10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

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 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  x

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  x

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  x    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  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 amendments to this Form 10-K  x

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  x      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 Exchange Act).    Yes  ¨    No  x

Based on the closing price of the registrant’s common stock on June 30, 2013, the aggregate market value of common stock held by non-affiliates of the registrant was $392,955,494.

The number of the registrant’s common shares outstanding was 13,842,877 as of January 24, 2014.

Documents Incorporated by Reference:

Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held on April 22, 2014 are incorporated by reference into Part III of this Report

UNITIL CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2013

Table of Contents

Item	Description	Page
	PART I
1.	Business		1
	Unitil Corporation		1
	Operations		2
	Rates and Regulation		4
	Natural Gas Supply		5
	Electric Power Supply		6
	Environmental Matters		7
	Employees		8
	Available Information		8
	Investor Information		9
1A.	Risk Factors		10
1B.	Unresolved Staff Comments		16
2.	Properties		16
3.	Legal Proceedings		17
4.	Mine Safety Disclosures		17
	PART II
5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities		18
6.	Selected Financial Data		21
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)		22
7A.	Quantitative and Qualitative Disclosures about Market Risk		42
8.	Financial Statements and Supplementary Data		43
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		83
9A.	Controls and Procedures		83
9B.	Other Information		83
	PART III
10.	Directors, Executive Officers and Corporate Governance		84
11.	Executive Compensation		84
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		84
13.	Certain Relationships and Related Transactions, and Director Independence		84
14.	Principal Accountant Fees and Services		84
	PART IV
15.	Exhibits and Financial Statement Schedules		85
	Signatures		89

CAUTIONARY STATEMENT

This report and the documents incorporated by reference into this report contain statements that 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 energy commodities and transmission capacity and the Company’s ability to recover energy commodity costs in its rates;

• customers’ preferred energy sources;

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

• the Company’s stranded electric generation and generation-related supply costs and the Company’s ability to recover stranded 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;

• the Company’s energy brokering customers’ performance under multi-year energy brokering contracts; and

• increased competition.

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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 178,300 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 102,400 electric customers and 75,900 natural gas customers.

	Customers Served as of December 31, 2013
	Residential		Commercial & Industrial (C&I)		Total
Electric:
Unitil Energy		62,818		10,970		73,788
Fitchburg		24,874		3,731		28,605
Total Electric		87,692		14,701		102,393
Natural Gas:
Northern Utilities		43,659		16,646		60,305
Fitchburg		13,957		1,658		15,615
Total Natural Gas		57,616		18,304		75,920
Total Customers Served		145,308		33,005		178,313

Unitil’s distribution utilities had an investment in Net Utility Plant of $665.6 million at December 31, 2013. Unitil’s total operating revenue was $366.9 million in 2013. Unitil’s operating revenue is substantially derived from regulated natural gas and electric distribution utility operations.

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A fifth utility subsidiary, Unitil Power, 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.

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 $170.4 million for 2013, which represents about 46% 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. As a result of a restructuring of the gas utility industry, Northern Utilities’ commercial and industrial (C&I) customers and Fitchburg’s residential and C&I customers have the opportunity to purchase their natural gas supplies from third-party energy supply vendors. Most customers, however, continue to purchase such supplies through Northern Utilities and Fitchburg under regulated rates and tariffs. Northern Utilities and Fitchburg purchase natural gas from unaffiliated wholesale suppliers and recover the actual costs of these supplies on a pass-through basis through reconciling rate mechanisms that are periodically adjusted.

Natural gas is supplied and distributed by Northern Utilities to approximately 60,300 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’ 2013 gas operating revenue was $133.7 million, of which approximately 39% was derived from residential firm sales and 61% from commercial/industrial firm sales.

Natural gas is supplied and distributed by Fitchburg to approximately 15,600 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 2013 gas operating revenue was $31.1 million, of which approximately 52% was derived from residential firm sales and 48% from commercial/industrial 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

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provides Northern Utilities with interconnection to major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State had operating revenue of $5.6 million for 2013. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, to third-party marketers.

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 $190.7 million for 2013, which represents about 52% 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. As a result of electric industry restructuring in New Hampshire and Massachusetts, Unitil’s customers are free to contract for their supply of electricity with third-party suppliers. The distribution utilities continue to deliver that supply of electricity over their distribution systems. Both Unitil Energy and Fitchburg supply electricity to those customers who do not obtain their supply from third-party suppliers, with the approved costs associated with electricity supplied by the distribution utilities