementation of electric industry restructuring in New Hampshire, 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 those contracts.

Unitil also has three other wholly-owned 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-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are indirect subsidiaries that are wholly-owned by Unitil Resources. Usource provides energy brokering and advisory services to a national client base of large commercial and industrial customers. For segment information relating to each segment’s revenue, earnings and assets, see Note 3 (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.

OPERATIONS

Natural Gas Operations

Unitil’s natural gas operations include gas distribution utility operations and interstate gas transmission pipeline operations, discussed below. Revenue from Unitil’s gas operations was $181.2 million for 2016, which represents about 47% of Unitil’s total operating revenue.

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’ Commercial and Industrial (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 64,144 customers in 44 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 in 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, printing, textile, pharmaceutical, electronics, wire and food production industries as well as a military installation. Northern Utilities’ 2016 gas operating revenue was $145.3 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 15,794 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 companies and printing, publishing and associated industries. Fitchburg’s 2016 gas operating revenue was $29.3 million, of which approximately 55% was derived from residential firm sales and 45% 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

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natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State had operating revenue of $6.6 million for 2016. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and to third-party suppliers.

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 $196.1 million for 2016, which represents about 51% of Unitil’s total operating revenue.

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 choose to purchase their supply of electricity from third-party competitive suppliers, while Unitil Energy or Fitchburg remains 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 through regulated reconciling rate mechanisms that are periodically adjusted.

Unitil Energy distributes electricity to 75,273 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. In addition, Unitil Energy’s service territory encompasses retail trading 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, healthcare and education. Unitil Energy’s 2016 electric operating revenue was $132.6 million, of which approximately 55% was derived from residential sales and 45% from 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. Electricity is distributed by Fitchburg to 28,999 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, chemical products companies, printing, publishing and associated industries and educational institutions. Fitchburg’s 2016 electric operating revenue was $63.5 million, of which approximately 59% was derived from residential sales and 41% from C&I 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 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 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 are conducted through Usource, a subsidiary of Unitil Resources. Usource provides energy brokering and advisory services to a national client base of large commercial and industrial customers. Revenue from Unitil’s non-regulated operations was $6.1 million in 2016.

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

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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.

RATES AND REGULATION

Rate Case Activity

Unitil Energy—Base Rates—On April 29, 2016 Unitil Energy filed for an increase in distribution base rates with the New Hampshire Public Utilities Commission (NHPUC). The Company’s filing seeks an increase in base rates of approximately $6.3 million or 3.6 percent above present rates. The Company also requested a long-term rate plan for the annual recovery in future years of the costs associated with utility plant additions. On June 28, 2016 the NHPUC approved a settlement agreement between the Company, Commission Staff and the Office of Consumer Advocate on a $2.4 million temporary rate increase effective July 1, 2016. The temporary rate increase will remain in effect until a permanent rate increase decision is issued. Once a permanent rate is decided, it will be reconciled back to the effective date of the temporary rate increase. The Company is currently engaged in settlement discussions with the Commission and the Office of the Consumer Advocate on the remaining issues in the rate case. Any settlement in the rate case or additional investigation and litigation is expected to be completed for final approval by NHPUC by the end of April, 2017.

Fitchburg—Base Rates—Electric—On April 29, 2016, the Massachusetts Department of Public Utilities (MDPU) issued an order approving a $2.1 million increase in Fitchburg’s electric base revenue decoupling target, effective May 1, 2016. The MDPU also approved a capital cost recovery mechanism, providing for annual adjustments to target revenues to account for capital spending. In 2016, Fitchburg made its first capital cost adjustment filing documenting its capital investments for calendar year 2015 and requesting $0.5 million of the associated revenue requirements for recovery beginning January 1, 2017. On December 27, 2016 the MDPU approved this filing subject to further investigation and reconciliation.

Fitchburg—Base Rates—Gas—On April 29, 2016, the MDPU issued an order approving a $1.6 million increase in Fitchburg’s gas base revenue decoupling target, effective May 1, 2016.

Fitchburg—Gas Operations—On October 31, 2015, Fitchburg submitted its second annual filing to recover the estimated costs to be incurred in 2016 under its approved 20 year gas system enhancement plan program. The program was established pursuant to legislation that provided for the establishment of comprehensive replacement programs to address aging natural gas pipeline infrastructure. Effective May 1, 2016, the MDPU approved the Company’s request to collect in rates $0.9 million for the estimated costs of its cumulative capital investments in the program through the end of 2016. On October 31, 2016, Fitchburg submitted its third annual filing to recover the estimated cost to be incurred in 2017 under the gas system enhancement plan program, seeking approval to collect an additional $0.9 million to recover the cumulative cost of investments in the program through the end of 2017. In addition, the Company seeks a waiver of the 1.5 percent cap on annual changes in the revenue requirement eligible for recovery. The MDPU’s decision on this request is pending and is expected by the end of April, 2017, for rates effective May 1, 2017.

Northern Utilities—Base Rates—Maine—The rate case settlement in Northern Utilities’ Maine division’s last rate case allowed the Company to implement a Targeted Infrastructure Replacement Adjustment (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. The TIRA has an initial term of four years and covers targeted capital expenditures in 2013 through 2016. The 2016 TIRA, for 2015 expenditures, was filed on February 29, 2016, and provides for an annual increase in distribution base revenue of $1.5 million, effective May 1, 2016, and was approved by the Maine Public Utilities Commission (MPUC) on April 28, 2016.

Northern Utilities—Targeted Area Build-out Program—Maine—On December 22, 2015 the MPUC approved a new Targeted Area Build-out 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 and is being initially piloted in the City of Saco. 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. This pilot program is planned to be built out over the next three years and has the potential

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to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco pilot area. The Company will continue to evaluate the success of the program and ways to economically reach new targeted service areas.

Northern Utilities—Base Rates—New Hampshire—Northern Utilities’ New Hampshire division’s last rate case resulted in a settlement agreement providing for an increase of $4.6 million in distribution base revenue and an additional step increase in revenue of $1.4 million for investments in gas mains extensions and infrastructure replacement projects, effective May 1, 2014, and a step adjustment that provided for an annual increase of $1.8 million in revenue effective May 1, 2015.

Northern Utilities—Pipeline Refund—On February 19, 2015, the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers. In New Hampshire, the refund is being credited to all customers over a three year period as directed by the NHPUC. In Maine, the refund has been divided into two parts, as directed by the MPUC. Maine retail customers who purchase their gas directly from Northern Utilities are being credited their portion of the refund over a three year period. The second part of the refund was paid on October 5, 2015 as a one-time lump sum payment directly to marketers who transport gas on Northern Utilities’ distribution system. The Company has recorded current and noncurrent Regulatory Liabilities related to these refunds of $4.4 million and $2.4 million, respectively, on its Consolidated Balance Sheets as of December 31, 2016.

Granite State—Base Rates—Granite State has in place a FERC-approved second amended settlement agreement under which it is permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a specific cost cap. On June 24, 2016 Granite State filed for an annual revenue and rate increase under this provision of $0.3 million, effective August 1, 2016. This filing was approved by the FERC on July 13, 2016.

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 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 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 tracker 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 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 Regulatory 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 rates and regulation.

NATURAL GAS SUPPLY

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 to purchase their natural gas supply from third-party gas suppliers. Many of Northern Utilities’ largest and some medium C&I customers purchase their gas supply from third party suppliers, while most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. As of December 2016, 78% of Unitil’s largest New Hampshire gas customers, representing 27% of Unitil’s New Hampshire gas sales and 66% of Unitil’s largest Maine customers, representing 26% of Unitil’s Maine gas sales, are purchasing 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 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 2016, 79% of Unitil’s largest Massachusetts gas customers, representing 30% of Unitil’s Massachusetts gas sales, are purchasing gas supply from third-party suppliers. The approved costs associated 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 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 3.6 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 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.

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.

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Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers. As of December 2016, 80% of Unitil’s largest New Hampshire customers, representing 26% of Unitil’s New Hampshire electric energy sales and 85% of Unitil’s largest Massachusetts customers, representing 34% of Unitil’s Massachusetts electric energy 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 19% of Fitchburg’s customer base and customers in Ashby comprise another 5%.

In New Hampshire, the number of residential customers purchasing from a third party supplier has increased significantly since 2014 and currently stands at 13% of residential customers. Notwithstanding this recent activity, 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’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-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 the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-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. The ISO-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 the ISO-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.

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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 (the “Green Communities Act”) of 2008 and An Act Relative to Competitively Priced Electricity in the Commonwealth of 2012, and the MDPU’s regulations implementing the legislation. The generating facilities associated with three of these contracts have been constructed and are now operating. In 2016, the Company participated in a multi-state procurement for long-term renewable contracts and several contracts from this solicitation are currently under negotiation. These are expected to be finalized and submitted to MDPU for approval in 2017. Additional long-term clean energy contracts are expected in compliance with the Acts of 2016, An Act to Promote Energy Diversity (“Energy Diversity Act”). Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

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, 2016, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, we 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 the mid-1800s through the mid-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 (ME DEP) and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Dover, Somersworth, Portsmouth, Lewiston, Portland and Scarborough sites, though on site monitoring continues and it is possible that future activities may be required.

In December 2016, the ME DEP issued a Certificate of Completion for the Portland remediation activities completed in early 2016. Pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the Portland site will be primarily the responsibility of the State of Maine.

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.

Fitchburg’s Manufactured Gas Plant Site—Fitchburg has worked with the Massachusetts Department of Environmental Protection (MA DEP) 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.

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Also, see Environmental 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, 2016, the Company and its subsidiaries had 498 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of December 31, 2016, a total of 161 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, 2016:

|  | Employees Covered |  |  | CBA Expiration |
Fitchburg |  |  | 46 |  |  |  | 05/31/2019 |
Northern Utilities NH Division |  |  | 34 |  |  |  | 06/05/2017 |
Northern Utilities ME Division/Granite State |  |  | 38 |  |  |  | 03/31/2017 |
Unitil Energy |  |  | 38 |  |  |  | 05/31/2018 |
Unitil Service |  |  | 5 |  |  |  | 05/31/2018 |

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 www.unitil.com. 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.

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 26, 2017, at 11:30 a.m.

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 30170

College Station, TX 77842-3170

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 www.unitil.com; or contact the transfer agent, Computershare, at the number listed above.

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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

Risks Relating to Our Business

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 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 impact 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 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

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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, 2016, the Company had approximately $81.9 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. 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 impact on the financial results. Additionally, the Company uses its best judgment in attempting to quantify and reserve for these tax obligations. However, a

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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.

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 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 entitled Critical 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 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 and results of operations. See the sections entitled Liquidity, 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.

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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 has to satisfy its debt obligations and comply with any statutory or contractual limitations.

As of January 25, 2017, the Company’s current annual dividend is $1.44 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.

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.

In order to meet existing and future customer demands for natural gas and electricity, the Company must acquire sufficient supplies of natural gas and electricity. 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 natural gas and electric supply were insufficient to meet future customer demands for natural gas and electricity.

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.

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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.

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 electricity and natural gas systems rely on evolving information technology systems and network infrastructures 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 impact 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

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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.

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 impacted 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 impact the timely delivery of natural gas and electricity, 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 and results of operations.

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 and results of operations.

The natural gas and electric 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

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contract directly with customers. In either scenario, significant increases in natural gas and electricity commodity prices may negatively impact 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, since 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.

The financial performance of the Company’s non-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. | Unresolved Staff Comments

None.

Item 2. | Properties

As of December 31, 2016, Unitil owned, through its natural gas and electric distribution utilities, five utility operation centers located in New Hampshire, Maine and Massachusetts. In addition, the Company’s real estate subsidiary, Unitil Realty, owns the Company’s corporate headquarters building and the 12 acres of land on which it is located. In 2016, the Company completed its acquisition of a 15 acre property for its new Fitchburg Gas and Electric Distribution Operations Center.

The following tables detail certain of the Company’s natural gas and electric operations properties.

Natural Gas Operations

|  | Northern Utilities |  |  | Fitchburg |  |  | Granite State |  |  | Total |
Description |  | NH |  |  | ME |  |  |  |
Underground Natural Gas Mains—Miles |  |  | 535 |  |  |  | 571 |  |  |  | 275 |  |  |  | — |  |  |  | 1,381 |
Natural Gas Transmission Pipeline—Miles |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 86 |  |  |  | 86 |
Service Pipes |  |  | 22,977 |  |  |  | 21,681 |  |  |  | 10,981 |  |  |  | — |  |  |  | 55,639 |

Electric Operations

Description |  | Unitil Energy |  |  | Fitchburg |  |  | Total |
Primary Transmission and Distribution Pole Miles—Overhead |  |  | 1,271 |  |  |  | 442 |  |  |  | 1,713 |
Conduit Distribution Bank Miles—Underground |  |  | 222 |  |  |  | 65 |  |  |  | 287 |
Transmission and Distribution Substations |  |  | 33 |  |  |  | 16 |  |  |  | 49 |
Transformer Capacity of Transmission and Distribution Substations (MVA) |  |  | 433.7 |  |  |  | 621.0 |  |  |  | 1,054.7 |

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The Company’s natural gas operations property includes two liquid 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 (78%), coated and wrapped cathodically protected steel (16%), cast/wrought iron (4%), and unprotected bare and coated steel (2%). Fitchburg’s gas mains are primarily made up of steel (47%), polyethylene plastic (32%), and cast iron (21%).

Granite State’s underground natural gas transmission pipeline, regulated by the FERC, is located primarily in Maine and New Hampshire.

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 Hampshire. Unitil 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 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, 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 impact on its financial position, operating results or cash flows.

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks 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 remain pending. The Company continues to believe that this suit is without merit and will continue to defend itself vigorously. The Town of Lunenburg filed a separate action in the Court arising out of the December 2008 ice storm. The Court granted the Company’s Motion for Summary Judgment on all counts in December 2016 and dismissed the Town’s complaint. The Court’s decision remains subject to a potential motion for reconsideration and appeal. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these suits will not have a material impact on its financial position, operating results or cash flows.

Item 4. | Mine Safety Disclosures

Not applicable.

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PART II

Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the New York Stock Exchange under the symbol “UTL.” As of December 31, 2016, there were 1,412 shareholders of record of our common stock.

Common Stock Data

Dividends per Common Share |  | 2016 |  |  | 2015 |
1st Quarter |  | $ | 0.355 |  |  | $ | 0.350 |
2nd Quarter |  |  | 0.355 |  |  |  | 0.350 |
3rd Quarter |  |  | 0.355 |  |  |  | 0.350 |
4th Quarter |  |  | 0.355 |  |  |  | 0.350 |
Total for Year |  | $ | 1.42 |  |  | $ | 1.40 |

See also “Dividends” in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) below.

|  | 2016 |  |  | 2015 |
Price Range of Common Stock |  | High/Ask |  |  | Low/Bid |  |  | High/Ask |  |  | Low/Bid |
1st Quarter |  | $ | 43.29 |  |  | $ | 34.70 |  |  | $ | 39.00 |  |  | $ | 32.99 |
2nd Quarter |  | $ | 42.93 |  |  | $ | 35.37 |  |  | $ | 35.29 |  |  | $ | 32.63 |
3rd Quarter |  | $ | 45.16 |  |  | $ | 38.00 |  |  | $ | 37.59 |  |  | $ | 32.75 |
4th Quarter |  | $ | 46.00 |  |  | $ | 37.31 |  |  | $ | 38.75 |  |  | $ | 33.75 |

Information regarding securities authorized for issuance under our equity compensation plans, as of December 31, 2016, is set forth in the table below.

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) |  |  | — |  |  |  | — |  |  |  | 374,986 |
Equity compensation plans not approved by security holders |  |  | — |  |  |  | — |  |  |  | — |
Total |  |  | — |  |  |  | — |  |  |  | 374,986 |

NOTES: (also see Note 6 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 306,615 shares of restricted stock have been awarded and 1,106 restricted stock units have been settled and issued as shares of common stock by Plan participants through December 31, 2016. As of December 31, 2016, a total of 5,207 shares of restricted stock were forfeited and once again became available for issuance under the Plan.

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Stock Performance Graph

The following graph compares Unitil Corporation’s cumulative stockholder return since December 31, 2011 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, 2011.

Comparative Five-Year Total Returns

NOTE:

(1) | The graph above assumes $100 invested on December 31, 2011, in each category and the reinvestment of all dividends during the five-year period. The Peer Group is comprised of the S&P 500 Utilities Index.

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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, 2016.

Issuer Purchases of Equity Securities

Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted and announced by the Company on May 2, 2016, the Company will periodically repurchase shares of its Common Stock on the open market related to Employee Length of Service Awards and 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 $75,000 in value of shares have been purchased or, if sooner, on May 2, 2017.

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.

The following table shows 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, 2016.

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 |
10/1/16 – 10/31/16 |  |  | 1,356 |  |  | $ | 38.30 |  |  |  | 1,356 |  |  | $ | 12,203 |
11/1/16 – 11/30/16 |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 12,203 |
12/1/16 – 12/31/16 |  |  | 115 |  |  | $ | 43.28 |  |  |  | 115 |  |  | $ | 7,226 |
Total |  |  | 1,471 |  |  | $ | 38.69 |  |  |  | 1,471 |  |  |  |  |

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Item 6. | Selected Financial Data

|  | For the Years Ended December 31, (all data in millions except customers served, shares, % and per share data) |
|  | 2016 |  |  | 2015 |  |  | 2014 |  |  | 2013 |  |  | 2012 |
Customers Served (Year-End): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  |  | 89,400 |  |  |  | 88,444 |  |  |  | 88,012 |  |  |  | 87,692 |  |  |  | 87,062 |
Commercial & Industrial |  |  | 14,872 |  |  |  | 14,825 |  |  |  | 14,740 |  |  |  | 14,701 |  |  |  | 14,612 |
Total Electric |  |  | 104,272 |  |  |  | 103,269 |  |  |  | 102,752 |  |  |  | 102,393 |  |  |  | 101,674 |
Natural Gas: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  |  | 62,284 |  |  |  | 61,270 |  |  |  | 60,236 |  |  |  | 57,616 |  |  |  | 56,745 |
Commercial & Industrial |  |  | 17,654 |  |  |  | 17,479 |  |  |  | 17,624 |  |  |  | 18,304 |  |  |  | 16,977 |
Total Natural Gas |  |  | 79,938 |  |  |  | 78,749 |  |  |  | 77,860 |  |  |  | 75,920 |  |  |  | 73,722 |
Total Customers Served |  |  | 184,210 |  |  |  | 182,018 |  |  |  | 180,612 |  |  |  | 178,313 |  |  |  | 175,396 |
Electric and Gas Sales: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric Distribution Sales (kWh) |  |  | 1,628.8 |  |  |  | 1,667.7 |  |  |  | 1,679.0 |  |  |  | 1,668.3 |  |  |  | 1,653.8 |
Firm Natural Gas Distribution Sales (Therms) |  |  | 205.7 |  |  |  | 219.4 |  |  |  | 216.2 |  |  |  | 200.7 |  |  |  | 181.3 |
Consolidated Statements of Earnings: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating Revenue |  | $ | 383.4 |  |  | $ | 426.8 |  |  | $ | 425.8 |  |  | $ | 366.9 |  |  | $ | 353.1 |
Operating Income |  |  | 65.3 |  |  |  | 63.1 |  |  |  | 60.0 |  |  |  | 53.5 |  |  |  | 47.5 |
Interest Expense, net |  |  | 22.5 |  |  |  | 21.9 |  |  |  | 20.9 |  |  |  | 18.8 |  |  |  | 18.1 |
Other Expense (Income), net |  |  | 0.3 |  |  |  | (0.5 | ) |  |  | 0.4 |  |  |  | 0.4 |  |  |  | 0.2 |
Income Before Income Taxes |  |  | 42.5 |  |  |  | 41.7 |  |  |  | 38.7 |  |  |  | 34.3 |  |  |  | 29.2 |
Income Taxes |  |  | 15.4 |  |  |  | 15.4 |  |  |  | 14.0 |  |  |  | 12.7 |  |  |  | 11.0 |
Net Income |  |  | 27.1 |  |  |  | 26.3 |  |  |  | 24.7 |  |  |  | 21.6 |  |  |  | 18.2 |
Dividends on Preferred Stock |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 0.1 |
Earnings Applicable to Common Shareholders |  | $ | 27.1 |  |  | $ | 26.3 |  |  | $ | 24.7 |  |  | $ | 21.6 |  |  | $ | 18.1 |
Earnings Per Average Share: |  | $ | 1.94 |  |  | $ | 1.89 |  |  | $ | 1.79 |  |  | $ | 1.57 |  |  | $ | 1.43 |
Common Stock—(Diluted Weighted Average Outstanding, 000’s) |  |  | 13,996 |  |  |  | 13,920 |  |  |  | 13,847 |  |  |  | 13,775 |  |  |  | 12,672 |
Dividends Declared Per Share |  | $ | 1.42 |  |  | $ | 1.40 |  |  | $ | 1.38 |  |  | $ | 1.38 |  |  | $ | 1.38 |
Book Value Per Share (Year-End) |  | $ | 20.82 |  |  | $ | 20.20 |  |  | $ | 19.62 |  |  | $ | 19.14 |  |  | $ | 18.90 |
Balance Sheet Data (as of December 31,): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Utility Plant |  | $ | 1,173.4 |  |  | $ | 1,080.6 |  |  | $ | 988.8 |  |  | $ | 909.1 |  |  | $ | 833.2 |
Capital Lease Obligations(1) |  | $ | 11.3 |  |  | $ | 14.1 |  |  | $ | 8.0 |  |  | $ | 0.6 |  |  | $ | 1.0 |
Total Assets |  | $ | 1,128.2 |  |  | $ | 1,038.8 |  |  | $ | 997.0 |  |  | $ | 917.6 |  |  | $ | 889.0 |
Capitalization: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common Stock Equity |  | $ | 292.9 |  |  | $ | 282.6 |  |  | $ | 273.1 |  |  | $ | 265.0 |  |  | $ | 260.4 |
Preferred Stock |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.2 |
Long-Term Debt, less current portion |  |  | 316.8 |  |  |  | 305.5 |  |  |  | 326.0 |  |  |  | 282.1 |  |  |  | 284.3 |
Total Capitalization |  | $ | 609.9 |  |  | $ | 588.3 |  |  | $ | 599.3 |  |  | $ | 547.3 |  |  | $ | 544.9 |
Current Portion of Long-Term Debt |  | $ | 16.8 |  |  | $ | 17.1 |  |  | $ | 3.7 |  |  | $ | 2.2 |  |  | $ | 0.2 |
Short-Term Debt |  | $ | 81.9 |  |  | $ | 42.0 |  |  | $ | 29.3 |  |  | $ | 60.2 |  |  | $ | 49.4 |
Capital Structure Ratios (as of December 31,): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common Stock Equity |  |  | 48 | % |  |  | 48 | % |  |  | 46 | % |  |  | 48 | % |  |  | 48 | %
Long-Term Debt, less current portion |  |  | 52 | % |  |  | 52 | % |  |  | 54 | % |  |  | 52 | % |  |  | 52 | %

(1) | Includes amounts due within one year.

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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 8, below.)

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 184,200 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 104,300 electric customers and 79,900 natural gas customers in their service territory.

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.

The distribution utilities are local “pipes and wires” operating companies, and Unitil had an investment in Net Utility Plant of $883.4 million at December 31, 2016. Unitil’s total revenue was $383.4 million in 2016, which includes revenue to recover the approved cost of purchased electricity and natural gas in rates on a fully reconciling basis. As a result of this reconciling rate structure, the Company’s earnings are not affected by changes in the cost of purchased electricity and natural gas. Earnings from Unitil’s utility operations are derived from the return on investment in the three distribution utilities and Granite State.

Unitil also conducts non-regulated operations principally through Usource, which is wholly-owned by Unitil Resources. Usource provides energy brokering and advisory services to a national client base of large commercial and industrial customers. Usource’s total revenues were $6.1 million in 2016. The Company’s other subsidiaries include Unitil Service, which provides, at cost, a variety of 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 and financial position.

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Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities 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 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 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 see Regulatory Matters shown below and Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on rates and regulation.

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.

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’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. Also, as a result of recent rate cases, the Company’s natural gas sales margins are derived from a higher percentage of fixed billing components, including customer charges. Therefore, natural gas revenues and 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 sales margin on decoupled sales volumes.

Net Income and EPS Overview

2016 Compared to 2015—The Company’s Net Income was $27.1 million, or $1.94 per share, for the year ended December 31, 2016, a 3.0% increase of $0.8 million in Net Income, and $0.05 per share, compared to 2015. The Company’s earnings for 2016 were driven by increases in natural gas and electric sales margins and lower utility operating costs.

Natural gas sales margin was $103.6 million in the twelve months ended December 31, 2016, resulting in an increase of $1.7 million compared to 2015. Gas sales margin in the twelve month period was positively affected by higher natural gas distribution rates and customer growth, partially offset by the

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negative impact of warmer winter weather on sales in the beginning of 2016. Based on weather data collected in the Company’s natural gas service areas, there were 8% fewer Heating Degree Days (HDD) in 2016 compared to 2015. The Company estimates that the warmer winter weather in 2016 negatively impacted gas sales margins by approximately $3.3 million, or $0.15 per share.

Electric sales margin was $88.1 million in the twelve months ended December 31, 2016, resulting in an increase of $2.6 million compared to 2015. Electric sales margins in 2016 were positively affected by customer growth, higher electric distribution rates and the favorable effect of above normal summer temperatures.

Total Operation & Maintenance (O&M) expenses decreased $0.8 million in 2016 compared to 2015, reflects lower utility operating costs of $2.0 million, including lower electric and gas distribution system maintenance costs of $1.3 million and lower bad debt expenses of $0.7 million, and lower outside service professional fees of $0.9 million, partially offset by higher compensation and benefit costs of $2.1 million.

Depreciation and Amortization expense increased $0.9 million in 2016 compared to 2015, reflecting higher depreciation of $1.8 million on normal utility plant assets in service, partially offset by lower amortization of $0.9 million.

Taxes Other Than Income Taxes increased $1.9 million in 2016 compared to 2015, primarily reflecting higher local property taxes on higher levels of utility plant assets in service.

Interest Expense, net increased $0.6 million in 2016 compared to 2015 reflecting higher levels of short-term debt and lower net interest income on regulatory assets.

Other Expense (Income), net changed from income of $0.5 million in 2015 to an expense of $0.3 million in 2016. This change was the result of the recognition of a pre-tax gain of $0.9 million in the fourth quarter of 2015 on the sale of its former Distribution Operations Center facility in Portland, Maine.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $6.1 million in 2016, essentially on par with 2015. Usource’s revenues are primarily derived from fees billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

Income Taxes in 2016 were essentially unchanged compared to 2015, reflecting higher pre-tax earnings in 2016 and higher federal and state tax credits recognized in 2016.

In 2016, Unitil’s annual common dividend was $1.42 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January 2017 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.36 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annual dividend rate to $1.44 per share from $1.42 per share.

2015 Compared to 2014—The Company’s Net Income was $26.3 million, or $1.89 per share, for the year ended December 31, 2015, an increase of $1.6 million, or $0.10 per share, compared to 2014. The Company’s earnings for 2015 were driven by increases in natural gas and electric sales margins partially offset by higher utility operating expenses.

A more detailed discussion of the Company’s 2016 and 2015 results of operations and a year-to-year comparison of changes in financial position are presented below.

Gas Sales, Revenues and Margin

Therm Sales—Unitil’s total therm sales of natural gas decreased 6.2% in 2016 compared to 2015. Sales to residential and C&I customers decreased 10.2% and 5.2%, respectively, in 2016 compared to 2015. The decrease in gas therm sales in the Company’s service areas was driven by warmer winter weather in the first quarter of 2016 compared to 2015, partially offset by customer growth. Based on weather data collected in the Company’s natural gas service areas, there were 8% fewer HDD in 2016 compared to 2015.

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The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 1.2% in 2016 compared to 2015. This growth was led by a year over year increase of 3.3% in gas therm sales to large industrial customers. As of December 31, 2016 the number of total natural gas customers served has increased by 1,189 in the last twelve months. As discussed above, sales margin derived from decoupled unit sales (representing approximately 11% of total annual therm sales volume) is not sensitive to changes in gas therm sales.

Unitil’s total therm sales of natural gas increased 1.5% in 2015 compared to 2014. The impact of growth in the number of customers year over year was partially offset by warmer winter weather in 2015 compared to the prior year. The average number of natural gas customers served increased by 1.8% in 2015 compared to the prior year. For the full year, based on weather data collected in the Company’s service areas, there were 2.3% fewer Heating Degree Days in 2015 compared to 2014. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 4% in 2015 compared to 2014, led by a year over year increase of eight percent in gas therm sales to large C&I customers.

The following table details total therm sales for the last three years, by major customer class:

Therm Sales (millions) |  |  |  |  |  |  |  |  |  |  | Change |
|  |  |  |  |  |  |  |  |  |  | 2016 vs. 2015 |  |  | 2015 vs. 2014 |
|  | 2016 |  |  | 2015 |  |  | 2014 |  |  | Therms |  |  | % |  |  | Therms |  |  | % |
Residential |  |  | 40.6 |  |  |  | 45.2 |  |  |  | 44.7 |  |  |  | (4.6 | ) |  |  | (10.2 | %) |  |  | 0.5 |  |  |  | 1.1 | %
Commercial & Industrial |  |  | 165.1 |  |  |  | 174.2 |  |  |  | 171.5 |  |  |  | (9.1 | ) |  |  | (5.2 | %) |  |  | 2.7 |  |  |  | 1.6 | %
Total Therm Sales |  |  | 205.7 |  |  |  | 219.4 |  |  |  | 216.2 |  |  |  | (13.7 | ) |  |  | (6.2 | %) |  |  | 3.2 |  |  |  | 1.5 | %

Gas Operating Revenues and Sales Margin—The following table details total Gas Operating Revenue and Sales Margin for the last three years by major customer class:

Gas Operating Revenues and Sales Margin (millions) |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  | Change |
|  |  |  |  |  |  |  |  |  |  | 2016 vs. 2015 |  |  | 2015 vs. 2014 |
|  | 2016 |  |  | 2015 |  |  | 2014 |  |  | $ |  |  | % |  |  | $ |  |  | % |
Gas Operating Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 71.0 |  |  | $ | 78.5 |  |  | $ | 80.0 |  |  | $ | (7.5 | ) |  |  | (9.6 | %) |  | $ | (1.5 | ) |  |  | (1.9 | %)
Commercial & Industrial |  |  | 110.2 |  |  |  | 124.1 |  |  |  | 121.4 |  |  |  | (13.9 | ) |  |  | (11.2 | %) |  |  | 2.7 |  |  |  | 2.2 | %
Total Gas Operating Revenue |  | $ | 181.2 |  |  | $ | 202.6 |  |  | $ | 201.4 |  |  | $ | (21.4 | ) |  |  | (10.6 | %) |  | $ | 1.2 |  |  |  | 0.6 | %
Cost of Gas Sales |  | $ | 77.6 |  |  | $ | 100.7 |  |  | $ | 104.0 |  |  | $ | (23.1 | ) |  |  | (22.9 | %) |  | $ | (3.3 | ) |  |  | (3.2 | %)
Gas Sales Margin |  | $ | 103.6 |  |  | $ | 101.9 |  |  | $ | 97.4 |  |  | $ | 1.7 |  |  |  | 1.7 | % |  | $ | 4.5 |  |  |  | 4.6 | %

The Company analyzes operating results using Gas Sales Margin, a non-GAAP measure. Gas Sales Margin is calculated as Total Gas Operating Revenue less Cost of Gas Sales. The Company believes Gas Sales Margin is an important measure to analyze profitability because the approved cost of sales are tracked and reconciled to costs that are passed through directly to customers, resulting in an equal and offsetting amount reflected in Total Gas Operating Revenue. Sales margin can be reconciled to Operating Income, a GAAP measure, by including Operation and Maintenance, Depreciation and Amortization and Taxes Other Than Income Taxes for each segment in the analysis.

Natural gas sales margin was $103.6 million in 2016, resulting in an increase of $1.7 million compared to 2015. Gas sales margin in 2016 was positively affected by $3.7 million in higher natural gas distribution rates and customer growth of $1.3 million, partially offset by the negative impact of warmer winter weather in 2016 of $3.3 million.

The decrease in Total Gas Operating Revenues of $21.4 million, or 10.6%, in 2016 compared to 2015 reflects lower natural gas sales volumes and lower cost of gas sales, which are tracked and reconciled costs that are passed through directly to customers.

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Natural gas sales margin was $101.9 million in 2015, resulting in an increase of $4.5 million compared to 2014. Approximately $3.4 million of the increase reflects higher natural gas distribution rates and $1.1 million of the increase reflects higher sales volumes related to customer growth, net of the impact of warmer winter weather in 2015.

The increase in Total Gas Operating Revenues of $1.2 million, or 0.6%, in 2015 compared to 2014 reflects higher gas base rates and sales volumes, partially offset by lower costs of gas sales, which are tracked and reconciled to costs that are passed through directly to customers.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales—Unitil’s total electric kWh sales decreased 2.3% in 2016 compared to 2015. Sales to residential customers and C&I customers decreased 3.0% and 1.9%, respectively, in 2016 compared to 2015, reflecting warmer winter in 2016 compared to 2015, partially offset by warmer summer weather in 2016. Based on weather data collected in the Company’s electric service areas, there were 12% more Cooling Degree Days in 2016 compared to 2015. As of December 31, 2016, the number of total electric customers served has increased by 1,003 in the last twelve months. As discussed above, sales margins derived from revenue decoupled unit sales (representing approximately 27% of total annual sales volume) are not sensitive to changes in kWh sales.

Unitil’s total electric kWh sales decreased 0.7% in 2015 compared to 2014. Sales to residential customers decreased 2.4% in 2015 compared to 2014, reflecting a decrease in average use per customer. Sales to C&I customers increased 0.5% in 2015 compared to 2014, reflecting the addition of new customers.

The following table details total kWh sales for the last three years by major customer class:

kWh Sales (millions) |  |  |  |  |  |  |  |  |  |  | Change |
|  |  |  |  |  |  |  |  |  |  | 2016 vs. 2015 |  |  | 2015 vs. 2014 |
|  | 2016 |  |  | 2015 |  |  | 2014 |  |  | kWh |  |  | % |  |  | kWh |  |  | % |
Residential |  |  | 651.3 |  |  |  | 671.4 |  |  |  | 687.6 |  |  |  | (20.1 | ) |  |  | (3.0 | %) |  |  | (16.2 | ) |  |  | (2.4 | %)
Commercial & Industrial |  |  | 977.5 |  |  |  | 996.3 |  |  |  | 991.4 |  |  |  | (18.8 | ) |  |  | (1.9 | %) |  |  | 4.9 |  |  |  | 0.5 | %
Total kWh Sales |  |  | 1,628.8 |  |  |  | 1,667.7 |  |  |  | 1,679.0 |  |  |  | (38.9 | ) |  |  | (2.3 | %) |  |  | (11.3 | ) |  |  | (0.7 | %)

Electric Operating Revenues and Sales Margin—The following table details Total Electric Operating Revenue and Sales Margin for the last three years by major customer class:

Electric Operating Revenues and Sales Margin (millions) |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  | Change |
|  |  |  |  |  |  |  |  |  |  | 2016 vs. 2015 |  |  | 2015 vs. 2014 |
|  | 2016 |  |  | 2015 |  |  | 2014 |  |  | $ |  |  | % |  |  | $ |  |  | % |
Electric Operating Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 110.6 |  |  | $ | 125.9 |  |  | $ | 118.0 |  |  | $ | (15.3 | ) |  |  | (12.2 | %) |  | $ | 7.9 |  |  |  | 6.7 | %
Commercial & Industrial |  |  | 85.5 |  |  |  | 92.1 |  |  |  | 100.7 |  |  |  | (6.6 | ) |  |  | (7.2 | %) |  |  | (8.6 | ) |  |  | (8.5 | %)
Total Electric Operating Revenue |  | $ | 196.1 |  |  | $ | 218.0 |  |  | $ | 218.7 |  |  | $ | (21.9 | ) |  |  | (10.0 | %) |  | $ | (0.7 | ) |  |  | (0.3 | %)
Cost of Electric Sales |  | $ | 108.0 |  |  | $ | 132.5 |  |  | $ | 137.9 |  |  | $ | (24.5 | ) |  |  | (18.5 | %) |  | $ | (5.4 | ) |  |  | (3.9 | %)
Electric Sales Margin |  | $ | 88.1 |  |  | $ | 85.5 |  |  | $ | 80.8 |  |  | $ | 2.6 |  |  |  | 3.0 | % |  | $ | 4.7 |  |  |  | 5.8 | %

The Company analyzes operating results using Electric Sales Margin, a non-GAAP measure. Electric Sales Margin is calculated as Total Electric Operating Revenues less Cost of Electric Sales. The Company believes Electric Sales Margin is an important measure to analyze profitability because the approved cost of sales are tracked and reconciled to costs that are passed through directly to customers resulting in an equal and offsetting amount reflected in Total Electric Operating Revenues. Sales margin can be reconciled to Operating Income, a GAAP measure, by including Operation and Maintenance, Depreciation and Amortization and Taxes Other Than Income Taxes for each segment in the analysis.

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Electric sales margin was $88.1 million in 2016, resulting in an increase of $2.6 million compared to 2015. Electric sales margin in 2016 was positively affected by $3.1 million in higher electric distribution rates and the positive impact of $1.2 million resulting from warmer summer weather in 2016, partially offset by the negative impact of warmer winter weather of $1.7 million.

The decrease in Total Electric Operating Revenue of $21.9 million, or 10.0%, in 2016 compared to 2015 reflects lower electric sales volumes and lower cost of electric sales, which are tracked and reconciled to costs that are passed through directly to customers.

Electric sales margin was $85.5 million in 2015, resulting in an increase of $4.7 million compared to 2014. Higher electric distribution rates of $5.0 million and the positive impact of $0.7 million resulting from warmer summer weather in 2015 were partially offset by approximately $1.0 million of lower electric sales margin, reflecting lower average usage in 2015.

The decrease in Total Electric Operating Revenue of $0.7 million, or 0.3%, in 2015 compared to 2014 reflects lower costs of electric sales, which are tracked costs that are passed through directly to customers, partially offset by higher electric distribution rates.

Operating Revenue—Other

Total Other Operating Revenue is comprised of revenues from the Company’s non-regulated energy brokering business, Usource. Usource’s revenues in 2016 were $6.1 million, essentially on par with 2015. Usource’s revenues in 2015 were $6.2 million, an increase of $0.5 million compared to 2014. As an energy broker and advisor, Usource assists business customers with the procurement and contracting for electricity and natural gas in competitive energy markets. Usource’s revenues are primarily derived from fees billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

The following table details total Other Revenue for the last three years:

Other Revenue (millions) |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  | Change |
|  |  |  |  |  |  |  |  |  |  | 2016 vs. 2015 |  |  | 2015 vs. 2014 |
|  | 2016 |  |  | 2015 |  |  | 2014 |  |  | $ |  |  | % |  |  | $ |  |  | % |
Usource |  | $ | 6.1 |  |  | $ | 6.2 |  |  | $ | 5.7 |  |  | $ | (0.1 | ) |  |  | (1.6 | %) |  | $ | 0.5 |  |  |  | 8.8 | %
Total Other Revenue |  | $ | 6.1 |  |  | $ | 6.2 |  |  | $ | 5.7 |  |  | $ | (0.1 | ) |  |  | (1.6 | %) |  | $ | 0.5 |  |  |  | 8.8 | %

Operating Expenses

Cost of Gas Sales—Cost of Gas Sales includes the cost of natural gas purchased and manufactured to supply the Company’s total gas supply requirements and spending on energy efficiency programs. Cost of Gas Sales decreased $23.1 million, or 22.9%, in 2016 compared to 2015. This decrease reflects lower wholesale natural gas prices and lower sales of natural gas, partially offset by a decrease in the amount of natural gas purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Gas Sales in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

In 2015, Cost of Gas Sales decreased $3.3 million, or 3.2%, compared to 2014. This decrease reflects lower wholesale natural gas prices and decreased spending on energy efficiency programs, partially offset by higher sales of natural gas and a decrease in the amount of natural gas purchased by customers directly from third-party suppliers.

Cost of Electric Sales—Cost of Electric Sales includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs, and spending on energy efficiency programs. Cost of Electric Sales decreased $24.5 million, or 18.5%, in 2016 compared to 2015. This decrease reflects lower electric kWh sales, lower wholesale electricity prices and an increase in the

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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 2015, Cost of Electric Sales decreased $5.4 million, or 3.9%, compared to 2014. This decrease reflects lower electric kWh sales and an increase in the amount of electricity purchased by customers directly from third-party suppliers.

Operation and Maintenance—O&M expense includes electric and gas utility operating costs, and the operating costs of the Company’s non-regulated business activities. Total O&M expenses decreased $0.8 million, or 1.2%, in 2016 compared to 2015. The change in O&M expenses reflects lower utility operating costs of $2.0 million, including lower electric and gas distribution system maintenance costs of $1.3 million and lower bad debt expenses of $0.7 million, and lower outside service professional fees of $0.9 million, partially offset by higher compensation and benefit costs of $2.1 million. The savings achieved in utility operating costs in 2016 reflect maintenance costs at lower seasonal sales levels and the implementation of cost efficiency measures in 2016.

In 2015, total O&M expenses increased $2.5 million, or 3.9%, compared to 2014. The change in O&M expenses reflects higher compensation and benefit costs of $3.5 million partially offset by lower professional fees of $0.3 million and lower all other utility O&M costs, net of $0.7 million. The decrease in utility operating costs includes $0.8 million in lower electric and natural gas maintenance costs and higher all other utility operating costs, net of $0.1 million.

Depreciation and Amortization—Depreciation and Amortization expense increased $0.9 million, or 2.0%, in 2016 compared to 2015, reflecting higher depreciation of $1.8 million on normal utility plant assets in service, partially offset by lower amortization of $0.9 million.

In 2015, Depreciation and Amortization expense increased $3.6 million, or 8.6%, compared to 2014, reflecting higher depreciation of $2.4 million on normal utility plant assets in service, higher amortization of major storm restoration costs of $0.9 million and an increase in all other amortization of $0.3 million. The increase in major storm restoration cost amortization is currently recovered in electric rates and reflected in electric sales margin.

Taxes Other Than Income Taxes—Taxes Other Than Income Taxes increased $1.9 million, or 10.7%, in 2016 compared to 2015, primarily reflecting higher local property taxes on higher levels of utility plant assets in service.

In 2015, Taxes Other Than Income Taxes increased 0.5 million, or 2.9%, compared to 2014, reflecting higher local property taxes on higher levels of utility plant in service.

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. Certain reconciling rate mechanisms used by the Company’s distribution utilities give rise to regulatory assets (and regulatory liabilities) on which interest is calculated (See Note 5 to the accompanying Consolidated Financial Statements).

Interest Expense, net increased $0.6 million, or 2.7%, in 2016 compared to 2015 reflecting higher levels of short-term debt and lower net interest income on regulatory assets.

In 2015, Interest Expense, net increased $1.0 million, or 4.8%, compared to 2014 reflecting higher levels of long-term debt and higher interest expense on regulatory liabilities.

Other Expense (Income), net

Other Expense (Income), net changed from income of $0.5 million in 2015 to an expense of $0.3 million in 2016. This change was the result of the recognition of a pre-tax gain of $0.9 million in the fourth quarter of 2015 on the sale of its former Distribution Operations Center facility in Portland, Maine.

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Other Expense (Income), net, changed from an expense of $0.4 million in 2014 to income of $0.5 million in 2015. This change was the result of the recognition of a pre-tax gain of $0.9 million in the fourth quarter of 2015 on the sale of property, discussed above.

Income Taxes

Income Taxes in 2016 were essentially unchanged compared to 2015 reflecting higher pre-tax earnings in 2016 and higher federal and state tax credits recognized in 2016 (See Note 9 to the accompanying Consolidated Financial Statements).

In 2015, Income Taxes increased $1.4 million compared to 2014 due to higher pre-tax earnings in 2015 compared to 2014.

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.

The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (the “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, 2016 and December 31, 2015, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (as further amended, restated, amended and restated, modified or supplemented from time to time, the “Credit Facility”). The Credit Facility terminates October 4, 2020 and provides for a borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil 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 1.25%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

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The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $218.2 million and $140.3 million for the years ended December 31, 2016 and December 31, 2015, respectively. Total gross repayments were $178.3 million and $127.6 million for the years ended December 31, 2016 and December 31, 2015, respectively. In the third quarter of 2016, the Company issued a standby letter of credit for $1.1 million. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2016 and December 31, 2015:

Revolving Credit Facility (millions) |
|  | December 31, |
|  | 2016 |  |  | 2015 |
Limit |  | $ | 120.0 |  |  | $ | 120.0 |
Short-Term Borrowings Outstanding |  | $ | 81.9 |  |  | $ | 42.0 |
Letters of Credit Outstanding |  | $ | 1.1 |  |  | $ | 0.0 |
Available |  | $ | 37.0 |  |  | $ | 78.0 |

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, 2016 and December 31, 2015, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 5.)

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services.

In April 2014, Unitil Service Corp. entered into a financing arrangement for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of December 31, 2016, there are $2.6 million of current and $7.8 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

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.

Contractual Obligations

The table below lists the Company’s known specified contractual obligations as of December 31, 2016.

|  |  |  |  | Payments Due by Period |
Contractual Obligations (millions) as of December 31, 2016 |  | Total |  |  | 2017 |  |  | 2018- 2019 |  |  | 2020- 2021 |  |  | 2022 & Beyond |
Long-Term Debt |  | $ | 336.6 |  |  | $ | 17.2 |  |  | $ | 48.9 |  |  | $ | 28.4 |  |  | $ | 242.1 |
Interest on Long-Term Debt |  |  | 235.7 |  |  |  | 20.9 |  |  |  | 36.9 |  |  |  | 31.8 |  |  |  | 146.1 |
Gas Supply Contracts |  |  | 353.0 |  |  |  | 39.0 |  |  |  | 52.8 |  |  |  | 43.4 |  |  |  | 217.8 |
Electric Supply Contracts |  |  | 18.0 |  |  |  | 1.7 |  |  |  | 3.5 |  |  |  | 3.5 |  |  |  | 9.3 |
Other (Including Capital and Operating Lease Obligations) |  |  | 14.8 |  |  |  | 4.3 |  |  |  | 7.4 |  |  |  | 3.0 |  |  |  | 0.1 |
Total Contractual Cash Obligations |  | $ | 958.1 |  |  | $ | 83.1 |  |  | $ | 149.5 |  |  | $ | 110.1 |  |  | $ | 615.4 |

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The Company and its subsidiaries have material energy supply commitments that are discussed in Note 7 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 a 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, 2016, there were approximately $17.9 million of guarantees outstanding and the longest term guarantee extends through August 2017.

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 $9.9 million and $10.8 million of natural gas storage inventory at December 31, 2016 and 2015, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2016, which was payable in January 2017, was $2.1 million and recorded in Accounts Payable at December 31, 2016. The amount of natural gas inventory released in December 2015, which was payable in January 2016, was $0.6 million and recorded in Accounts Payable at December 31, 2015.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of December 31, 2016, the principal amount outstanding for the 8% Unitil Realty notes was $0.4 million, and the principal amount outstanding for the 7.15% Granite State notes was $6.7 million.

Benefit Plan Funding

The Company, along with its subsidiaries, made cash contributions to its Pension Plan in the amounts of $5.1 million and $4.2 million in 2016 and 2015, respectively. The Company, along with its subsidiaries, contributed $4.0 million to Voluntary Employee Benefit Trusts (VEBTs) in each of 2016 and 2015. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan and the VEBTs in 2017 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these benefit plans. See Note 10 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements.

Off-Balance Sheet Arrangements

The Company and its subsidiaries do not currently use, and are not dependent on the use of, 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. Unitil’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. Additionally, as of December 31, 2016, there were approximately $17.9 million of guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities outstanding and the longest term guarantee extends through August 2017. See Note 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

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 2016 and 2015.

|  | 2016 |  |  | 2015 |
Cash Provided by Operating Activities |  | $ | 68.3 |  |  | $ | 115.1 |

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Cash Provided by Operating Activities—Cash Provided by Operating Activities was $68.3 million in 2016, a decrease of $46.8 million compared to 2015.

Cash flow from net income, adjusted for the total of non-cash charges to depreciation, amortization and deferred taxes, was $89.1 million in 2016 compared to $83.9 million in 2015, reflecting an increase of $5.2 million. The increase in net income of $0.8 million in 2016 compared to 2015 is primarily attributable to increases in natural gas and electric sales margins and customer growth. The increase in depreciation and amortization of $0.9 million in 2016 compared to 2015 reflects higher utility depreciation from higher net utility plant in service. The increase in the deferred tax provision of $3.5 million in 2016 compared to 2015 is primarily a result of increased tax depreciation deductions and the Portland Natural Gas Transmission System (PNGTS) refund to customers (See Note 8).

Changes in working capital items resulted in a ($20.8) million use of cash in 2016 compared to a $18.5 million source of cash in 2015, representing a decrease of $39.3 million. Sources of cash from Regulatory Liabilities decreased $12.1 million in 2016 compared to 2015, primarily driven by the current portion of the PNGTS to be refunded to customers (see Note 8). All other changes in working capital reflect normal variations from year-to-year, including changes in underlying commodity prices.

Deferred Regulatory and Other Charges decreased $13.2 million in 2016 compared to 2015, primarily driven by the long-term portion of the PNGTS refund. The change in Other, net in 2016 compared to 2015 was 0.5 million.

|  | 2016 |  |  | 2015 |
Cash (Used in) Investing Activities |  | $ | (98.1 | ) |  | $ | (103.9 | )

Cash (Used in) Investing Activities—Cash Used in Investing Activities was ($98.1) million in 2016 compared to ($103.9) million in 2015. The actual capital spending in both 2016 and 2015 is related to utility capital expenditures for electric and gas utility system additions. The Company’s projected capital spending range for 2017 is $100 million to $105 million.

|  | 2016 |  |  | 2015 |
Cash Provided by (Used in) Financing Activities |  | $ | 26.9 |  |  | $ | (10.9 | )

Cash Provided by (Used in) Financing Activities—Cash Provided by (Used in) Financing Activities was $26.9 million in 2016 compared to ($10.9) million in 2015. The higher cash provided by financing activities in 2016 compared to 2015 is primarily attributable to the issuance of $30 million of long-term debt in 2016. Other changes in financing activities in 2016 compared to 2015 are ($11.6) million greater repayment of long-term debt, ($8.9) million decrease in capital lease obligations, ($0.4) million greater dividends paid, offset by $27.2 million greater proceeds of short-term debt and $1.5 million of exchange gas financing.

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 5 (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

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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, 2016 and December 31, 2015, 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 $1.42 per common share in 2016, $1.40 per common share in 2015, and $1.38 per share in 2014. 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 2017 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.36 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annual dividend rate to $1.44 from $1.42. 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 to satisfy its debt obligations and comply with any statutory or contractual limitations. See Financial Covenants and Restrictions, above, as well as Note 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

LEGAL PROCEEDINGS

The Company is involved in legal and administrative proceedings and claims of various types, 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 impact on its financial position, operating results or cash flows. Refer to “Legal Proceedings” in Note 8 of the Consolidated Financial Statements for a discussion of legal proceedings.

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 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 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

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their electricity or gas supply from third party suppliers, while most small C&I customers, as well 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. The MDPU, the NHPUC and the MPUC have 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.

In 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. 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 assets have been principally recovered as of December 31, 2016. The remaining balance of these assets is $1.6 million as of December 31, 2016, including $0.3 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet projected to be recovered in the next year and $1.3 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the next five years. Unitil’s distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Rate Case Activity

Unitil Energy—Base Rates—On April 29, 2016 Unitil Energy filed for an increase in distribution base rates with the NHPUC. The Company’s filing seeks an increase in base rates of approximately $6.3 million or 3.6 percent above present rates. The Company also requested a long-term rate plan for the annual recovery in future years of the costs associated with utility plant additions. On June 28, 2016 the NHPUC approved a settlement agreement between the Company, Commission Staff and the Office of Consumer Advocate on a $2.4 million temporary rate increase effective July 1, 2016. The temporary rate increase will remain in effect until a permanent rate increase decision is issued. Once a permanent rate is decided, it will be reconciled back to the effective date of the temporary rate increase. The Company is currently engaged in settlement discussions with the Commission and the Office of the Consumer Advocate on the remaining issues in the rate case. Any settlement in the rate case or additional investigation and litigation is expected to be completed for final approval by NHPUC by the end of April, 2017.

Fitchburg—Base Rates—Electric—On April 29, 2016, the MDPU issued an order approving a $2.1 million increase in Fitchburg’s electric base revenue decoupling target, effective May 1, 2016. The MDPU also approved a capital cost recovery mechanism, providing for annual adjustments to target revenues to account for capital spending. In 2016, Fitchburg made its first capital cost adjustment filing documenting its capital investments for calendar year 2015 and requesting $0.5 million of the associated revenue requirements for recovery beginning January 1, 2017. On December 27, 2016 the MDPU approved this filing subject to further investigation and reconciliation.

Fitchburg—Base Rates—Gas—On April 29, 2016, the MDPU issued an order approving a $1.6 million increase in Fitchburg’s gas base revenue decoupling target, effective May 1, 2016.

Fitchburg—Gas Operations—On October 31, 2015, Fitchburg submitted its second annual filing to recover the estimated costs to be incurred in 2016 under its approved 20 year gas system enhancement plan program. The program was established pursuant to legislation that provided for the establishment of comprehensive replacement programs to address aging natural gas pipeline infrastructure. Effective May 1, 2016, the MDPU approved the Company’s request to collect in rates $0.9 million for the estimated costs of its cumulative capital investments in the program through the end of 2016. On October 31, 2016, Fitchburg submitted its third annual filing to recover the estimated cost to be incurred in 2017 under the gas system enhancement plan program, seeking approval to collect an additional $0.9 million to recover the cumulative cost of investments in the program through the end of 2017. In addition, the Company seeks a waiver of the 1.5 percent cap on annual changes in the revenue requirement eligible for recovery. The MDPU’s decision on this request is pending and is expected by the end of April, 2017, for rates effective May 1, 2017.

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Northern Utilities—Base Rates—Maine—The rate case settlement in Northern Utilities’ Maine division’s last 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. The TIRA has an initial term of four years and covers targeted capital expenditures in 2013 through 2016. The 2016 TIRA, for 2015 expenditures, was filed on February 29, 2016, and provides for an annual increase in distribution base revenue of $1.5 million, effective May 1, 2016, and was approved by the MPUC on April 28, 2016.

Northern Utilities—Targeted Area Build-out Program—Maine—On December 22, 2015 the MPUC approved a new Targeted Area Build-out 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 and is being initially piloted in the City of Saco. 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. This pilot program is planned to be built out over the next three years and has the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco pilot area. The Company will continue to evaluate the success of the program and ways to economically reach new targeted service areas.

Northern Utilities—Base Rates—New Hampshire—Northern Utilities’ New Hampshire division’s last rate case resulted in a settlement agreement providing for an increase of $4.6 million in distribution base revenue and an additional step increase in revenue of $1.4 million for investments in gas mains extensions and infrastructure replacement projects, effective May 1, 2014, and a step adjustment that provided for an annual increase of $1.8 million in revenue effective May 1, 2015.

Northern Utilities—Pipeline Refund—On February 19, 2015, the FERC issued Opinion No. 524-A, the final order in PNGTS’ Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers. In New Hampshire, the refund is being credited to all customers over a three year period as directed by the NHPUC. In Maine, the refund has been divided into two parts, as directed by the MPUC. Maine retail customers who purchase their gas directly from Northern Utilities are being credited their portion of the refund over a three year period. The second part of the refund was paid on October 5, 2015 as a one-time lump sum payment directly to marketers who transport gas on Northern Utilities’ distribution system. The Company has recorded current and noncurrent Regulatory Liabilities related to these refunds of $4.4 million and $2.4 million, respectively, on its Consolidated Balance Sheets as of December 31, 2016.

Granite State—Base Rates—Granite State has in place a FERC-approved second amended settlement agreement under which it is permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a specific cost cap. On June 24, 2016 Granite State filed for an annual revenue and rate increase under this provision of $0.3 million, effective August 1, 2016. This filing was approved by the FERC on July 13, 2016.

Other Matters

NHPUC Energy Efficiency Resource Standard Proceeding—In May 2015, the NHPUC opened a proceeding to establish an Energy Efficiency Resource Standard (“EERS”), an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. On April 27, 2016, a comprehensive settlement agreement was filed by the parties, including Unitil Energy and Northern Utilities, which was approved by the NHPUC on August 2, 2016. The settlement provides for: extending the 2014-2016 Core program an additional year (through 2017); establishing an EERS; establishing a recovery mechanism to compensate the utilities for lost-revenue related to the EERS programs; and approving the performance incentives and processes for stakeholder involvement, evaluation, measurement and verification, and oversight of the EERS programs.

Unitil Energy—Electric Grid Modernization—In July 2015, the NHPUC opened an investigation into Grid Modernization to address a variety of issues related to Distribution System Planning, Customer

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Engagement with Distributed Energy Resources, and Utility Cost Recovery and Financial Incentives. The NHPUC has engaged a consultant to direct a Working Group to investigate these issues and to prepare a final report with recommendations for the Commission. The report is expected to be filed in early 2017. Unitil Energy is an active participant in the Working Group. This matter remains pending.

Unitil Energy—Net Metering—Pursuant to legislation that became effective in May 2016, the NHPUC opened a proceeding to consider alternatives to the net metering tariffs currently in place. The legislation requires that a decision on this matter must be issued by the NHPUC by March 2, 2017. The NHPUC approved an extension of the current net metering tariffs on an interim basis until it issues its final decision on June 2, 2017. Unitil Energy is an active participant in this proceeding.

Fitchburg—Electric Operations—On November 17, 2016, Fitchburg submitted its 2016 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were given final approval by the MDPU on December 29, 2016, effective January 1, 2017.

Fitchburg—Service Quality—On March 1, 2016, Fitchburg submitted its 2015 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. Fitchburg’s annual gas and electric divisions’ Service Quality Reports for the periods up through 2014 have all been approved by the MDPU. On September 30, 2016 the MDPU approved Fitchburg’s 2015 electric division Service Quality Report as filed, and on November 22, 2016 the MDPU approved Fitchburg’s 2015 gas division Service Quality Report.

In December 2015, the MDPU issued its final order adopting new and revised Service Quality Guidelines. The Company has generally been able to meet or exceed the performance metrics of the previous Service Quality Guidelines and believes that it will continue to meet or exceed the performance metrics under the new and revised Guidelines.

Fitchburg—Solar Generation—On August 19, 2016, Fitchburg filed a petition with the MDPU seeking approval to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts. The proposal includes a cost recovery mechanism that would share the costs and benefits of the project among all Fitchburg customers. On October 27, 2016 a Settlement Agreement supporting the proposal was reached between the Company, the Attorney General of Massachusetts, and the Low-Income Weatherization and Fuel Assistance Program Network. The Settlement Agreement was approved by the MDPU on November 9, 2016. Construction of the solar generating facility is expected to be completed by the end of November 2017.

Fitchburg—Energy Diversity—Governor Baker signed into law H4568 “An Act to Promote Energy Diversity” on August 8, 2016. Among many sections in the bill, the primary provision adds new sections 83c and 83d to the 2008 Green Communities Act. Section 83c requires every electric distribution company (EDC) to jointly and competitively solicit proposals for at least 400 MW’s of offshore wind energy generation by June 30, 2017, as part of a total of 1,600 MW of offshore wind the EDCs are directed to procure by June 30, 2027. The procurement requirement is subject to a determination by the MDPU that the proposed long-term contracts are cost-effective. Section 83d further requires the EDCs to jointly seek proposals for cost effective clean energy (hydro and other) long-term contracts via one or more staggered solicitations, the first of which shall be issued not later than April 1, 2017, for a total of 9,450,000 megawatt-hours by December 31, 2022. Emergency regulations implementing these new provisions, 220 C.M.R. § 23.00 et seq. and 220 C.M.R. § 24.00 et seq. were adopted by the MDPU on December 29, 2016.

Fitchburg—Clean Energy RFP—Pursuant to Section 83a of the Green Communities Act in Massachusetts and similar clean energy directives established in Connecticut and Rhode Island, state agencies and the electric distribution companies in the three states, including Fitchburg, issued an RFP for clean energy resources (including Class I renewable generation and large hydroelectric generation) in November 2015. The RFP sought proposals for clean energy and transmission projects that can deliver new renewable energy to the three states. Project proposals were received in January 2016 and joint evaluation

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activities are ongoing. Selection of contracts concluded during the fourth quarter of 2016 and contract negotiations are underway for several proposed projects. Fitchburg’s final contracts will be subject to review and approval of the MDPU.

Fitchburg—Other—On September 23, 2016, the Massachusetts Department of Energy Resources (“DOER”) presented its Solar Incentive Straw Proposal in accordance with Chapter 75 of the Acts of 2016 which directed the DOER to develop a statewide solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers throughout the commonwealth. The program would replace the state’s expiring solar incentive program, which uses solar renewable energy credits (“SRECs”) and is known as SREC-2, with a tariff program. The tariff would provide for incentive payments which would be net of energy value (i.e., total tariff rate minus value of energy). The program also includes a variety of tariff adders, including incentives for location, such as landfill site, for off-takers, such as a community aggregation program, and for other technologies, such as behind-the-meter storage. Cost recovery of tariff payments and administrative costs may be made through a fixed, non-bypassable monthly charge to all distribution customers. Comments on the straw proposal were filed on October 28, 2016. The DOER’s implementation schedule includes filing emergency regulations, conducting a rulemaking during winter 2017 to permanently promulgate emergency regulation, MDPU review of model tariffs in spring 2017, and final program implementation in summer 2017.

On May 11, 2016, the MDPU issued an Order commencing a rulemaking proceeding to adopt emergency regulations amending 220 C.M.R. § 18.00 et seq. (“Net Metering Regulations”). Specifically, the MDPU amended its Net Metering Regulations to implement the net metering provisions of An Act Relative to Solar Energy, St. 2016, c. 75, §§ 3-9, and to make additional clerical changes to the Net Metering Regulations. On July 15, 2016, the MDPU issued an order approving Final Net Metering Regulations. The distribution companies were required to submit draft net metering tariffs to comply with the new regulations, which they did on September 1, 2016. On January 6, 2017, the MDPU approved the model tariff and ordered the utilities to file compliance tariffs on January 20, 2017. This matter remains pending.

On August 23, 2016 the MDPU held a technical session to discuss its straw proposal for a monthly minimum reliability contribution (“MMRC”). The purpose of the MMRC is for all distribution company customers to contribute to the fixed costs that ensure the reliability, proper maintenance, and safety of the electric distribution system. Parties in the proceeding filed alternative proposals on October 11, 2016. On January 13, 2017, the MDPU issued an order noting that no consensus was reached with respect to its straw proposal. The MDPU stated that it has the authority to consider proposals for an MMRC and sets limitations on when and how it may approve such a proposal, and that it is each distribution company’s discretion whether to file an MMRC proposal and what such a proposal would include.

In December 2013, the MDPU opened an investigation into Modernization of the Electric Grid. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices.” In June 2014, the MDPU issued its first Grid Modernization order, setting forth a requirement that each electric distribution company submit a ten-year strategic Grid Modernization Plan (GMP). As part of the GMP, each company must include a five-year Short-Term Investment Plan (STIP), which must include an approach to achieving advanced metering functionality within five years of the Department’s approval of the GMP. The filing of a GMP is a recurring obligation and must be updated as part of subsequent base distribution rate cases, which by statute must occur no less often than every five years. Capital investments contained in the STIP are eligible for pre-authorization, meaning that the MDPU will not revisit in later filings whether the Company should have proceeded with these investments. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015. These filings are currently under MDPU review and remain pending.

On January 28, 2016 the MDPU approved Fitchburg’s Three-Year Energy Efficiency Plan for 2016-2018, subject to limited modifications and directives in the Order. The Department found that the savings goals included in each Three-Year Plan are reasonable and are consistent with the achievement of all available cost-effective energy efficiency; approved each Program Administrator’s program implementation cost budget for the Three-Year Plans; approved the performance incentive pool, mechanism, and payout

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rates; found that all proposed energy efficiency programs are cost-effective; found that funding sources are reasonable and that each Program Administrator may recover the funds to implement its energy efficiency plan through its EES; and found that each Program Administrator’s Three-Year Plan is consistent with the Green Communities Act, the Guidelines, and Department precedent.

FERC Transmission Formula Rate Proceeding—On December 28, 2015, FERC issued an order, pursuant to Section 206 of the Federal Power Act, instituting a proceeding concerning the justness and reasonableness of ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that this proceeding results in any changes to the rates being charged, a refund period will begin retroactive to January 4, 2016. The Company does not believe this investigation will have a material adverse impact on the Company’s financial condition or results of operations.

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, 2016, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, we 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 MGP sites, which were operated from the mid-1800s through the mid-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 ME DEP and NH DES to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Dover, Somersworth, Portsmouth, Lewiston, Portland and Scarborough sites, though on site monitoring continues and it is possible that future activities may be required.

In December 2016, the ME DEP issued a Certificate of Completion for the Portland remediation activities completed in early 2016. Pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the Portland site will be primarily the responsibility of the State of Maine.

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.

Fitchburg’s Manufactured Gas Plant Site—Fitchburg has worked with the MA DEP 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.

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Also, see Environmental 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.

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 impact 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: Summary of Significant Accounting Policies.

Regulatory Accounting—The Company’s principal business is the distribution 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 NHPUC and Northern Utilities is regulated by the 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 Financial Accounting Standards Board Accounting Standards Codification (FASB Codification). In accordance with the FASB Codification, the Company 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 public utility regulatory commission.

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 accounted for by a regulated enterprise. Revenues intended to cover some 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. 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 impact 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 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.

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Utility Revenue Recognition—Utility revenues are recognized according to regulations and are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are 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 calculated each month based on estimated customer usage by class and applicable customer rates.

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 takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, the electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-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.

Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan covering substantially all of its employees. The Company also sponsors a 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 are 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 resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact 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, 2016, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $524,000 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 $454,000 in the Net Periodic Benefit Cost for the Pension Plan. For the year ended December 31, 2016, a 1.0% increase in the assumption of health

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care cost trend rates would have resulted in increases in the Net Periodic Benefit Cost for the PBOP Plan of $1,352,000. Similarly, a 1.0% decrease in the assumption of health care cost trend rates would have resulted in decreases in the Net Periodic Benefit Cost for the PBOP Plan of $1,032,000. (See Note 10 to the accompanying Consolidated Financial Statements).

Income Taxes—The Company is subject to Federal and State income taxes as well as various other business taxes. This process involves estimating the Company’s current tax liabilities as well as assessing 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 guidance on Income Taxes. The Company classifies penalty 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, the 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.

Depreciation—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements.

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2016, the Company is not aware of any material commitments or contingencies other than those disclosed in the Significant Contractual Obligations table in the Contractual Obligations section above and the Commitments and Contingencies footnote to the Company’s consolidated financial statements below.

Refer to “Recently Issued Pronouncements” in Note 1 of the Notes of Consolidated Financial Statements for information regarding recently issued accounting standards.

For further information regarding the foregoing matters, see Note 1 (Summary of Significant Accounting Policies), Note 9 (Income Taxes), Note 7 (Energy Supply), Note 10 (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

As discussed above, Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance

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of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding was $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rate on short-term borrowings was 1.8%, 1.5%, and 1.6% during 2016, 2015, and 2014, respectively.

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 entitled Rates and Regulation in Part I, Item 1 (Business) and in Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements, the Company has divested its commodity-related contracts and therefore, further reduced its exposure to commodity risk.

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Item 8. | Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Unitil Corporation

We have audited the accompanying consolidated balance sheets of Unitil Corporation and subsidiaries (the “Company”) as of December 31, 2016 and 2015, and 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, 2016. We also have audited the Company’s internal control over financial reporting as of December 31, 2016 based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. 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.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Unitil Corporation and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, 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, 2016, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Boston, MA

February 2, 2017

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CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except per share data)

Year Ended December 31, |  | 2016 |  |  | 2015 |  |  | 2014 |
Operating Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Gas |  | $ | 181.2 |  |  | $ | 202.6 |  |  | $ | 201.4 |
Electric |  |  | 196.1 |  |  |  | 218.0 |  |  |  | 218.7 |
Other |  |  | 6.1 |  |  |  | 6.2 |  |  |  | 5.7 |
Total Operating Revenues |  |  | 383.4 |  |  |  | 426.8 |  |  |  | 425.8 |
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Cost of Gas Sales |  |  | 77.6 |  |  |  | 100.7 |  |  |  | 104.0 |
Cost of Electric Sales |  |  | 108.0 |  |  |  | 132.5 |  |  |  | 137.9 |
Operation and Maintenance |  |  | 66.3 |  |  |  | 67.1 |  |  |  | 64.6 |
Depreciation and Amortization |  |  | 46.6 |  |  |  | 45.7 |  |  |  | 42.1 |
Taxes Other Than Income Taxes |  |  | 19.6 |  |  |  | 17.7 |  |  |  | 17.2 |
Total Operating Expenses |  |  | 318.1 |  |  |  | 363.7 |  |  |  | 365.8 |
Operating Income |  |  | 65.3 |  |  |  | 63.1 |  |  |  | 60.0 |
Interest Expense, net |  |  | 22.5 |  |  |  | 21.9 |  |  |  | 20.9 |
Other Expense (Income), net |  |  | 0.3 |  |  |  | (0.5 | ) |  |  | 0.4 |
Income Before Income Taxes |  |  | 42.5 |  |  |  | 41.7 |  |  |  | 38.7 |
Income Taxes |  |  | 15.4 |  |  |  | 15.4 |  |  |  | 14.0 |
Net Income Applicable to Common Shares |  | $ | 27.1 |  |  | $ | 26.3 |  |  | $ | 24.7 |
Earnings per Common Share—Basic and Diluted |  | $ | 1.94 |  |  | $ | 1.89 |  |  | $ | 1.79 |
Weighted Average Common Shares Outstanding—(Basic and Diluted) |  |  | 14.0 |  |  |  | 13.9 |  |  |  | 13.8 |

(The accompanying Notes are an integral part of these consolidated financial statements.)

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CONSOLIDATED BALANCE SHEETS (Millions)

ASSETS

December 31, |  | 2016 |  |  | 2015 |
Current Assets: |  |  |  |  |  |  |  |
Cash and Cash Equivalents |  | $ | 5.8 |  |  | $ | 8.7 |
Accounts Receivable, net |  |  | 52.9 |  |  |  | 49.8 |
Accrued Revenue |  |  | 49.5 |  |  |  | 38.4 |
Exchange Gas Receivable |  |  | 8.3 |  |  |  | 11.1 |
Gas Inventory |  |  | 0.6 |  |  |  | 0.8 |
Prepayments and Other |  |  | 14.5 |  |  |  | 11.7 |
Total Current Assets |  |  | 131.6 |  |  |  | 120.5 |
Utility Plant: |  |  |  |  |  |  |  |
Gas |  |  | 629.5 |  |  |  | 576.8 |
Electric |  |  | 437.9 |  |  |  | 408.4 |
Common |  |  | 35.8 |  |  |  | 35.5 |
Construction Work in Progress |  |  | 70.2 |  |  |  | 59.9 |
Utility Plant |  |  | 1,173.4 |  |  |  | 1,080.6 |
Less: Accumulated Depreciation |  |  | 290.0 |  |  |  | 271.7 |
Net Utility Plant |  |  | 883.4 |  |  |  | 808.9 |
Other Noncurrent Assets: |  |  |  |  |  |  |  |
Regulatory Assets |  |  | 104.1 |  |  |  | 99.6 |
Other Assets |  |  | 9.1 |  |  |  | 9.8 |
Total Other Noncurrent Assets |  |  | 113.2 |  |  |  | 109.4 |
TOTAL ASSETS |  | $ | 1,128.2 |  |  | $ | 1,038.8 |

(The accompanying Notes are an integral part of these consolidated financial statements.)

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CONSOLIDATED BALANCE SHEETS (cont.) (Millions, except number of shares)

LIABILITIES AND CAPITALIZATION

December 31, |  | 2016 |  |  | 2015 |
Current Liabilities: |  |  |  |  |  |  |  |
Accounts Payable |  | $ | 32.4 |  |  | $ | 33.3 |
Short-Term Debt |  |  | 81.9 |  |  |  | 42.0 |
Long-Term Debt, Current Portion |  |  | 16.8 |  |  |  | 17.1 |
Regulatory Liabilities |  |  | 10.4 |  |  |  | 15.6 |
Energy Supply Obligations |  |  | 12.0 |  |  |  | 14.6 |
Environmental Obligations |  |  | 0.4 |  |  |  | 1.3 |
Capital Lease Obligations |  |  | 3.0 |  |  |  | 3.1 |
Other Current Liabilities |  |  | 20.0 |  |  |  | 17.3 |
Total Current Liabilities |  |  | 176.9 |  |  |  | 144.3 |
Noncurrent Liabilities: |  |  |  |  |  |  |  |
Retirement Benefit Obligations |  |  | 149.0 |  |  |  | 124.4 |
Deferred Income Taxes, net |  |  | 97.9 |  |  |  | 87.5 |
Cost of Removal Obligations |  |  | 77.0 |  |  |  | 70.1 |
Regulatory Liabilities |  |  | 2.6 |  |  |  | 8.1 |
Capital Lease Obligations |  |  | 8.3 |  |  |  | 11.0 |
Environmental Obligations |  |  | 1.5 |  |  |  | 1.5 |
Other Noncurrent Liabilities |  |  | 5.1 |  |  |  | 3.6 |
Total Noncurrent Liabilities |  |  | 341.4 |  |  |  | 306.2 |
Capitalization: |  |  |  |  |  |  |  |
Long-Term Debt, Less Current Portion |  |  | 316.8 |  |  |  | 305.5 |
Stockholders’ Equity: |  |  |  |  |  |  |  |
Common Equity (Outstanding 14,065,230 and 13,991,430 Shares) |  |  | 240.7 |  |  |  | 237.5 |
Retained Earnings |  |  | 52.2 |  |  |  | 45.1 |
Total Common Stock Equity |  |  | 292.9 |  |  |  | 282.6 |
Preferred Stock |  |  | 0.2 |  |  |  | 0.2 |
Total Stockholders’ Equity |  |  | 293.1 |  |  |  | 282.8 |
Total Capitalization |  |  | 609.9 |  |  |  | 588.3 |
Commitments and Contingencies (Note 8) |  |  |  |  |  |  |  |
TOTAL LIABILITIES AND CAPITALIZATION |  | $ | 1,128.2 |  |  | $ | 1,038.8 |

(The accompanying Notes are an integral part of these consolidated financial statements.)

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions)

Year Ended December 31, |  | 2016 |  |  | 2015 |  |  | 2014 |
Operating Activities: |  |  |  |  |  |  |  |  |  |  |  |
Net Income |  | $ | 27.1 |  |  | $ | 26.3 |  |  | $ | 24.7 |
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and Amortization |  |  | 46.6 |  |  |  | 45.7 |  |  |  | 42.1 |
Deferred Tax Provision |  |  | 15.4 |  |  |  | 11.9 |  |  |  | 14.4 |
Changes in Working Capital Items: |  |  |  |  |  |  |  |  |  |  |  |
Accounts Receivable |  |  | (5.4 | ) |  |  | 10.9 |  |  |  | (8.5 | )
Accrued Revenue |  |  | (11.1 | ) |  |  | 10.1 |  |  |  | 8.1 |
Regulatory Liabilities |  |  | (5.2 | ) |  |  | 6.9 |  |  |  | (1.0 | )
Exchange Gas Receivable |  |  | 2.8 |  |  |  | 3.9 |  |  |  | (4.2 | )
Accounts Payable |  |  | (0.9 | ) |  |  | (10.9 | ) |  |  | 6.1 |
Other Changes in Working Capital Items |  |  | (1.0 | ) |  |  | (2.4 | ) |  |  | 6.5 |
Deferred Regulatory and Other Charges |  |  | (5.0 | ) |  |  | 8.2 |  |  |  | (1.4 | )
Other, net |  |  | 5.0 |  |  |  | 4.5 |  |  |  | (2.8 | )
Cash Provided by Operating Activities |  |  | 68.3 |  |  |  | 115.1 |  |  |  | 84.0 |
Investing Activities: |  |  |  |  |  |  |  |  |  |  |  |
Property, Plant and Equipment Additions |  |  | (98.1 | ) |  |  | (103.9 | ) |  |  | (92.6 | )
Cash Used In Investing Activities |  |  | (98.1 | ) |  |  | (103.9 | ) |  |  | (92.6 | )
Financing Activities: |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from (Repayment of) Short-Term Debt, net |  |  | 39.9 |  |  |  | 12.7 |  |  |  | (30.9 | )
Issuance of Long-Term Debt |  |  | 30.0 |  |  |  | — |  |  |  | 50.0 |
Repayment of Long-Term Debt |  |  | (19.0 | ) |  |  | (7.4 | ) |  |  | (4.4 | )
(Decrease) Increase in Capital Lease Obligations |  |  | (2.8 | ) |  |  | 6.1 |  |  |  | 6.5 |
Net (Decrease) Increase in Exchange Gas Financing |  |  | (2.5 | ) |  |  | (4.0 | ) |  |  | 4.4 |
Dividends Paid |  |  | (20.0 | ) |  |  | (19.6 | ) |  |  | (19.2 | )
Proceeds from Issuance of Common Stock |  |  | 1.3 |  |  |  | 1.3 |  |  |  | 1.2 |
Cash Provided by (Used In) Financing Activities |  |  | 26.9 |  |  |  | (10.9 | ) |  |  | 7.6 |
Net (Decrease) Increase in Cash |  |  | (2.9 | ) |  |  | 0.3 |  |  |  | (1.0 | )
Cash at Beginning of Year |  |  | 8.7 |  |  |  | 8.4 |  |  |  | 9.4 |
Cash at End of Year |  | $ | 5.8 |  |  | $ | 8.7 |  |  | $ | 8.4 |
Supplemental Information: |  |  |  |  |  |  |  |  |  |  |  |
Interest Paid |  | $ | 22.1 |  |  | $ | 22.3 |  |  | $ | 20.8 |
Income Taxes Paid |  | $ | 1.6 |  |  | $ | 1.8 |  |  | $ | 1.2 |
Payments on Capital Leases |  | $ | 3.4 |  |  | $ | 1.1 |  |  | $ | 0.6 |
Capital Expenditures Included in Accounts Payable |  | $ | 0.3 |  |  | $ | 0.4 |  |  | $ | 0.3 |
Non-Cash Additions to Property, Plant and Equipment |  | $ | 3.5 |  |  | $ | — |  |  | $ | — |

(The accompanying Notes are an integral part of these consolidated financial statements.)

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CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Millions, except shares data)

|  | Common Equity |  |  | Retained Earnings |  |  | Total |
Balance at January 1, 2014 |  | $ | 232.1 |  |  | $ | 32.9 |  |  | $ | 265.0 |
Net Income for 2014 |  |  |  |  |  |  | 24.7 |  |  |  | 24.7 |
Dividends ($1.38 per Common Share) |  |  |  |  |  |  | (19.2 | ) |  |  | (19.2 | )
Shares Issued Under Stock Plans |  |  | 1.4 |  |  |  |  |  |  |  | 1.4 |
Issuance of 38,020 Common Shares |  |  | 1.2 |  |  |  |  |  |  |  | 1.2 |
Balance at December 31, 2014 |  |  | 234.7 |  |  |  | 38.4 |  |  |  | 273.1 |
Net Income for 2015 |  |  |  |  |  |  | 26.3 |  |  |  | 26.3 |
Dividends ($1.40 per Common Share) |  |  |  |  |  |  | (19.6 | ) |  |  | (19.6 | )
Shares Issued Under Stock Plans |  |  | 1.5 |  |  |  |  |  |  |  | 1.5 |
Issuance of 36,265 Common Shares |  |  | 1.3 |  |  |  |  |  |  |  | 1.3 |
Balance at December 31, 2015 |  |  | 237.5 |  |  |  | 45.1 |  |  |  | 282.6 |
Net Income for 2016 |  |  |  |  |  |  | 27.1 |  |  |  | 27.1 |
Dividends ($1.42 per Common Share) |  |  |  |  |  |  | (20.0 | ) |  |  | (20.0 | )
Shares Issued Under Stock Plans |  |  | 1.9 |  |  |  |  |  |  |  | 1.9 |
Issuance of 32,095 Common Shares |  |  | 1.3 |  |  |  |  |  |  |  | 1.3 |
Balance at December 31, 2016 |  | $ | 240.7 |  |  | $ | 52.2 |  |  | $ | 292.9 |

(The accompanying Notes are an integral part of these consolidated financial statements.)

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Note 1: Summary of Significant Accounting Policies

Nature of Operations—Unitil Corporation (Unitil or the Company) is a public utility holding company. 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. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources). Usource, Inc. and Usource L.L.C. are wholly-owned subsidiaries of 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 three 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”).

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 three 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, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 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.

Unitil also has three 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) are wholly- owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to a national client base of large commercial and industrial customers.

Basis of Presentation

Principles of Consolidation—The Company’s consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation. Certain reclassifications of prior year data were made in the accompanying financial statements. These reclassifications were made to conform to the current year presentation related to the adoption of new accounting standards.

Use of Estimates—The preparation of 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 requires 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. Actual results could differ from those estimates.

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Fair Value—The Financial Accounting Standards Board (FASB) Codification defines fair value, and establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The three levels of the fair value hierarchy under the FASB Codification are described below:

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—Utility revenues are recognized according to regulations and are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are 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 calculated each month based on estimated customer usage by class and applicable customer rates.

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.

Revenue Recognition—Non-regulated Operations—Usource, Unitil’s competitive energy brokering subsidiary, records energy brokering and advisory service revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period.

Depreciation and Amortization—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the

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Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2016 – 3.49%, 2015 – 3.57% and 2014 – 3.56%.

Stock-based Employee Compensation—Unitil accounts for stock-based employee compensation using the fair value-based method (See Note 6).

Sales and Consumption Taxes—The Company bills its customers sales tax in Massachusetts and Maine and consumption tax in New Hampshire. 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.

Income Taxes—The Company is subject to Federal and State income taxes as well as various other business taxes. This process involves estimating the Company’s current tax liabilities as well as assessing 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 guidance on Income Taxes. The Company classifies penalty 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. 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.

In the first quarter of 2016, the Company adopted ASU 2015-17 which simplifies the presentation of deferred income taxes in a classified statement of financial position. Current generally accepted accounting principles (GAAP) require an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. ASU 2015-17 amends current GAAP to require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position.

For all periods presented in the Consolidated Financial Statements in this Form 10-K for the year ended December 31, 2016, deferred income taxes are reported as “Deferred Income Taxes” in the “Noncurrent Liabilities” section on the Consolidated Balance Sheets. Prior to adoption, the Company reported deferred income taxes in either the “Current Assets” or “Current Liabilities” and “Other Noncurrent Assets” or “Noncurrent Liabilities” sections on the Consolidated Balance Sheets, depending on whether the net current deferred income taxes and net noncurrent deferred income taxes were in an asset or liability position, respectively. The change in presentation for the year ended December 31, 2016 resulted in a reduction of both “Current Assets” and “Noncurrent Liabilities” for all prior periods presented.

Dividends—The Company’s dividend policy is reviewed periodically by 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, 2016 the Company paid quarterly dividends of $0.355 per share, resulting in an annual dividend rate of $1.42 per common share. For the years ended December 31, 2015 and 2014, the Company paid quarterly dividends of $0.350 and $0.345 per common share, respectively, resulting in annual dividend rates of $1.40 and $1.38 per common share, respectively. At its January 2017 meeting, the Unitil

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Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.36 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annual dividend rate to $1.44 per share from $1.42 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 to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. On December 31, 2016 and 2015, the Unitil subsidiaries had deposited $2.8 million and $2.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities maintains an account used to implement its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of December 31, 2016 and 2015.

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 takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, the electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-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.

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below) and unbilled revenues (see “Utility Revenue Recognition” above.) The following table shows the components of Accrued Revenue as of December 31, 2016 and 2015.

Accrued Revenue (millions) |  | December 31, |
| 2016 |  |  | 2015 |
Regulatory Assets—Current |  | $ | 37.9 |  |  | $ | 26.8 |
Unbilled Revenues |  |  | 11.6 |  |  |  | 11.6 |
Total Accrued Revenue |  | $ | 49.5 |  |  | $ | 38.4 |

Exchange Gas Receivable—Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November 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, 2016 and 2015.

Exchange Gas Receivable (millions) |  | December 31, |
| 2016 |  |  | 2015 |
Northern Utilities |  | $ | 7.8 |  |  | $ | 10.3 |
Fitchburg |  |  | 0.5 |  |  |  | 0.8 |
Total Exchange Gas Receivable |  | $ | 8.3 |  |  | $ | 11.1 |

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Gas Inventory—The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of December 31, 2016 and 2015.

Gas Inventory (millions) |  | December 31, |
| 2016 |  |  | 2015 |
Natural Gas |  | $ | 0.3 |  |  | $ | 0.3 |
Propane |  |  | 0.2 |  |  |  | 0.3 |
Liquefied Natural Gas & Other |  |  | 0.1 |  |  |  | 0.2 |
Total Gas Inventory |  | $ | 0.6 |  |  | $ | 0.8 |

Utility Plant—The cost of additions to 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 2.18%, 2.32% and 1.56% in 2016, 2015 and 2014, 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, 2016 and 2015, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $77.0 million and $70.1 million, respectively.

Regulatory Accounting—The Company’s principal business is the distribution 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 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 public utility regulatory commission.

Regulatory Assets consist of the following (millions) |  | December 31, |
| 2016 |  |  | 2015 |
Retirement Benefits |  | $ | 75.9 |  |  | $ | 64.7 |
Energy Supply & Other Regulatory Tracker Mechanisms |  |  | 32.7 |  |  |  | 21.3 |
Deferred Storm Charges |  |  | 9.6 |  |  |  | 15.4 |
Environmental |  |  | 10.8 |  |  |  | 11.2 |
Income Taxes |  |  | 7.3 |  |  |  | 8.5 |
Other |  |  | 5.7 |  |  |  | 5.3 |
Total Regulatory Assets |  | $ | 142.0 |  |  | $ | 126.4 |
Less: Current Portion of Regulatory Assets(1) |  |  | 37.9 |  |  |  | 26.8 |
Regulatory Assets—noncurrent |  | $ | 104.1 |  |  | $ | 99.6 |

| (1) | Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets and in the Accrued Revenue table shown above.

Regulatory Liabilities consist of the following (millions) |  | December 31, |
| 2016 |  |  | 2015 |
Regulatory Tracker Mechanisms |  | $ | 6.2 |  |  | $ | 8.0 |
Gas Pipeline Refund (Note 8) |  |  | 6.8 |  |  |  | 15.7 |
Total Regulatory Liabilities |  |  | 13.0 |  |  |  | 23.7 |
Less: Current Portion of Regulatory Liabilities |  |  | 10.4 |  |  |  | 15.6 |
Regulatory Liabilities—noncurrent |  | $ | 2.6 |  |  | $ | 8.1 |

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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, 2016 are $3.3 million of deferred storm charges to be recovered over the next two and a half years and $8.6 million of environmental and rate case costs and other expenditures to be recovered over 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 impact 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 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.

Derivatives—The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that none of its energy supply contracts, other than the regulatory approved hedging program, described below, qualifies as a derivative instrument under the guidance set forth in the FASB Codification.

The Company has a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service. Prior to April 2013 Northern Utilities purchased natural gas futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to associated delivery months. Beginning in April 2013, the hedging program was redesigned and the Company began purchasing call option contracts on NYMEX natural gas futures contracts for future winter period months. As of December 31, 2015, all futures contracts purchased under the prior program design have been sold and the hedging portfolio now consists entirely of call option contracts.

Any gains or losses resulting from the change in the fair value of these derivatives are passed through to customers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.

As of December 31, 2016 and December 31, 2015, the Company had 2.0 billion and 2.5 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program.

The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. The tables below include disclosure of the derivative assets and liabilities and the recognition of the charges from their corresponding regulatory liabilities and assets, respectively into Cost of Gas Sales. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Regulatory Liabilities and Other Noncurrent Liabilities, respectively on the Company’s Consolidated Balance Sheets.

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Fair Value Amount of Derivative Assets / Liabilities (millions) Offset in Regulatory Liabilities / Assets, as of:

|  |  |  | Fair Value |
Description |  | Balance Sheet Location |  | December 31, 2016 |  |  | December 31, 2015 |
Derivative Assets |  |  |  |  |  |  |  |  |  |
Natural Gas Futures / Options Contracts |  | Prepayments and Other |  | $ | 0.1 |  |  | $ | — |
Natural Gas Futures / Options Contracts |  | Other Noncurrent Assets |  |  | 0.3 |  |  |  | — |
Total Derivative Assets |  |  |  | $ | 0.4 |  |  | $ | — |
Derivative Liabilities |  |  |  |  |  |  |  |  |  |
Natural Gas Futures / Options Contracts |  | Other Current Liabilities |  | $ | — |  |  | $ | — |
Natural Gas Futures / Options Contracts |  | Other Noncurrent Liabilities |  |  | — |  |  |  | — |
Total Derivative Liabilities |  |  |  | $ | — |  |  | $ | — |

|  | Twelve Months Ended December 31, |
|  | 2016 |  |  | 2015 |
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives: |  |  |  |  |  |  |  |
Natural Gas Futures / Options Contracts |  | $ | (0.1 | ) |  | $ | 0.3 |
Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings(1): |  |  |  |  |  |  |  |
Cost of Gas Sales |  | $ | 0.3 |  |  | $ | 0.2 |

| (1) | These amounts are offset in the Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

Investments in Marketable Securities—In 2015, the Company established a trust through which it invests in a variety of equity and fixed income mutual funds. These funds are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (“SERP”) (See further discussion of the SERP in Note 10).

At December 31, 2016 and 2015, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $1.9 million and $0.7 million, respectively, as shown in the table below. 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 Expense, net.

Fair Value of Marketable Securities (millions) |  | December 31, |
|  | 2016 |  |  | 2015 |
Equity Funds |  | $ | 1.1 |  |  | $ | 0.4 |
Fixed Income Funds |  |  | 0.8 |  |  |  | 0.3 |
Total Marketable Securities |  | $ | 1.9 |  |  | $ | 0.7 |

Goodwill and Intangible Assets—As a result of the acquisitions of Northern Utilities and Granite State, the Company recognized a bargain purchase adjustment as a reduction to Utility Plant, to be amortized over a ten year period, beginning with the date of the Acquisitions, as authorized by regulators. As of December 31, 2016, the unamortized balance of the bargain purchase adjustment was $4.7 million, to be amortized over the next two years.

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Energy Supply Obligations—The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets.

|  | December 31, |
Energy Supply Obligations consist of the following: (millions) |  | 2016 |  |  | 2015 |
Current: |  |  |  |  |  |  |  |
Exchange Gas Obligation |  | $ | 7.8 |  |  | $ | 10.3 |
Renewable Energy Portfolio Standards |  |  | 3.9 |  |  |  | 4.0 |
Power Supply Contract Divestitures |  |  | 0.3 |  |  |  | 0.3 |
Total Energy Supply Obligations—Current |  | $ | 12.0 |  |  | $ | 14.6 |
Noncurrent: |  |  |  |  |  |  |  |
Power Supply Contract Divestitures |  | $ | 1.3 |  |  | $ | 1.6 |
Total Energy Supply Obligations |  | $ | 13.3 |  |  | $ | 16.2 |

Exchange Gas Obligation—As discussed above, Northern Utilities enters into gas exchange 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. The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations.

Renewable Energy Portfolio Standards—Renewable Energy Portfolio Standards (RPS) require 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. Due to timing differences between collection of revenue from customers and payment of REC costs to suppliers, Unitil Energy and Fitchburg typically maintain accrued revenue for RPS compliance which is recorded in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits pursuant to Massachusetts legislation, specifically, the Act Relative to Green Communities of 2008 and the Act Relative to Competitively Priced Electricity (2012) in the Commonwealth, and the MDPU’s regulations implementing the legislation. The generating facilities associated with three of these contracts have been constructed and are operating. A recent round of long-term renewable energy procurements was conducted during 2016 and several contracts are expected to be finalized and submitted to MDPU for approval in 2017. Additional procurements are expected in compliance with the Act to Promote Energy Diversity (2016). Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Power Supply Contract Divestitures—Unitil Energy’s and Fitchburg’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. 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. The obligations 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 corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (noncurrent portion).

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Debt Issuance Costs—In the first quarter of 2016, the Company adopted Accounting Standards Update (ASU) 2015-03, which requires entities to present debt issuance costs related to a debt liability as a direct deduction from the carrying amount of that debt liability on the balance sheet as opposed to being presented as a deferred charge, and ASU 2015-15, which adds paragraphs to ASU 2015-03 indicating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to line of credit arrangements as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings on the line of credit arrangement.

For all periods presented in the Consolidated Financial Statements in this Form 10-K for the year ended December 31, 2016, unamortized debt issuance costs related to the Company’s long-term debt are reported on the Consolidated Balance Sheets as a reduction of the carrying value of the related debt. Prior to adoption, the Company reported the unamortized debt issuance costs in “Other Assets” on the Consolidated Balance Sheets. The change in presentation resulted in a reduction of “Other Assets” and “Long-Term Debt” of $2.9 million as of December 31, 2015.

Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (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 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 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, to recognize the future collection of these obligations in electric and gas rates (See Note 10).

Off-Balance Sheet Arrangements—As of December 31, 2016, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases (See Note 5).

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2016, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (See Note 8).

Environmental Matters—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2016, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8, Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Recently Issued Pronouncements—In April and March 2016, the FASB issued ASU 2016-10 and ASU 2016-08, respectively. ASU 2016-10 clarifies the implementation guidance on licensing and the identification of performance obligations considerations included in ASU 2014-09. ASU 2016-08 provides

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amendments to clarify the implementation guidance on principal versus agent considerations included in ASU 2014-09. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The effective date of this pronouncement is for fiscal years beginning after December 15, 2017 with early adoption permitted as of the original effective date. The Company will implement the standard in the first quarter of 2018 on a modified retrospective basis and it is not expected to have a material impact on the Company’s Consolidated Financial Statements.

In March 2016, the FASB issued ASU 2016-09, which provides for improvements to employee share-based payment accounting. ASU 2016-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. ASU 2016-09 simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company does not expect that this new guidance will have a material impact on the Company’s Consolidated Financial Statements.

In February 2016, the FASB issued ASU 2016-02, which replaces the existing guidance in Accounting Standard Codification 840, Leases. ASU 2016-02 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018. ASU 2016-02 requires a dual approach for lessee accounting under which a lessee would account for leases as finance (also referred to as capital) leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use asset and corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the right-of-use asset and for operating leases the lessee would recognize straight-line total lease expense. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01 which addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. A financial instrument is defined as cash, evidence of ownership interest in a company or other entity, or a contract that both: (i) imposes on one entity a contractual obligation either to deliver cash or another financial instrument to a second entity or to exchange other financial instruments on potentially unfavorable terms with the second entity and (ii) conveys to that second entity a contractual right either to receive cash or another financial instruments from the first entity or to exchange other financial instruments on potentially favorable terms with the first entity. This pronouncement is effective for financial statements issued for annual periods beginning after December 15, 2017 and interim periods within those annual periods with earlier application permitted as of the beginning of the fiscal year of adoption. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

In May 2015, the FASB issued ASU 2015-07 which provides authoritative guidance removing the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the statement of financial position. The guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Rather, those disclosures are limited to investments for which the entity has elected to measure the fair value using the practical expedient. The guidance is effective for fiscal years beginning after December 15, 2015 with early adoption permitted. The guidance is required to be applied retrospectively to all periods presented. The Company adopted this new guidance and it did not have a material impact on the Company’s Consolidated Financial Statements.

Other than the pronouncements discussed above, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.

Subsequent Events—The Company evaluates all events or transactions through the date of the related filing. During the period through the date of this filing, the Company did not have any material subsequent events that would result in adjustment to or disclosure in its Consolidated Financial Statements.

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Note 2: Quarterly Financial Information (unaudited; millions, except per share data)

Quarterly earnings per share may not agree with the annual amounts due to rounding and the impact of additional common share issuances. Basic and Diluted Earnings per Share are the same for the periods presented.

|  | Three Months Ended |
|  | March 31, |  |  | June 30, |  |  | September 30, |  |  | December 31, |
|  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |
Total Operating Revenues |  | $ | 125.8 |  |  | $ | 172.2 |  |  | $ | 74.5 |  |  | $ | 77.5 |  |  | $ | 78.8 |  |  | $ | 74.7 |  |  | $ | 104.3 |  |  | $ | 102.4 |
Operating Income |  | $ | 23.4 |  |  | $ | 28.4 |  |  | $ | 9.5 |  |  | $ | 8.9 |  |  | $ | 11.1 |  |  | $ | 7.3 |  |  | $ | 21.3 |  |  | $ | 18.5 |
Net Income (Loss) Applicable to Common |  | $ | 10.9 |  |  | $ | 13.6 |  |  | $ | 2.5 |  |  | $ | 1.7 |  |  | $ | 3.5 |  |  | $ | 1.7 |  |  | $ | 10.2 |  |  | $ | 9.3 |
|  | Per Share Data: |
Earnings Per Common Share |  | $ | 0.78 |  |  | $ | 0.98 |  |  | $ | 0.18 |  |  | $ | 0.12 |  |  | $ | 0.25 |  |  | $ | 0.12 |  |  | $ | 0.73 |  |  | $ | 0.67 |
Dividends Paid Per Common Share |  | $ | 0.355 |  |  | $ | 0.350 |  |  | $ | 0.355 |  |  | $ | 0.350 |  |  | $ | 0.355 |  |  | $ | 0.350 |  |  | $ | 0.355 |  |  | $ | 0.350 |

Note 3: Segment Information

Unitil reports three segments: 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 capital regions 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 three 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 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 three 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 transmission services provided to Northern Utilities and, to a lesser extent, third-party marketers.

Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to a national client base of large commercial and industrial customers. Unitil Realty and Unitil Service provide centralized facilities, operations and administrative services to support the affiliated Unitil companies. Unitil Resources and Usource are included in the Non-Regulated column below.

Unitil Realty, Unitil Service and the holding company are included in the “Other” column of the table below. 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.

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The following table provides significant segment financial data for the years ended December 31, 2016, 2015 and 2014 (millions):

Year Ended December 31, 2016 |  | Gas |  |  | Electric |  |  | Non- Regulated |  |  | Other |  |  | Total |
Revenues |  | $ | 181.2 |  |  | $ | 196.1 |  |  | $ | 6.1 |  |  | $ | — |  |  | $ | 383.4 |
Interest Income |  |  | 0.2 |  |  |  | 0.7 |  |  |  | 0.1 |  |  |  | 0.2 |  |  |  | 1.2 |
Interest Expense |  |  | 13.3 |  |  |  | 8.3 |  |  |  | — |  |  |  | 2.1 |  |  |  | 23.7 |
Depreciation & Amortization Expense |  |  | 21.9 |  |  |  | 23.8 |  |  |  | 0.1 |  |  |  | 0.8 |  |  |  | 46.6 |
Income Tax Expense (Benefit) |  |  | 9.2 |  |  |  | 6.6 |  |  |  | 0.8 |  |  |  | (1.2 | ) |  |  | 15.4 |
Segment Profit |  |  | 14.5 |  |  |  | 11.1 |  |  |  | 1.1 |  |  |  | 0.4 |  |  |  | 27.1 |
Segment Assets |  |  | 645.2 |  |  |  | 441.1 |  |  |  | 6.8 |  |  |  | 35.1 |  |  |  | 1,128.2 |
Capital Expenditures |  |  | 57.0 |  |  |  | 30.1 |  |  |  | — |  |  |  | 11.0 |  |  |  | 98.1 |
Year Ended December 31, 2015 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 202.6 |  |  | $ | 218.0 |  |  | $ | 6.2 |  |  | $ | — |  |  | $ | 426.8 |
Interest Income |  |  | 0.8 |  |  |  | 0.7 |  |  |  | 0.1 |  |  |  | 0.3 |  |  |  | 1.9 |
Interest Expense |  |  | 13.3 |  |  |  | 8.8 |  |  |  | — |  |  |  | 1.7 |  |  |  | 23.8 |
Depreciation & Amortization Expense |  |  | 20.7 |  |  |  | 24.0 |  |  |  | 0.1 |  |  |  | 0.9 |  |  |  | 45.7 |
Income Tax Expense (Benefit) |  |  | 10.2 |  |  |  | 5.5 |  |  |  | 0.8 |  |  |  | (1.1 | ) |  |  | 15.4 |
Segment Profit |  |  | 15.3 |  |  |  | 8.7 |  |  |  | 1.3 |  |  |  | 1.0 |  |  |  | 26.3 |
Segment Assets |  |  | 590.9 |  |  |  | 415.1 |  |  |  | 6.6 |  |  |  | 26.2 |  |  |  | 1,038.8 |
Capital Expenditures |  |  | 64.9 |  |  |  | 29.9 |  |  |  | 0.1 |  |  |  | 9.0 |  |  |  | 103.9 |
Year Ended December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 201.4 |  |  | $ | 218.7 |  |  | $ | 5.7 |  |  | $ | — |  |  | $ | 425.8 |
Interest Income |  |  | 0.3 |  |  |  | 0.6 |  |  |  | 0.1 |  |  |  | 0.3 |  |  |  | 1.3 |
Interest Expense |  |  | 11.5 |  |  |  | 9.1 |  |  |  | — |  |  |  | 1.6 |  |  |  | 22.2 |
Depreciation & Amortization Expense |  |  | 18.8 |  |  |  | 22.3 |  |  |  | — |  |  |  | 1.0 |  |  |  | 42.1 |
Income Tax Expense (Benefit) |  |  | 10.8 |  |  |  | 4.5 |  |  |  | 0.6 |  |  |  | (1.9 | ) |  |  | 14.0 |
Segment Profit |  |  | 15.8 |  |  |  | 6.8 |  |  |  | 0.9 |  |  |  | 1.2 |  |  |  | 24.7 |
Segment Assets |  |  | 564.9 |  |  |  | 412.6 |  |  |  | 6.3 |  |  |  | 13.2 |  |  |  | 997.0 |
Capital Expenditures |  |  | 62.3 |  |  |  | 24.8 |  |  |  | 0.3 |  |  |  | 5.2 |  |  |  | 92.6 |

Note 4: Allowance for Doubtful Accounts

Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2016, 2015 and 2014, the Company recorded provisions for the energy commodity portion of bad debts of $1.6 million, $2.6 million and $2.6 million, respectively. These provisions were recognized in Cost of Gas Sales and Cost of Electric Sales expense as the associated electric and gas utility revenues were billed. Cost of Gas Sales and Cost of Electric Sales costs are recovered from customers through periodic rate reconciling mechanisms. Also, the electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off.

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The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2014—2016 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

|  | Balance at Beginning of Period |  |  | Provision |  |  | Recoveries |  |  | Accounts Written Off |  |  | Balance at End of Period |
Year Ended December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 0.6 |  |  | $ | 2.9 |  |  | $ | 0.3 |  |  | $ | 3.0 |  |  | $ | 0.8 |
Gas |  |  | 0.5 |  |  |  | 1.7 |  |  |  | 0.3 |  |  |  | 2.3 |  |  |  | 0.2 |
Other |  |  | 0.1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 0.1 |
|  | $ | 1.2 |  |  | $ | 4.6 |  |  | $ | 0.6 |  |  | $ | 5.3 |  |  | $ | 1.1 |
Year Ended December 31, 2015 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 1.3 |  |  | $ | 2.5 |  |  | $ | 0.3 |  |  | $ | 3.5 |  |  | $ | 0.6 |
Gas |  |  | 0.4 |  |  |  | 2.8 |  |  |  | 0.4 |  |  |  | 3.1 |  |  |  | 0.5 |
Other |  |  | 0.1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 0.1 |
|  | $ | 1.8 |  |  | $ | 5.3 |  |  | $ | 0.7 |  |  | $ | 6.6 |  |  | $ | 1.2 |
Year Ended December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 1.3 |  |  | $ | 2.9 |  |  | $ | 0.3 |  |  | $ | 3.2 |  |  | $ | 1.3 |
Gas |  |  | 0.2 |  |  |  | 3.1 |  |  |  | 0.3 |  |  |  | 3.2 |  |  |  | 0.4 |
Other |  |  | 0.1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 0.1 |
|  | $ | 1.6 |  |  | $ | 6.0 |  |  | $ | 0.6 |  |  | $ | 6.4 |  |  | $ | 1.8 |

Note 5: 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:

Long-Term Debt and Interest Expense

Long-Term Debt Structure and Covenants—The agreements under which the long-term debt of Unitil and its utility subsidiaries, Unitil Energy, Fitchburg, Northern Utilities, and Granite State, were issued 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 and business combinations, as described below.

The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge 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 have total funded indebtedness less than 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 its 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; including that Unitil Energy have sufficient

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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. The Granite State notes are guaranteed by Unitil for the payment of principal, interest and other amounts payable. This guarantee will terminate if Granite State is reorganized and merges with and into Northern Utilities.

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, 2016, in accordance with the covenants, these subsidiary companies had a combined amount of $199.7 million available for the payment of dividends and Unitil Corporation had $83.4 million available for the payment of dividends. As of December 31, 2016, the Company’s balance in Retained Earnings was $52.2 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2016 for the payment of dividends.

Issuance of Long-Term Debt—On August 1, 2016, Unitil Corporation completed a private placement of $30 million aggregate principal amount of 3.70% Senior Unsecured Notes due August 1, 2026 to institutional investors. The proceeds from the offering were used to repay short-term debt and for general corporate purposes. The Company incurred $0.3 million of costs associated with this issuance and these costs have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

On October 15, 2014, Northern Utilities completed a private placement of $50 million aggregate principal amount of 4.42% Senior Unsecured Notes due October 15, 2044 to institutional investors. The proceeds from the offering were used to repay short-term debt and for general corporate purposes.

Debt Repayment—The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $19.0 million, $7.4 million, and $4.4 million in 2016, 2015, and 2014, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2016 is: 2017 – $17.2 million; 2018 – $30.1 million; 2019 – $18.8 million; 2020 – $19.8 million; 2021 – $8.6 million and thereafter $242.1 million.

Fair Value of Long-Term Debt—Currently, the Company believes that there is no active market in the Company’s debt securities, which have all been sold through private placements. If there were an active

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market for the Company’s debt securities, the fair value of the Company’s long-term debt would be estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. The fair value of the Company’s long-term debt is estimated using Level 2 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.) 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, |
|  | 2016 |  |  | 2015 |
Estimated Fair Value of Long-Term Debt |  | $ | 370.3 |  |  | $ | 345.2 |

Details on long-term debt at December 31, 2016 and 2015 are shown below:

Long-Term Debt (millions) |  | December 31, |
| 2016 |  |  | 2015 |
Unitil Corporation Senior Notes: |  |  |  |  |  |  |  |
6.33% Notes, Due May 1, 2022 |  | $ | 20.0 |  |  | $ | 20.0 |
3.70% Notes, Due August 1, 2026 |  |  | 30.0 |  |  |  | — |
Unitil Energy First Mortgage Bonds: |  |  |  |  |  |  |  |
5.24% Series, Due March 2, 2020 |  |  | 15.0 |  |  |  | 15.0 |
8.49% Series, Due October 14, 2024 |  |  | 9.0 |  |  |  | 12.0 |
6.96% Series, Due September 1, 2028 |  |  | 20.0 |  |  |  | 20.0 |
8.00% Series, Due May 1, 2031 |  |  | 15.0 |  |  |  | 15.0 |
6.32% Series, Due September 15, 2036 |  |  | 15.0 |  |  |  | 15.0 |
Fitchburg Long-Term Notes: |  |  |  |  |  |  |  |
6.75% Notes, Due November 30, 2023 |  |  | 9.5 |  |  |  | 11.4 |
6.79% Notes, Due October 15, 2025 |  |  | 10.0 |  |  |  | 10.0 |
7.37% Notes, Due January 15, 2029 |  |  | 12.0 |  |  |  | 12.0 |
5.90% Notes, Due December 15, 2030 |  |  | 15.0 |  |  |  | 15.0 |
7.98% Notes, Due June 1, 2031 |  |  | 14.0 |  |  |  | 14.0 |
Northern Utilities Senior Notes: |  |  |  |  |  |  |  |
6.95% Senior Notes, Series A, Due December 3, 2018 |  |  | 20.0 |  |  |  | 30.0 |
5.29% Senior Notes, Due March 2, 2020 |  |  | 25.0 |  |  |  | 25.0 |
7.72% Senior Notes, Series B, Due December 3, 2038 |  |  | 50.0 |  |  |  | 50.0 |
4.42% Senior Notes, Due October 15, 2044 |  |  | 50.0 |  |  |  | 50.0 |
Granite State Senior Notes: |  |  |  |  |  |  |  |
7.15% Senior Notes, Due December 15, 2018 |  |  | 6.7 |  |  |  | 10.0 |
Unitil Realty Corp. Senior Secured Notes: |  |  |  |  |  |  |  |
8.00% Notes, Due August 1, 2017 |  |  | 0.4 |  |  |  | 1.1 |
Total Long-Term Debt |  |  | 336.6 |  |  |  | 325.5 |
Less: Unamortized Debt Issuance Costs |  |  | 3.0 |  |  |  | 2.9 |
Total Long-Term Debt, net of Unamortized Debt Issuance Costs |  |  | 333.6 |  |  |  | 322.6 |
Less: Current Portion |  |  | 16.8 |  |  |  | 17.1 |
Total Long-Term Debt, Less Current Portion |  | $ | 316.8 |  |  | $ | 305.5 |

Interest Expense, net—Interest expense is presented in the financial statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and short-term borrowings. In addition, certain reconciling rate mechanisms used by the Company’s distribution operating utilities give rise to regulatory assets (and regulatory liabilities) on which interest is calculated.

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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. 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, net (millions) |
|  | 2016 |  |  | 2015 |  |  | 2014 |
Interest Expense |  |  |  |  |  |  |  |  |  |  |  |
Long-Term Debt |  | $ | 21.8 |  |  | $ | 22.0 |  |  | $ | 20.5 |
Short-Term Debt |  |  | 1.4 |  |  |  | 0.9 |  |  |  | 1.1 |
Regulatory Liabilities |  |  | 0.5 |  |  |  | 0.9 |  |  |  | 0.6 |
Subtotal Interest Expense |  |  | 23.7 |  |  |  | 23.8 |  |  |  | 22.2 |
Interest Income |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  | (0.3 | ) |  |  | (0.7 | ) |  |  | (0.6 | )
AFUDC(1) and Other |  |  | (0.9 | ) |  |  | (1.2 | ) |  |  | (0.7 | )
Subtotal Interest Income |  |  | (1.2 | ) |  |  | (1.9 | ) |  |  | (1.3 | )
Total Interest Expense, net |  | $ | 22.5 |  |  | $ | 21.9 |  |  | $ | 20.9 |

| (1) | AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (as further amended, restated, amended and restated, modified or supplemented from time to time, the “Credit Facility”). The Credit Facility terminates October 4, 2020 and provides for a borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil 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 1.25%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $218.2 million and $140.3 million for the years ended December 31, 2016 and December 31, 2015, respectively. Total gross repayments were $178.3 million and $127.6 million for the years ended December 31, 2016 and December 31, 2015, respectively. In the third quarter of 2016, the Company issued a standby letter of credit for $1.1 million. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2016 and December 31, 2015:

Revolving Credit Facility (millions) |
|  | December 31, |
|  | 2016 |  |  | 2015 |
Limit |  | $ | 120.0 |  |  | $ | 120.0 |
Short-Term Borrowings Outstanding |  | $ | 81.9 |  |  | $ | 42.0 |
Letters of Credit Outstanding |  | $ | 1.1 |  |  | $ | 0.0 |
Available |  | $ | 37.0 |  |  | $ | 78.0 |

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

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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, 2016 and December 31, 2015, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

The weighted average interest rates on all short-term borrowings were 1.8%, 1.5%, and 1.6% during 2016, 2015, and 2014, respectively.

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services.

In April 2014, Unitil Service Corp. entered into a financing arrangement for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of December 31, 2016, there are $2.6 million of current and $7.8 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

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 $9.9 million and $10.8 million of natural gas storage inventory at December 31, 2016 and 2015, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2016, which was payable in January 2017, was $2.1 million and recorded in Accounts Payable at December 31, 2016. The amount of natural gas inventory released in December 2015, which was payable in January 2016, was $0.6 million and recorded in Accounts Payable at December 31, 2015.

Leases

Unitil’s subsidiaries conduct a portion of their operations in leased facilities and also 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, 2016, 2015 and 2014 amounted to $1.8 million, $1.7 million and $1.3 million respectively.

Assets under capital leases amounted to approximately $11.3 million and $15.3 million as of December 31, 2016 and 2015, respectively, less accumulated amortization of $1.0 million and $0.8 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

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The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2016. The payments for capital leases consist of $3.0 million of current Capital Lease Obligations and $8.3 million of noncurrent Capital Lease Obligations on the Company’s Consolidated Balance Sheets as of December 31, 2016. $2.6 million of the current Capital Lease Obligations and $7.8 million of the noncurrent Capital Lease Obligations reflect amounts under a financing arrangement entered into in April 2014 for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation.

Year Ending December 31, (000’s) |  | Operating Leases |  |  | Capital Leases |
2017 |  | $ | 1,274 |  |  | $ | 3,015 |
2018 |  |  | 926 |  |  |  | 2,973 |
2019 |  |  | 582 |  |  |  | 2,935 |
2020 |  |  | 405 |  |  |  | 2,373 |
2021 |  |  | 236 |  |  |  | 2 |
2022 – 2026 |  |  | 132 |  |  |  | — |
Total Payments |  | $ | 3,555 |  |  | $ | 11,298 |

Guarantees

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, 2016, there were approximately $17.9 million of guarantees outstanding and the longest term guarantee extends through August 2017.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of December 31, 2016, the principal amount outstanding for the 8% Unitil Realty notes was $0.4 million, and the principal amount outstanding for the 7.15% Granite State notes was $6.7 million.

Note 6: 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 13,991,430 and 14,065,230 shares of common stock outstanding at December 31, 2015 and December 31, 2016, respectively. The Company has 25,000,000 shares of common stock authorized as of December 31, 2015 and December 31, 2016.

Dividend Reinvestment and Stock Purchase Plan—During 2016, the Company sold 32,095 shares of its common stock, at an average price of $40.55 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.3 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 2015 and 2014, the Company raised $1.3 million and $1.2 million, respectively, through the issuance of 36,265 and 38,020 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common Shares Repurchased, Cancelled and Retired—Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on May 1, 2014, the Company may periodically repurchase shares of its common stock on the open market related to Employee Length of Service Awards and the stock portion of the Directors’ annual retainer. (See Part II, Item 5, for additional information). During 2016, 2015 and 2014, the Company repurchased 1,949, 1,981 and 2,763 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan. The expense recognized by the Company for these repurchases was $0.1 million, $0.1 million and $0.1 million in 2016, 2015 and 2014, respectively.

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During 2016, 2015 and 2014, the Company did not cancel or retire any of its common stock.

Stock-Based Compensation Plans—Unitil maintains a stock plan. The Company accounts for its stock-based compensation plan in accordance with the provisions of the FASB Codification and measures compensation costs at fair value at the date of grant. Details of the plan are as follows:

Stock Plan—The Company maintains the Unitil Corporation Second Amended and Restated 2003 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 (Restricted Shares), or of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

The maximum number of shares available for awards to participants under the Stock Plan is 677,500. The maximum number of shares that may be awarded in any one calendar year to any one participant is 20,000. In the event of any change in capitalization of the Company, the Compensation Committee is authorized to make an equitable adjustment to the number and kind of shares of common stock that may be delivered under the Stock Plan and, in addition, may authorize and make an equitable adjustment to the Stock Plan’s annual individual award limit.

Restricted Shares

Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a 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 an 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.

Restricted Shares issued for 2014 – 2016 in conjunction with the Stock Plan are presented in the following table:

Issuance Date |  | Shares |  | Aggregate Market Value (millions)
1/31/14 |  | 35,500 |  | $1.1
1/26/15 |  | 40,010 |  | $1.5
1/26/16 |  | 43,220 |  | $1.6
4/19/16 |  | 800 |  | <$0.1

There were 93,747 and 70,761 non-vested shares under the Stock Plan as of December 31, 2016 and 2015, respectively. The weighted average grant date fair value of these shares was $35.29 per share and $32.56 per share, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $2.2 million, $1.9 million and $1.4 million in 2016, 2015 and 2014, respectively. At December 31, 2016, there was approximately $1.1 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.4 years. There were 2,315 restricted shares forfeited and zero restricted shares cancelled under the Stock Plan during 2016. On January 30, 2017, there were 34,930 Restricted Shares issued under the Stock Plan with an aggregate market value of $1.6 million.

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Restricted Stock Units

Restricted Stock Units, which are issued to members 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 2016 and 2015 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion) |
|  | 2016 |  |  | 2015 |
|  | Units |  |  | Weighted Average Stock Price |  |  | Units |  |  | Weighted Average Stock Price |
Beginning Restricted Stock Units |  |  | 33,588 |  |  | $ | 31.83 |  |  |  | 23,576 |  |  | $ | 29.90 |
Restricted Stock Units Granted |  |  | 8,505 |  |  | $ | 38.51 |  |  |  | 8,965 |  |  | $ | 36.54 |
Dividend Equivalents Earned |  |  | 1,252 |  |  | $ | 41.00 |  |  |  | 1,047 |  |  | $ | 35.01 |
Restricted Stock Units Settled |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Ending Restricted Stock Units |  |  | 43,345 |  |  | $ | 33.40 |  |  |  | 33,588 |  |  | $ | 31.83 |

Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2016 and 2015 is $0.8 million and $0.5 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

Preferred Stock

There was $0.2 million, or 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2016. There was $0.2 million, or 1,898 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2015. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2016 and December 31, 2015, respectively.

Earnings Per Share

The following table reconciles basic and diluted earnings per share (EPS).

(Millions except shares and per share data) |  | 2016 |  |  | 2015 |  |  | 2014 |
Earnings Available to Common Shareholders |  | $ | 27.1 |  |  | $ | 26.3 |  |  | $ | 24.7 |
Weighted Average Common Shares Outstanding—Basic (000’s) |  |  | 13,990 |  |  |  | 13,917 |  |  |  | 13,843 |
Plus: Diluted Effect of Incremental Shares (000’s) |  |  | 6 |  |  |  | 3 |  |  |  | 4 |
Weighted Average Common Shares Outstanding—Diluted (000’s) |  |  | 13,996 |  |  |  | 13,920 |  |  |  | 13,847 |
Earnings per Share—Basic and Diluted |  | $ | 1.94 |  |  | $ | 1.89 |  |  | $ | 1.79 |

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.

|  | 2016 |  |  | 2015 |  |  | 2014 |
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation |  |  | 600 |  |  |  | 36,941 |  |  |  | — |

Note 7: Energy Supply

Natural Gas Supply

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.

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Northern Utilities’ C&I customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Northern Utilities’ largest and some medium C&I customers purchase their gas supply from third party suppliers, while most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. As of December 2016, 78% of Unitil’s largest New Hampshire gas customers, representing 27% of Unitil’s New Hampshire gas sales and 66% of Unitil’s largest Maine customers, representing 26% of Unitil’s Maine gas sales, are purchasing 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 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 2016, 79% of Unitil’s largest Massachusetts gas customers, representing 30% of Unitil’s Massachusetts gas sales, are purchasing gas supply from third-party suppliers. The approved costs associated 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 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 3.6 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 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.

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 2016, 80% of Unitil’s largest New Hampshire customers, representing 26% of Unitil’s New Hampshire electric energy sales and 85% of Unitil’s largest Massachusetts customers, representing 34% of Unitil’s Massachusetts electric energy 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

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aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 19% of Fitchburg’s customer base and customers in Ashby comprise another 5%.

In New Hampshire, the number of residential customers purchasing from a third party supplier has increased significantly since 2014 and currently stands at 13% of residential customers. Notwithstanding this recent activity, 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’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-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 the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-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. The ISO-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 the ISO-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

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to Green Communities (the “Green Communities Act”) of 2008 and An Act Relative to Competitively Priced Electricity in the Commonwealth of 2012, and the MDPU’s regulations implementing the legislation. The generating facilities associated with three of these contracts have been constructed and are now operating. In 2016, the Company participated in a multi-state procurement for long-term renewable contracts and several contracts from this solicitation are currently under negotiation. These are expected to be finalized and submitted to MDPU for approval in 2017. Additional long-term clean energy contracts are expected in compliance with the Acts of 2016, An Act to Promote Energy Diversity (“Energy Diversity Act”). Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Note 8: Commitments and Contingencies

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 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 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 have 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.

In 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. 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 assets have been principally recovered as of December 31, 2016. The remaining balance of these assets is $1.6 million as of December 31, 2016, including $0.3 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet projected to be recovered in the next year and $1.3 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the next five years. Unitil’s distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Rate Case Activity

Unitil Energy—Base Rates—On April 29, 2016 Unitil Energy filed for an increase in distribution base rates with the New Hampshire Public Utilities Commission (NHPUC). The Company’s filing seeks an increase in base rates of approximately $6.3 million or 3.6 percent above present rates. The Company also requested a long-term rate plan for the annual recovery in future years of the costs associated with utility plant additions. On June 28, 2016 the NHPUC approved a settlement agreement between the Company, Commission Staff and the Office of Consumer Advocate on a $2.4 million temporary rate increase effective July 1, 2016. The temporary rate increase will remain in effect until a permanent rate increase decision is issued. Once a permanent rate is decided, it will be reconciled back to the effective date of the temporary rate increase. The Company is currently engaged in settlement discussions with the Commission and the Office of the Consumer Advocate on the remaining issues in the rate case. Any settlement in the rate case or additional investigation and litigation is expected to be completed for final approval by NHPUC by the end of April, 2017.

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Fitchburg—Base Rates—Electric—On April 29, 2016 the Massachusetts Department of Public Utilities (MDPU) issued an order approving a $2.1 million increase in Fitchburg’s electric base revenue decoupling target, effective May 1, 2016. The MDPU also approved a capital cost recovery mechanism, providing for annual adjustments to target revenues to account for capital spending. In 2016, Fitchburg made its first capital cost adjustment filing documenting its capital investments for calendar year 2015 and requesting $0.5 million of the associated revenue requirements for recovery beginning January 1, 2017. On December 27, 2016 the MDPU approved this filing subject to further investigation and reconciliation.

Fitchburg—Base Rates—Gas—On April 29, 2016, the MDPU issued an order approving a $1.6 million increase in Fitchburg’s gas base revenue decoupling target, effective May 1, 2016.

Fitchburg—Gas Operations—On October 31, 2015, Fitchburg submitted its second annual filing to recover the estimated costs to be incurred in 2016 under its approved 20 year gas system enhancement plan program. The program was established pursuant to legislation that provided for the establishment of comprehensive replacement programs to address aging natural gas pipeline infrastructure. Effective May 1, 2016, the MDPU approved the Company’s request to collect in rates $0.9 million for the estimated costs of its cumulative capital investments in the program through the end of 2016. On October 31, 2016, Fitchburg submitted its third annual filing to recover the estimated cost to be incurred in 2017 under the gas system enhancement plan program, seeking approval to collect an additional $0.9 million to recover the cumulative cost of investments in the program through the end of 2017. In addition, the Company seeks a waiver of the 1.5 percent cap on annual changes in the revenue requirement eligible for recovery. The MDPU’s decision on this request is pending and is expected by the end of April, 2017, for rates effective May 1, 2017.

Northern Utilities—Base Rates—Maine—The rate case settlement in Northern Utilities’ Maine division’s last rate case allowed the Company to implement a Targeted Infrastructure Replacement Adjustment (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. The TIRA has an initial term of four years and covers targeted capital expenditures in 2013 through 2016. The 2016 TIRA, for 2015 expenditures, was filed on February 29, 2016, and provides for an annual increase in distribution base revenue of $1.5 million, effective May 1, 2016, and was approved by the MPUC on April 28, 2016.

Northern Utilities—Targeted Area Build-out Program—Maine—On December 22, 2015 the MPUC approved a new Targeted Area Build-out 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 and is being initially piloted in the City of Saco. 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. This pilot program is planned to be built out over the next three years and has the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco pilot area. The Company will continue to evaluate the success of the program and ways to economically reach new targeted service areas.

Northern Utilities—Base Rates—New Hampshire—Northern Utilities’ New Hampshire division’s last rate case resulted in a settlement agreement providing for an increase of $4.6 million in distribution base revenue and an additional step increase in revenue of $1.4 million for investments in gas mains extensions and infrastructure replacement projects, effective May 1, 2014, and a step adjustment that provided for an annual increase of $1.8 million in revenue effective May 1, 2015.

Northern Utilities—Pipeline Refund—On February 19, 2015, the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers. In New Hampshire, the refund is being credited to all customers over a three year period as directed by the NHPUC. In Maine, the refund has been divided into two parts, as directed by the MPUC. Maine retail customers who purchase their gas directly from Northern Utilities are being credited their portion of the refund over a three year period. The second part of the refund was paid on October 5, 2015 as a one-time lump sum payment directly to marketers who transport gas on Northern Utilities’ distribution

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system. The Company has recorded current and noncurrent Regulatory Liabilities related to these refunds of $4.4 million and $2.4 million, respectively, on its Consolidated Balance Sheets as of December 31, 2016.

Granite State—Base Rates—Granite State has in place a FERC-approved second amended settlement agreement under which it is permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a specific cost cap. On June 24, 2016 Granite State filed for an annual revenue and rate increase under this provision of $0.3 million, effective August 1, 2016. This filing was approved by the FERC on July 13, 2016.

Other Matters

NHPUC Energy Efficiency Resource Standard Proceeding—In May 2015, the NHPUC opened a proceeding to establish an Energy Efficiency Resource Standard (“EERS”), an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. On April 27, 2016, a comprehensive settlement agreement was filed by the parties, including Unitil Energy and Northern Utilities, which was approved by the NHPUC on August 2, 2016. The settlement provides for: extending the 2014-2016 Core program an additional year (through 2017); establishing an EERS; establishing a recovery mechanism to compensate the utilities for lost-revenue related to the EERS programs; and approving the performance incentives and processes for stakeholder involvement, evaluation, measurement and verification, and oversight of the EERS programs.

Unitil Energy—Electric Grid Modernization—In July 2015, the NHPUC opened an investigation into Grid Modernization to address a variety of issues related to Distribution System Planning, Customer Engagement with Distributed Energy Resources, and Utility Cost Recovery and Financial Incentives. The NHPUC has engaged a consultant to direct a Working Group to investigate these issues and to prepare a final report with recommendations for the Commission. The report is expected to be filed in early 2017. Unitil Energy is an active participant in the Working Group. This matter remains pending.

Unitil Energy—Net Metering—Pursuant to legislation that became effective in May 2016, the NHPUC opened a proceeding to consider alternatives to the net metering tariffs currently in place. The legislation requires that a decision on this matter must be issued by the NHPUC by March 2, 2017. The NHPUC approved an extension of the current net metering tariffs on an interim basis until it issues its final decision on June 2, 2017. Unitil Energy is an active participant in this proceeding.

Fitchburg—Electric Operations—On November 17, 2016, Fitchburg submitted its 2016 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were given final approval by the MDPU on December 29, 2016, effective January 1, 2017.

Fitchburg—Service Quality—On March 1, 2016, Fitchburg submitted its 2015 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. Fitchburg’s annual gas and electric divisions’ Service Quality Reports for the periods up through 2014 have all been approved by the MDPU. On September 30, 2016 the MDPU approved Fitchburg’s 2015 electric division Service Quality Report as filed, and on November 22, 2016 the MDPU approved Fitchburg’s 2015 gas division Service Quality Report.

In December 2015, the MDPU issued its final order adopting new and revised Service Quality Guidelines. The Company has generally been able to meet or exceed the performance metrics of the previous Service Quality Guidelines and believes that it will continue to meet or exceed the performance metrics under the new and revised Guidelines.

Fitchburg—Solar Generation—On August 19, 2016, Fitchburg filed a petition with the MDPU seeking approval to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts. The proposal includes a cost recovery mechanism that would share the costs and benefits of

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the project among all Fitchburg customers. On October 27, 2016 a Settlement Agreement supporting the proposal was reached between the Company, the Attorney General of Massachusetts, and the Low-Income Weatherization and Fuel Assistance Program Network. The Settlement Agreement was approved by the MDPU on November 9, 2016. Construction of the solar generating facility is expected to be completed by the end of November 2017.

Fitchburg—Energy Diversity—Governor Baker signed into law H4568 “An Act to Promote Energy Diversity” on August 8, 2016. Among many sections in the bill, the primary provision adds new sections 83c and 83d to the 2008 Green Communities Act. Section 83c requires every electric distribution company (EDC) to jointly and competitively solicit proposals for at least 400 MW’s of offshore wind energy generation by June 30, 2017, as part of a total of 1,600 MW of offshore wind the EDCs are directed to procure by June 30, 2027. The procurement requirement is subject to a determination by the MDPU that the proposed long-term contracts are cost-effective. Section 83d further requires the EDCs to jointly seek proposals for cost effective clean energy (hydro and other) long-term contracts via one or more staggered solicitations, the first of which shall be issued not later than April 1, 2017, for a total of 9,450,000 megawatt-hours by December 31, 2022. Emergency regulations implementing these new provisions, 220 C.M.R. § 23.00 et seq. and 220 C.M.R. § 24.00 et seq. were adopted by the MDPU on December 29, 2016.

Fitchburg—Clean Energy RFP—Pursuant to Section 83a of the Green Communities Act in Massachusetts and similar clean energy directives established in Connecticut and Rhode Island, state agencies and the electric distribution companies in the three states, including Fitchburg, issued an RFP for clean energy resources (including Class I renewable generation and large hydroelectric generation) in November 2015. The RFP sought proposals for clean energy and transmission projects that can deliver new renewable energy to the three states. Project proposals were received in January 2016 and joint evaluation activities are ongoing. Selection of contracts concluded during the fourth quarter of 2016 and contract negotiations are underway for several proposed projects. Fitchburg’s final contracts will be subject to review and approval of the MDPU.

Fitchburg—Other—On September 23, 2016, the Massachusetts Department of Energy Resources (“DOER”) presented its Solar Incentive Straw Proposal in accordance with Chapter 75 of the Acts of 2016 which directed the DOER to develop a statewide solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers throughout the commonwealth. The program would replace the state’s expiring solar incentive program, which uses solar renewable energy credits (“SRECs”) and is known as SREC-2, with a tariff program. The tariff would provide for incentive payments which would be net of energy value (i.e., total tariff rate minus value of energy). The program also includes a variety of tariff adders, including incentives for location, such as landfill site, for off-takers, such as a community aggregation program, and for other technologies, such as behind-the-meter storage. Cost recovery of tariff payments and administrative costs may be made through a fixed, non-bypassable monthly charge to all distribution customers. Comments on the straw proposal were filed on October 28, 2016. The DOER’s implementation schedule includes filing emergency regulations, conducting a rulemaking during winter 2017 to permanently promulgate emergency regulation, MDPU review of model tariffs in spring 2017, and final program implementation in summer 2017.

On May 11, 2016, the MDPU issued an Order commencing a rulemaking proceeding to adopt emergency regulations amending 220 C.M.R. § 18.00 et seq. (“Net Metering Regulations”). Specifically, the MDPU amended its Net Metering Regulations to implement the net metering provisions of An Act Relative to Solar Energy, St. 2016, c. 75, §§ 3-9, and to make additional clerical changes to the Net Metering Regulations. On July 15, 2016, the MDPU issued an order approving Final Net Metering Regulations. The distribution companies were required to submit draft net metering tariffs to comply with the new regulations, which they did on September 1, 2016. On January 6, 2017, the MDPU approved the model tariff and ordered the utilities to file compliance tariffs on January 20, 2017. This matter remains pending.

On August 23, 2016 the MDPU held a technical session to discuss its straw proposal for a monthly minimum reliability contribution (“MMRC”). The purpose of the MMRC is for all distribution company customers to contribute to the fixed costs that ensure the reliability, proper maintenance, and safety of the

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electric distribution system. Parties in the proceeding filed alternative proposals on October 11, 2016. On January 13, 2017, the MDPU issued an order noting that no consensus was reached with respect to its straw proposal. The MDPU stated that it has the authority to consider proposals for an MMRC and sets limitations on when and how it may approve such a proposal, and that it is each distribution company’s discretion whether to file an MMRC proposal and what such a proposal would include.

In December 2013, the MDPU opened an investigation into Modernization of the Electric Grid. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices.” In June 2014, the MDPU issued its first Grid Modernization order, setting forth a requirement that each electric distribution company submit a ten-year strategic Grid Modernization Plan (GMP). As part of the GMP, each company must include a five-year Short-Term Investment Plan (STIP), which must include an approach to achieving advanced metering functionality within five years of the Department’s approval of the GMP. The filing of a GMP is a recurring obligation and must be updated as part of subsequent base distribution rate cases, which by statute must occur no less often than every five years. Capital investments contained in the STIP are eligible for pre-authorization, meaning that the MDPU will not revisit in later filings whether the Company should have proceeded with these investments. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015. These filings are currently under MDPU review and remain pending.

On January 28, 2016 the MDPU approved Fitchburg’s Three-Year Energy Efficiency Plan for 2016-2018, subject to limited modifications and directives in the Order. The Department found that the savings goals included in each Three-Year Plan are reasonable and are consistent with the achievement of all available cost-effective energy efficiency; approved each Program Administrator’s program implementation cost budget for the Three-Year Plans; approved the performance incentive pool, mechanism, and payout rates; found that all proposed energy efficiency programs are cost-effective; found that funding sources are reasonable and that each Program Administrator may recover the funds to implement its energy efficiency plan through its EES; and found that each Program Administrator’s Three-Year Plan is consistent with the Green Communities Act, the Guidelines, and Department precedent.

FERC Transmission Formula Rate Proceeding—On December 28, 2015, FERC issued an order, pursuant to Section 206 of the Federal Power Act, instituting a proceeding concerning the justness and reasonableness of ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that this proceeding results in any changes to the rates being charged, a refund period will begin retroactive to January 4, 2016. The Company does not believe this investigation will have a material adverse impact on the Company’s financial condition or results of operations.

Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, 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 impact on its financial position, operating results or cash flows.

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks 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 remain pending. The Company continues to believe that this suit is without merit and will continue to defend itself vigorously. The Town of Lunenburg filed a separate action in the Court arising out of the December 2008 ice storm. The Court granted the Company’s Motion for Summary Judgment on all counts in December 2016 and dismissed the Town’s complaint. The Court’s decision remains subject to a

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potential motion for reconsideration and appeal. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these suits will not have a material impact 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, 2016, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, we 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 the mid-1800s through the mid-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 (ME DEP) and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Dover, Somersworth, Portsmouth, Lewiston, Portland and Scarborough sites, though on site monitoring continues and it is possible that future activities may be required.

In December 2016, the ME DEP issued a Certificate of Completion for the Portland remediation activities completed in early 2016. Pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the Portland site will be primarily the responsibility of the State of Maine.

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—Fitchburg has worked with the Massachusetts Department of Environmental Protection (MA DEP) 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.

The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site with a corresponding Regulatory Asset recorded to reflect that the recovery of these environmental remediation costs are probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. 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.

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The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the years ended December 31, 2016 and 2015.

Environmental Obligations

|  | (millions) |
|  | Fitchburg |  |  | Northern Utilities |  |  | Total |
|  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |
Total Balance at Beginning of Period |  | $ | 1.2 |  |  | $ | 1.9 |  |  | $ | 1.6 |  |  | $ | 3.6 |  |  | $ | 2.8 |  |  | $ | 5.5 |
Additions |  |  | — |  |  |  | — |  |  |  | 1.8 |  |  |  | 2.9 |  |  |  | 1.8 |  |  |  | 2.9 |
Less: Payments / Reductions |  |  | 1.1 |  |  |  | 0.7 |  |  |  | 1.6 |  |  |  | 4.9 |  |  |  | 2.7 |  |  |  | 5.6 |
Total Balance at End of Period |  | $ | 0.1 |  |  | $ | 1.2 |  |  | $ | 1.8 |  |  | $ | 1.6 |  |  | $ | 1.9 |  |  | $ | 2.8 |
Less: Current Portion |  |  | 0.1 |  |  |  | 0.2 |  |  |  | 0.3 |  |  |  | 1.1 |  |  |  | 0.4 |  |  |  | 1.3 |
Noncurrent Balance at December 31, |  | $ | — |  |  | $ | 1.0 |  |  | $ | 1.5 |  |  | $ | 0.5 |  |  | $ | 1.5 |  |  | $ | 1.5 |

Note 9: Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2016, 2015 and 2014 are shown in the table below:

|  | ($000’s) |
|  | 2016 |  |  | 2015 |  |  | 2014 |
Current Income Tax Provision |  |  |  |  |  |  |  |  |  |  |  |
Federal |  | $ | — |  |  | $ | — |  |  | $ | — |
State |  |  | — |  |  |  | 3,530 |  |  |  | (387 | )
Total Current Income Taxes |  |  | — |  |  |  | 3,530 |  |  |  | (387 | )
Deferred Income Provision |  |  |  |  |  |  |  |  |  |  |  |
Federal |  |  | 11,209 |  |  |  | 12,413 |  |  |  | 10,809 |
State |  |  | 4,145 |  |  |  | (500 | ) |  |  | 3,573 |
Total Deferred Income Taxes |  |  | 15,354 |  |  |  | 11,913 |  |  |  | 14,382 |
Total Income Tax Expense |  | $ | 15,354 |  |  | $ | 15,443 |  |  | $ | 13,995 |

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:

|  | 2016 |  |  | 2015 |  |  | 2014 |
Statutory Federal Income Tax Rate |  |  | 34 | % |  |  | 34 | % |  |  | 34 | %
Income Tax Effects of: |  |  |  |  |  |  |  |  |  |  |  |
State Income Taxes, net |  |  | 4 |  |  |  | 5 |  |  |  | 2 |
Utility Plant Differences |  |  | (1 | ) |  |  | (2 | ) |  |  | (1 | )
Tax Credits |  |  | (1 | ) |  |  | (1 | ) |  |  | — |
Other, net |  |  | — |  |  |  | 1 |  |  |  | 1 |
Effective Income Tax Rate |  |  | 36 | % |  |  | 37 | % |  |  | 36 | %

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Temporary differences which gave rise to deferred tax assets and liabilities in 2016 and 2015, are shown below:

Temporary Differences (000’s) |  | 2016 |  |  | 2015 |
Deferred Tax Assets |  |  |  |  |  |  |  |
Retirement Benefit Obligations |  | $ | 56,804 |  |  | $ | 43,543 |
Net Operating Loss Carryforwards |  |  | 23,921 |  |  |  | 10,500 |
Tax Credit Carryforwards |  |  | 3,365 |  |  |  | 2,677 |
Other, net |  |  | 1,426 |  |  |  | 4,019 |
Total Deferred Tax Assets |  | $ | 85,516 |  |  | $ | 60,739 |
Deferred Tax Liabilities |  |  |  |  |  |  |  |
Utility Plant Differences |  | $ | 169,240 |  |  | $ | 142,412 |
Regulatory Assets & Liabilities |  |  | 10,594 |  |  |  | 5,445 |
Other, net |  |  | 3,629 |  |  |  | 348 |
Total Deferred Tax Liabilities |  |  | 183,463 |  |  |  | 148,205 |
Net Deferred Tax Liabilities |  | $ | 97,947 |  |  | $ | 87,466 |

The Company is subject to federal and state income taxes as well as various other business taxes. 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, the 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.

The Company filed its tax returns for the year ended December 31, 2015 with the Internal Revenue Service in September 2016 and generated additional federal net operating loss (NOL) carryforward assets principally due to current tax repair deductions, tax depreciation and research and development deductions. The Company has recorded in 2016 a benefit of approximately $0.7 million for New Hampshire business enterprise tax credits utilized in filing the Company’s 2015 tax returns. For the year ended December 31, 2016, the Company generated additional $9.9 million and $2.1 million of federal and state NOL carryforward assets, respectively in the calculation of its provisions for income taxes for the period. As of December 31, 2016, the Company had recorded cumulative federal and state NOL carryforward assets of $23.9 million to offset against taxes payable in future periods. If unused, the Company’s NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2016, the Company had $3.4 million of cumulative alternative minimum tax credits, general business tax credit and other state tax credit carryforwards to offset future income taxes payable.

The Company evaluated its tax positions at December 31, 2016 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2013; December 31, 2014; and December 31, 2015.

Note 10: 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.

| • |  | 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 (VEBT), into which it funds contributions to the PBOP Plan.

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| • |  | 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:

|  | 2016 |  |  | 2015 |  |  | 2014 |
Used to Determine Plan costs for years ended December 31: |  |  |  |  |  |  |  |  |
Discount Rate(1) |  |  | 4.30 | % |  |  | 4.00 | % |  |  | 4.80 | %
Rate of Compensation Increase |  |  | 3.00 | % |  |  | 3.00 | % |  |  | 3.00 | %
Expected Long-term rate of return on plan assets |  |  | 8.00 | % |  |  | 8.00 | % |  |  | 8.00 | %
Health Care Cost Trend Rate Assumed for Next Year |  |  | 7.00 | % |  |  | 7.00 | % |  |  | 8.00 | %
Ultimate Health Care Cost Trend Rate |  |  | 4.00 | % |  |  | 4.00 | % |  |  | 4.00 | %
Year that Ultimate Health Care Cost Trend Rate is reached |  |  | 2022 |  |  |  | 2018 |  |  |  | 2018 |
Effect of 1% Increase in Health Care Cost Trend Rate (000’s) |  | $ | 1,352 |  |  | $ | 1,383 |  |  | $ | 989 |
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s) |  | $ | (1,032 | ) |  | $ | (1,040 | ) |  | $ | (771 | )

| (1) | As a result of the addition of a plan participant to the SERP in July 2015, the Company was required to update the discount rate used in determining SERP costs for the remainder of 2015. Based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves at that time, the Company assumed a discount rate of 4.30% for the SERP from July through December of 2015.

Used to Determine Benefit Obligations at December 31: |  |  |  |  |  |  |  |  |
Discount Rate |  |  | 4.10 | % |  |  | 4.30 | % |  |  | 4.00 | %
Rate of Compensation Increase |  |  | 3.00 | % |  |  | 3.00 | % |  |  | 3.00 | %
Health Care Cost Trend Rate Assumed for Next Year |  |  | 8.00 | % |  |  | 7.00 | % |  |  | 7.00 | %
Ultimate Health Care Cost Trend Rate |  |  | 4.00 | % |  |  | 4.00 | % |  |  | 4.00 | %
Year that Ultimate Health care Cost Trend Rate is reached |  |  | 2025 |  |  |  | 2022 |  |  |  | 2018 |
Effect of 1% Increase in Health Care Cost Trend Rate (000’s) |  | $ | 19,471 |  |  | $ | 14,877 |  |  | $ | 15,325 |
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s) |  | $ | (15,153 | ) |  | $ | (11,611 | ) |  | $ | (11,829 | )

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 2016, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $524,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2016 was based on the expected long-term increase in compensation costs for personnel covered by the plans.

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The following table provides the components of the Company’s Retirement plan costs (000’s):

|  | Pension Plan |  |  | PBOP Plan |  |  | SERP |
|  | 2016 |  |  | 2015 |  |  | 2014 |  |  | 2016 |  |  | 2015 |  |  | 2014 |  |  | 2016 |  |  | 2015 |  |  | 2014 |
Service Cost |  | $ | 3,402 |  |  | $ | 3,689 |  |  | $ | 3,006 |  |  | $ | 2,610 |  |  | $ | 2,622 |  |  | $ | 1,988 |  |  | $ | 162 |  |  | $ | 120 |  |  | $ | 57 |
Interest Cost |  |  | 5,945 |  |  |  | 5,392 |  |  |  | 5,092 |  |  |  | 3,232 |  |  |  | 2,918 |  |  |  | 2,686 |  |  |  | 386 |  |  |  | 330 |  |  |  | 272 |
Expected Return on Plan Assets |  |  | (7,257 | ) |  |  | (6,779 | ) |  |  | (6,245 | ) |  |  | (1,205 | ) |  |  | (1,093 | ) |  |  | (920 | ) |  |  | — |  |  |  | — |  |  |  | — |
Prior Service Cost Amortization |  |  | 263 |  |  |  | 265 |  |  |  | 211 |  |  |  | 1,486 |  |  |  | 1,682 |  |  |  | 1,682 |  |  |  | 189 |  |  |  | 85 |  |  |  | 11 |
Actuarial Loss Amortization |  |  | 4,398 |  |  |  | 4,714 |  |  |  | 2,847 |  |  |  | 1,049 |  |  |  | 1,150 |  |  |  | 56 |  |  |  | 375 |  |  |  | 327 |  |  |  | 100 |
Sub-total |  |  | 6,751 |  |  |  | 7,281 |  |  |  | 4,911 |  |  |  | 7,172 |  |  |  | 7,279 |  |  |  | 5,492 |  |  |  | 1,112 |  |  |  | 862 |  |  |  | 440 |
Amounts Capitalized or Deferred |  |  | (3,008 | ) |  |  | (3,397 | ) |  |  | (1,881 | ) |  |  | (3,351 | ) |  |  | (3,423 | ) |  |  | (2,270 | ) |  |  | — |  |  |  | — |  |  |  | — |
NPBC Recognized |  | $ | 3,743 |  |  | $ | 3,884 |  |  | $ | 3,030 |  |  | $ | 3,821 |  |  | $ | 3,856 |  |  | $ | 3,222 |  |  | $ | 1,112 |  |  | $ | 862 |  |  | $ | 440 |

The estimated amortizations related to Actuarial Loss and Prior Service Cost included in the Company’s Retirement plan costs or as a reduction of regulatory assets over the next fiscal year is $5.0 million, $3.5 million and $0.5 million for the Pension, PBOP and SERP plans, respectively.

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over 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 impacted as previously deferred gains or losses are recognized. The Company’s pension expense for the years 2016, 2015 and 2014 before capitalization and deferral was $6.8 million, $7.3 million and $4.9 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2016, 2015 and 2014 would have been $7.7 million, $7.3 million and $4.3 million respectively.

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: |  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |
Plan Assets at Beginning of Year |  | $ | 87,194 |  |  | $ | 86,744 |  |  | $ | 14,174 |  |  | $ | 12,840 |  |  | $ | — |  |  | $ | — |
Actual Return on Plan Assets |  |  | 3,618 |  |  |  | 645 |  |  |  | 792 |  |  |  | (214 | ) |  |  | — |  |  |  | — |
Employer Contributions |  |  | 5,146 |  |  |  | 4,215 |  |  |  | 4,000 |  |  |  | 4,000 |  |  |  | 34 |  |  |  | 40 |
Participant Contributions |  |  | — |  |  |  | — |  |  |  | 61 |  |  |  | 63 |  |  |  | — |  |  |  | — |
Benefits Paid |  |  | (4,900 | ) |  |  | (4,410 | ) |  |  | (2,421 | ) |  |  | (2,515 | ) |  |  | (34 | ) |  |  | (40 | )
Plan Assets at End of Year |  | $ | 91,058 |  |  | $ | 87,194 |  |  | $ | 16,606 |  |  | $ | 14,174 |  |  | $ | — |  |  | $ | — |

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|  | Pension Plan |  |  | PBOP Plan |  |  | SERP |
Change in Plan Assets: |  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |
Change in PBO: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
PBO at Beginning of Year |  | $ | 140,816 |  |  | $ | 136,662 |  |  | $ | 76,249 |  |  | $ | 73,923 |  |  | $ | 9,177 |  |  | $ | 7,965 |
Service Cost |  |  | 3,402 |  |  |  | 3,689 |  |  |  | 2,610 |  |  |  | 2,622 |  |  |  | 162 |  |  |  | 120 |
Interest Cost |  |  | 5,945 |  |  |  | 5,392 |  |  |  | 3,232 |  |  |  | 2,918 |  |  |  | 386 |  |  |  | 330 |
Participant Contributions |  |  | — |  |  |  | — |  |  |  | 61 |  |  |  | 63 |  |  |  | — |  |  |  | — |
Plan Amendments |  |  | — |  |  |  | 474 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 608 |
Benefits Paid |  |  | (4,900 | ) |  |  | (4,410 | ) |  |  | (2,421 | ) |  |  | (2,515 | ) |  |  | (34 | ) |  |  | (40 | )
Actuarial (Gain) or Loss |  |  | 5,176 |  |  |  | (991 | ) |  |  | 16,928 |  |  |  | (762 | ) |  |  | (125 | ) |  |  | 194 |
PBO at End of Year |  | $ | 150,439 |  |  | $ | 140,816 |  |  | $ | 96,659 |  |  | $ | 76,249 |  |  | $ | 9,566 |  |  | $ | 9,177 |
Funded Status: Assets vs PBO |  | $ | (59,381 | ) |  | $ | (53,622 | ) |  | $ | (80,053 | ) |  | $ | (62,075 | ) |  | $ | (9,566 | ) |  | $ | (9,177 | )

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 $75.9 million and $64.7 million at December 31, 2016 and 2015, 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 $135.2 million and $126.8 million as of December 31, 2016 and 2015, respectively. The ABO for the SERP was $6.9 million and $7.0 million as of December 31, 2016 and 2015, respectively. For the PBOP Plan, the ABO and PBO are the same.

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2017 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.

The following table represents employer contributions, participant contributions and benefit payments (000’s).

|  | Pension Plan |  |  | PBOP Plan |  |  | SERP |
|  | 2016 |  |  | 2015 |  |  | 2014 |  |  | 2016 |  |  | 2015 |  |  | 2014 |  |  | 2016 |  |  | 2015 |  |  | 2014 |
Employer Contributions |  | $ | 5,146 |  |  | $ | 4,215 |  |  | $ | 4,191 |  |  | $ | 4,000 |  |  | $ | 4,000 |  |  | $ | 3,650 |  |  | $ | 34 |  |  | $ | 40 |  |  | $ | 53 |
Participant Contributions |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 61 |  |  | $ | 63 |  |  | $ | 59 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Benefit Payments |  | $ | 4,900 |  |  | $ | 4,410 |  |  | $ | 4,246 |  |  | $ | 2,421 |  |  | $ | 2,515 |  |  | $ | 2,184 |  |  | $ | 34 |  |  | $ | 40 |  |  | $ | 53 |

The following table represents estimated future benefit payments (000’s).

Estimated Future Benefit Payments |
|  | Pension |  |  | PBOP |  |  | SERP |
2017 |  | $ | 5,451 |  |  | $ | 2,439 |  |  | $ | 34 |
2018 |  |  | 5,475 |  |  |  | 2,690 |  |  |  | 33 |
2019 |  |  | 6,035 |  |  |  | 2,922 |  |  |  | 578 |
2020 |  |  | 6,288 |  |  |  | 3,138 |  |  |  | 569 |
2021 |  |  | 6,759 |  |  |  | 3,470 |  |  |  | 703 |
2022 - 2026 |  |  | 40,623 |  |  |  | 21,533 |  |  |  | 3,753 |

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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 47% in common stock equities, 37% in fixed income securities, 10% in real estate securities and 6% in a combined equity and debt fund. The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55% in common stock equities and 45% in fixed income securities. The actual investment allocations are shown in the tables below.

Pension Plan |  | Target Allocation 2017 |  |  | Actual Allocation at December 31, |
|  |  | 2016 |  |  | 2015 |  |  | 2014 |
Equity Funds |  |  | 47 | % |  |  | 46 | % |  |  | 46 | % |  |  | 49 | %
Debt Funds |  |  | 37 | % |  |  | 37 | % |  |  | 37 | % |  |  | 36 | %
Real Estate Fund |  |  | 10 | % |  |  | 10 | % |  |  | 11 | % |  |  | 10 | %
Asset Allocation Fund(1) |  |  | 6 | % |  |  | 7 | % |  |  | 6 | % |  |  | 5 | %
Total |  |  |  |  |  |  | 100 | % |  |  | 100 | % |  |  | 100 | %

| (1) | Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

PBOP Plan |  | Target Allocation 2017 |  |  | Actual Allocation at December 31, |
|  | 2016 |  |  | 2015 |  |  | 2014 |
Equity Funds |  |  | 55 | % |  |  | 55 | % |  |  | 53 | % |  |  | 56 | %
Debt Funds |  |  | 45 | % |  |  | 43 | % |  |  | 47 | % |  |  | 44 | %
Other(1) |  |  | 0 | % |  |  | 2 | % |  |  | 0 | % |  |  | 0 | %
Total |  |  |  |  |  |  | 100 | % |  |  | 100 | % |  |  | 100 | %

| (1) | Represents investments being held in cash equivalents as of December 31, 2016 pending transfer into debt and equity funds.

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.00% for 2016. The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually. The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index. 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, 2016 and 2015. Please also see Note 1 for a discussion of the Company’s fair value accounting policy.

| 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 (NAV) 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 to the “Plan Assets at End of Year” line item shown in the “Change in Plan Assets” table above.

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Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2016 and 2015 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) |
2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Pension Plan Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity Funds |  | $ | 42,134 |  |  | $ | 42,134 |  |  | $ | — |  |  | $ | — |
Fixed Income Funds |  |  | 33,924 |  |  |  | 33,924 |  |  |  | — |  |  |  | — |
Asset Allocation Fund |  |  | 6,172 |  |  |  | 6,172 |  |  |  | — |  |  |  | — |
Total Assets in the Fair Value Hierarchy |  | $ | 82,230 |  |  | $ | 82,230 |  |  | $ | — |  |  | $ | — |
Real Estate Fund–Measured at Net Asset Value |  |  | 8,828 |  |  |  |  |  |  |  |  |  |  |  |  |
Total Assets |  | $ | 91,058 |  |  |  |  |  |  |  |  |  |  |  |  |
2015 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Pension Plan Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity Funds |  | $ | 40,124 |  |  | $ | 40,124 |  |  | $ | — |  |  | $ | — |
Fixed Income Funds |  |  | 32,192 |  |  |  | 32,192 |  |  |  | — |  |  |  | — |
Asset Allocation Fund |  |  | 5,527 |  |  |  | 5,527 |  |  |  | — |  |  |  | — |
Total Assets in the Fair Value Hierarchy |  | $ | 77,843 |  |  | $ | 77,843 |  |  | $ | — |  |  | $ | — |
Real Estate Fund–Measured at Net Asset Value |  |  | 9,351 |  |  |  |  |  |  |  |  |  |  |  |  |
Total Assets |  | $ | 87,194 |  |  |  |  |  |  |  |  |  |  |  |  |

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.

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Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2016 and 2015 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) |
2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
PBOP Plan Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mutual Funds: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed Income Funds |  | $ | 7,078 |  |  | $ | 7,078 |  |  | $ | — |  |  | $ | — |
Equity Funds |  |  | 9,128 |  |  |  | 9,128 |  |  |  |  |  |  |  |  |
Total Mutual Funds |  |  | 16,206 |  |  |  | 16,206 |  |  |  |  |  |  |  |  |
Cash Equivalents |  |  | 400 |  |  |  | 400 |  |  |  |  |  |  |  |  |
Total Assets |  | $ | 16,606 |  |  | $ | 16,606 |  |  | $ | — |  |  | $ | — |
2015 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
PBOP Plan Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mutual Funds: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed Income Funds |  | $ | 6,620 |  |  | $ | 6,620 |  |  | $ | — |  |  | $ | — |
Equity Funds |  |  | 7,554 |  |  |  | 7,554 |  |  |  |  |  |  |  |  |
Total Assets |  | $ | 14,174 |  |  | $ | 14,174 |  |  | $ | — |  |  | $ | — |

Employee 401(k) Tax Deferred Savings Plan—The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k) Plan) under Section 401(k) of the Internal Revenue Code and covering substantially all of the Company’s employees. Participants may elect to defer current compensation by contributing to the plan. Employees may direct, at their sole discretion, the investment of their savings plan balances (both the employer and employee portions) into a variety of investment options, including a Company common stock fund.

The Company’s contributions to the 401(k) Plan were $2,304,000, $2,098,000 and $1,877,000 for the years ended December 31, 2016, 2015 and 2014, respectively.

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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, 2016. Based on this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of December 31, 2016 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-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) and 15d-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, 2016, based upon criteria established in the “Internal Control–Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, Unitil management concluded that Unitil’s internal control over financial reporting was effective as of December 31, 2016.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2016, 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 Rules 13a-15(f) and 15d-15(f)) during the fiscal quarter ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, Unitil’s internal control over financial reporting. The Company plans to implement a new customer information system; the project is in process and the timing of the implementation is subject to the completion of user testing and system acceptance.

Item 9B. | Other Information

On February 2, 2017, the Company issued a press release announcing its results of operations for the quarter and year ended December 31, 2016. The press release is furnished with this Annual Report on Form 10-K as Exhibit 99.1.

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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 26, 2017. 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 26, 2017. 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 26, 2017. 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 26, 2017. 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 26, 2017.

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 26, 2017.

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 26, 2017, 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 26, 2017.

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 Committee Pre-Approval Policy” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 26, 2017.

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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

| • |  | Consolidated Statements of Earnings for the years ended December 31, 2016, 2015 and 2014

| • |  | Consolidated Balance Sheets—December 31, 2016 and 2015

| • |  | Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014

| • |  | Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2016, 2015 and 2014

| • |  | 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*
| 2.1 |  |  | Stock Purchase Agreement among Nisource Inc., Bay State Gas Company and Unitil Corporation. |  | Exhibit 2.1 to Form 8-K dated February 15, 2008 (SEC File No. 1-8858)
| 3.1 |  |  | Articles of Incorporation of Unitil Corporation. |  | Exhibit 3.1 to Form S-14 Registration Statement No. 2-93769 dated October 12, 1984
| 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 File No. 1-8858)
| 3.3 |  |  | Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on September 23, 2008. |  | Exhibit 3.3 to Form S-3/A Registration Statement No. 333-152823 dated November 25, 2008
| 3.4 |  |  | Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on April 27, 2011. |  | Exhibit 4.4 to Post-Effective Amendment No. 1 to Form S-3 Registration Statement No. 333-168394, dated January 28, 2014
| 3.5 |  |  | Third Amended and Restated By-Laws of Unitil Corporation. |  | Exhibit 3.1 to Form 8-K dated December 12, 2013 (SEC File No. 1-8858)
| 4.1 |  |  | Twelfth Supplemental Indenture of Unitil Energy Systems, Inc., successor to Concord Electric Company, dated as of December 2, 2002, amending and restating the Concord Electric Company Indenture of Mortgage and Deed of Trust dated as of July 15, 1958. |  | Exhibit 4.1 to Form 10-K for 2002 (SEC File No. 1-8858)

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Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 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 File No. 1-8858)
| 4.3 |  |  | Fitchburg Note Agreement dated January 15, 1999 for the 7.37% Notes due January 15, 2029. |  | Exhibit 4.25 to Form 10-K for 1999 (SEC File No. 1-8858)
| 4.4 |  |  | Fitchburg Note Agreement dated June 1, 2001 for the 7.98% Notes due June 1, 2031. |  | Exhibit 4.6 to Form 10-Q for June 30, 2001 (SEC File No. 1-8858)
| 4.5 |  |  | Unitil Realty Corp. Note Purchase Agreement dated July 1, 1997 for the 8.00% Senior Secured Notes due August 1, 2017. |  | Exhibit 4.22 to Form 10-K for 1997 (SEC File No. 1-8858)
| 4.6 |  |  | Fitchburg Note Agreement dated October 15, 2003 for the 6.79% Notes due October 15, 2025. |  | Exhibit 4.7 to Form 10-K for 2003 (SEC File No. 1-8858)
| 4.7 |  |  | Fitchburg Note Agreement dated December 21, 2005 for the 5.90% Notes due December 15, 2030. |  | **
| 4.8 |  |  | Thirteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of September 26, 2006. |  | **
| 4.9 |  |  | Unitil Corporation Note Purchase Agreement, dated as of May 2, 2007, for the 6.33% Senior Notes due May 1, 2022. |  | **
| 4.10 |  |  | Northern Utilities Note Purchase Agreement, dated as of December 3, 2008, for the 6.95% Senior Notes, Series A due December 3, 2018 and the 7.72% Senior Notes, Series B due December 3, 2038. |  | Exhibit 4.1 to Form 8-K dated December 3, 2008 (SEC File No. 1-8858)
| 4.11 |  |  | Granite State Note Purchase Agreement, dated as of December 15, 2008, for the 7.15% Senior Notes due December 15, 2018. |  | Exhibit 99.1 to Form 8-K dated December 15, 2008 (SEC File No. 1-8858)
| 4.12 |  |  | Northern Utilities Note Purchase Agreement, dated as of March 2, 2010, for the 5.29% Senior Notes, due March 2, 2020. |  | Exhibit 4.1 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
| 4.13 |  |  | Fourteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of March 2, 2010. |  | Exhibit 4.4 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
| 4.14 |  |  | Northern Utilities form of Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October 15, 2044. |  | Exhibit 4.1 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
| 4.15 |  |  | Northern Utilities form of Note issued pursuant to the Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October 15, 2044. |  | Exhibit 4.2 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
| 4.16 |  |  | Note Purchase Agreement dated August 1, 2016 by and among Unitil Corporation and the several purchasers named therein. |  | Exhibit 4.1 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.17 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Metropolitan Life Insurance Company in the principal amount of $11,200,000. |  | Exhibit 4.2 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.18 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $4,000,000. |  | Exhibit 4.3 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)

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Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 4.19 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $3,800,000. |  | Exhibit 4.4 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.20 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $1,000,000. |  | Exhibit 4.5 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.21 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by United of Omaha Life Insurance Company in the principal amount of $5,000,000. |  | Exhibit 4.6 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.22 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by United of Omaha Life Insurance Company in the principal amount of $3,000,000. |  | Exhibit 4.7 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.23 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Companion Life Insurance Company in the principal amount of $2,000,000. |  | Exhibit 4.8 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 10.1 |  |  | Unitil System Agreement dated June 19, 1986 providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H. |  | Exhibit 10.9 to Form 10-K for 1986 (SEC File No. 1-8858)
| 10.2 |  |  | Supplement No. 1 to Unitil System Agreement providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H. |  | Exhibit 10.8 to Form 10-K for 1987 (SEC File No. 1-8858)
| 10.3 |  |  | Transmission Agreement between Unitil Power Corp. and Public Service Company of New Hampshire, effective November 11, 1992. |  | Exhibit 10.6 to Form 10-K for 1993 (SEC File No. 1-8858)
| 10.4*** |  |  | Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement. |  | Exhibit 10.2 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
| 10.5*** |  |  | Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement. |  | Exhibit 10.3 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
| 10.6*** |  |  | Amended and Restated Unitil Corporation Supplemental Executive Retirement Plan effective as of December 31, 2007. |  | Exhibit 10.4 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
| 10.7*** |  |  | Unitil Corporation Management Incentive Plan (amended and restated as of June 5, 2013). |  | Exhibit 10.2 to Form 8-K dated June 5, 2013 (SEC File No. 1-8858)
| 10.8 |  |  | Entitlement Sale and Administrative Services Agreement with Select Energy. |  | Exhibit 10.14 to Form 10-K for 1999 (SEC File No. 1-8858)
| 10.9*** |  |  | Unitil Corporation Second Amended and Restated 2003 Stock Plan |  | Exhibit 10.1 to Form 8-K dated April 19, 2012 (SEC File No. 1-8858)
| 10.10*** |  |  | Form of Restricted Stock Unit Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan |  | Exhibit 4.7 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
| 10.11*** |  |  | Form of Restricted Stock Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan |  | Exhibit 4.8 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012

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Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 10.12*** |  |  | Unitil Corporation Tax Deferred Savings and Investment Plan—Trust Agreement. |  | Exhibit 10.1 to Form 10-Q for September 30, 2004 (SEC File No. 1-8858)
| 10.13*** |  |  | Unitil Corporation Tax Deferred Savings and Investment Plan, as amended to date |  | Exhibit 10.13 to Form 10-K for 2013 (SEC File No. 1-8858)
| 10.14*** |  |  | Employment Agreement effective November 1, 2015 between Unitil Corporation and Robert G. Schoenberger |  | Exhibit 10.1 to Form 8-K dated October 21, 2015 (SEC File No. 1-8858)
| 10.15 |  |  | Amended and Restated Credit Agreement dated as of October 4, 2013 by and among Unitil Corporation and Bank of America, N.A. |  | Exhibit 10.1 to Form 8-K dated October 4, 2013 (SEC File No. 1-8858)
| 10.16 |  |  | First Amendment to Amended and Restated Credit Agreement dated as of July 24, 2015 by and among Unitil Corporation, Bank of America, N.A., and the other parties thereto. |  | Exhibit 10.1 to Form 8-K dated July 24, 2015 (SEC File No. 1-8858)
| 10.17 |  |  | Parent Guaranty of Unitil Corporation for the Granite State 7.15% Senior Notes due December 15, 2018. |  | Exhibit 10.1 to Form 8-K dated December 15, 2008 (SEC File No. 1-8858)
| 10.18*** |  |  | Unitil Corporation Incentive Plan (amended and restated as of January 26, 2015) |  | Exhibit 10.1 to Form 10-Q for March 31, 2015 (SEC File No. 1-8858)
| 10.19*** |  |  | Unitil Corporation—Compensation of Directors. |  | Exhibit 10.18 to Form 10-K for 2014 (SEC File No. 1-8858)
| 10.20*** |  |  | Unitil Corporation—Compensation of Directors. |  | Filed herewith
| 11.1 |  |  | Statement Re: Computation in Support of Earnings per Share for the Company. |  | Filed herewith
| 12.1 |  |  | Statement Re: Computation in Support of Ratio of Earnings to Fixed Charges for the Company. |  | Filed herewith
| 21.1 |  |  | Statement Re: Subsidiaries of Registrant. |  | Filed herewith
| 23.1 |  |  | Consent of Independent Registered Public Accounting Firm. |  | Filed herewith
| 31.1 |  |  | Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  | Filed herewith
| 31.2 |  |  | Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  | Filed herewith
| 31.3 |  |  | Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  | Filed herewith
| 32.1 |  |  | Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |  | Filed herewith
| 99.1 |  |  | Unitil Corporation Press Release Dated February 2, 2017 Announcing Earnings For the Quarter and Year Ended December 31, 2016. |  | Filed herewith

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Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 101.INS |  |  | XBRL Instance Document. |  | Filed herewith
| 101.SCH |  |  | XBRL Taxonomy Extension Schema Document. |  | Filed herewith
| 101.CAL |  |  | XBRL Taxonomy Extension Calculation Linkbase Document. |  | Filed herewith
| 101.DEF |  |  | XBRL Taxonomy Extension Definition Linkbase Document. |  | Filed herewith
| 101.LAB |  |  | XBRL Taxonomy Extension Label Linkbase Document. |  | Filed herewith
| 101.PRE |  |  | XBRL Taxonomy Extension Presentation Linkbase Document. |  | Filed herewith

* | The exhibits referred to in this column by specific designations and dates have heretofore been filed with the Securities and Exchange Commission under such designations and are hereby incorporated by reference.

** | In accordance with Item 601(b)(4)(iii)(A) of Federal Securities 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.

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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.

|  |  |  | UNITIL CORPORATION
Date February 2, 2017 |  |  |  | By |  | /S/ ROBERT G. SCHOENBERGER
|  |  |  |  |  | Robert G. Schoenberger
|  |  |  |  |  | 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
/s/ ROBERT G. SCHOENBERGER Robert G. Schoenberger |  | Principal Executive Officer; Director |  | February 2, 2017
/s/ MARK H. COLLIN Mark H. Collin |  | Principal Financial Officer |  | February 2, 2017
/s/ LAURENCE M. BROCK Laurence M. Brock |  | Principal Accounting Officer |  | February 2, 2017
/s/ ALBERT H. ELFNER, III Albert H. Elfner, III |  | Director |  | February 2, 2017
/s/ M. BRIAN O’SHAUGHNESSY M. Brian O’Shaughnessy |  | Director |  | February 2, 2017
/s/ DR. SARAH P. VOLL Dr. Sarah P. Voll |  | Director |  | February 2, 2017
/s/ EBEN S. MOULTON Eben S. Moulton |  | Director |  | February 2, 2017
/s/ DAVID P. BROWNELL David P. Brownell |  | Director |  | February 2, 2017
/s/ EDWARD F. GODFREY Edward F. Godfrey |  | Director |  | February 2, 2017
/s/ MICHAEL B. GREEN Michael B. Green |  | Director |  | February 2, 2017
/s/ DR. ROBERT V. ANTONUCCI Dr. Robert V. Antonucci |  | Director |  | February 2, 2017
/s/ LISA CRUTCHFIELD Lisa Crutchfield |  | Director |  | February 2, 2017
/s/ DAVID A. WHITELEY David A. Whiteley |  | Director |  | February 2, 2017

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EXHIBIT INDEX

Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 2.1 |  |  | Stock Purchase Agreement among Nisource Inc., Bay State Gas Company and Unitil Corporation. |  | Exhibit 2.1 to Form 8-K dated February 15, 2008 (SEC File No. 1-8858)
| 3.1 |  |  | Articles of Incorporation of Unitil Corporation. |  | Exhibit 3.1 to Form S-14 Registration Statement No. 2-93769 dated October 12, 1984
| 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 File No. 1-8858)
| 3.3 |  |  | Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on September 23, 2008. |  | Exhibit 3.3 to Form S-3/A Registration Statement No. 333-152823 dated November 25, 2008
| 3.4 |  |  | Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on April 27, 2011. |  | Exhibit 4.4 to Post-Effective Amendment No. 1 to Form S-3 Registration Statement No. 333-168394, dated January 28, 2014
| 3.5 |  |  | Third Amended and Restated By-Laws of Unitil Corporation. |  | Exhibit 3.1 to Form 8-K dated December 12, 2013 (SEC File No. 1-8858)
| 4.1 |  |  | Twelfth Supplemental Indenture of Unitil Energy Systems, Inc., successor to Concord Electric Company, dated as of December 2, 2002, amending and restating the Concord Electric Company Indenture of Mortgage and Deed of Trust dated as of July 15, 1958. |  | Exhibit 4.1 to Form 10-K for 2002 (SEC File No. 1-8858)
| 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 File No. 1-8858)
| 4.3 |  |  | Fitchburg Note Agreement dated January 15, 1999 for the 7.37% Notes due January 15, 2029. |  | Exhibit 4.25 to Form 10-K for 1999 (SEC File No. 1-8858)
| 4.4 |  |  | Fitchburg Note Agreement dated June 1, 2001 for the 7.98% Notes due June 1, 2031. |  | Exhibit 4.6 to Form 10-Q for June 30, 2001 (SEC File No. 1-8858)
| 4.5 |  |  | Unitil Realty Corp. Note Purchase Agreement dated July 1, 1997 for the 8.00% Senior Secured Notes due August 1, 2017. |  | Exhibit 4.22 to Form 10-K for 1997 (SEC File No. 1-8858)
| 4.6 |  |  | Fitchburg Note Agreement dated October 15, 2003 for the 6.79% Notes due October 15, 2025. |  | Exhibit 4.7 to Form 10-K for 2003 (SEC File No. 1-8858)
| 4.7 |  |  | Fitchburg Note Agreement dated December 21, 2005 for the 5.90% Notes due December 15, 2030. |  | **
| 4.8 |  |  | Thirteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of September 26, 2006. |  | **
| 4.9 |  |  | Unitil Corporation Note Purchase Agreement, dated as of May 2, 2007, for the 6.33% Senior Notes due May 1, 2022. |  | **

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Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 4.10 |  |  | Northern Utilities Note Purchase Agreement, dated as of December 3, 2008, for the 6.95% Senior Notes, Series A due December 3, 2018 and the 7.72% Senior Notes, Series B due December 3, 2038. |  | Exhibit 4.1 to Form 8-K dated December 3, 2008 (SEC File No. 1-8858)
| 4.11 |  |  | Granite State Note Purchase Agreement, dated as of December 15, 2008, for the 7.15% Senior Notes due December 15, 2018. |  | Exhibit 99.1 to Form 8-K dated December 15, 2008 (SEC File No. 1-8858)
| 4.12 |  |  | Northern Utilities Note Purchase Agreement, dated as of March 2, 2010, for the 5.29% Senior Notes, due March 2, 2020. |  | Exhibit 4.1 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
| 4.13 |  |  | Fourteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of March 2, 2010. |  | Exhibit 4.4 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
| 4.14 |  |  | Northern Utilities form of Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October 15, 2044. |  | Exhibit 4.1 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
| 4.15 |  |  | Northern Utilities form of Note issued pursuant to the Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October 15, 2044. |  | Exhibit 4.2 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
| 4.16 |  |  | Note Purchase Agreement dated August 1, 2016 by and among Unitil Corporation and the several purchasers named therein. |  | Exhibit 4.1 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.17 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Metropolitan Life Insurance Company in the principal amount of $11,200,000. |  | Exhibit 4.2 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.18 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $4,000,000. |  | Exhibit 4.3 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.19 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $3,800,000. |  | Exhibit 4.4 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.20 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $1,000,000. |  | Exhibit 4.5 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.21 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by United of Omaha Life Insurance Company in the principal amount of $5,000,000. |  | Exhibit 4.6 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.22 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by United of Omaha Life Insurance Company in the principal amount of $3,000,000. |  | Exhibit 4.7 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 4.23 |  |  | 3.70% Senior Note, Series 2016, dated as of August 1, 2016 purchased by Companion Life Insurance Company in the principal amount of $2,000,000. |  | Exhibit 4.8 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
| 10.1 |  |  | Unitil System Agreement dated June 19, 1986 providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H. |  | Exhibit 10.9 to Form 10-K for 1986 (SEC File No. 1-8858)
| 10.2 |  |  | Supplement No. 1 to Unitil System Agreement providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H. |  | Exhibit 10.8 to Form 10-K for 1987 (SEC File No. 1-8858)

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##### Table of Contents

Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 10.3 |  |  | Transmission Agreement between Unitil Power Corp. and Public Service Company of New Hampshire, effective November 11, 1992. |  | Exhibit 10.6 to Form 10-K for 1993 (SEC File No. 1-8858)
| 10.4*** |  |  | Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement. |  | Exhibit 10.2 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
| 10.5*** |  |  | Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement. |  | Exhibit 10.3 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
| 10.6*** |  |  | Amended and Restated Unitil Corporation Supplemental Executive Retirement Plan effective as of December 31, 2007. |  | Exhibit 10.4 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
| 10.7*** |  |  | Unitil Corporation Management Incentive Plan (amended and restated as of June 5, 2013). |  | Exhibit 10.2 to Form 8-K dated June 5, 2013 (SEC File No. 1-8858)
| 10.8 |  |  | Entitlement Sale and Administrative Services Agreement with Select Energy. |  | Exhibit 10.14 to Form 10-K for 1999 (SEC File No. 1-8858)
| 10.9*** |  |  | Unitil Corporation Second Amended and Restated 2003 Stock Plan |  | Exhibit 10.1 to Form 8-K dated April 19, 2012 (SEC File No. 1-8858)
| 10.10*** |  |  | Form of Restricted Stock Unit Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan |  | Exhibit 4.7 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
| 10.11*** |  |  | Form of Restricted Stock Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan |  | Exhibit 4.8 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
| 10.12*** |  |  | Unitil Corporation Tax Deferred Savings and Investment Plan—Trust Agreement. |  | Exhibit 10.1 to Form 10-Q for September 30, 2004 (SEC File No. 1-8858)
| 10.13*** |  |  | Unitil Corporation Tax Deferred Savings and Investment Plan, as amended to date |  | Exhibit 10.13 to Form 10-K for 2013 (SEC File No. 1-8858)
| 10.14*** |  |  | Employment Agreement effective November 1, 2015 between Unitil Corporation and Robert G. Schoenberger |  | Exhibit 10.1 to Form 8-K dated October 21, 2015 (SEC File No. 1-8858)
| 10.15 |  |  | Amended and Restated Credit Agreement dated as of October 4, 2013 by and among Unitil Corporation and Bank of America, N.A. |  | Exhibit 10.1 to Form 8-K dated October 4, 2013 (SEC File No. 1-8858)
| 10.16 |  |  | First Amendment to Amended and Restated Credit Agreement dated as of July 24, 2015 by and among Unitil Corporation, Bank of America, N.A., and the other parties thereto. |  | Exhibit 10.1 to Form 8-K dated July 24, 2015 (SEC File No. 1-8858)
| 10.17 |  |  | Parent Guaranty of Unitil Corporation for the Granite State 7.15% Senior Notes due December 15, 2018. |  | Exhibit 10.1 to Form 8-K dated December 15, 2008 (SEC File No. 1-8858)

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##### Table of Contents

Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 10.18*** |  |  | Unitil Corporation Incentive Plan (amended and restated as of January 26, 2015) |  | Exhibit 10.1 to Form 10-Q for March 31, 2015 (SEC File No. 1-8858)
| 10.19*** |  |  | Unitil Corporation—Compensation of Directors. |  | Exhibit 10.18 to Form 10-K for 2014 (SEC File No. 1-8858)
| 10.20*** |  |  | Unitil Corporation—Compensation of Directors. |  | Filed herewith
| 11.1 |  |  | Statement Re: Computation in Support of Earnings per Share for the Company. |  | Filed herewith
| 12.1 |  |  | Statement Re: Computation in Support of Ratio of Earnings to Fixed Charges for the Company. |  | Filed herewith
| 21.1 |  |  | Statement Re: Subsidiaries of Registrant. |  | Filed herewith
| 23.1 |  |  | Consent of Independent Registered Public Accounting Firm. |  | Filed herewith
| 31.1 |  |  | Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  | Filed herewith
| 31.2 |  |  | Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  | Filed herewith
| 31.3 |  |  | Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  | Filed herewith
| 32.1 |  |  | Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |  | Filed herewith
| 99.1 |  |  | Unitil Corporation Press Release Dated February 2, 2017 Announcing Earnings For the Quarter and Year Ended December 31, 2016. |  | Filed herewith
| 101.INS |  |  | XBRL Instance Document. |  | Filed herewith
| 101.SCH |  |  | XBRL Taxonomy Extension Schema Document. |  | Filed herewith
| 101.CAL |  |  | XBRL Taxonomy Extension Calculation Linkbase Document. |  | Filed herewith
| 101.DEF |  |  | XBRL Taxonomy Extension Definition Linkbase Document. |  | Filed herewith
| 101.LAB |  |  | XBRL Taxonomy Extension Label Linkbase Document. |  | Filed herewith
| 101.PRE |  |  | XBRL Taxonomy Extension Presentation Linkbase Document. |  | Filed herewith

* | The exhibits referred to in this column by specific designations and dates have heretofore been filed with the Securities and Exchange Commission under such designations and are hereby incorporated by reference.

** | In accordance with Item 601(b)(4)(iii)(A) of Federal Securities 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

97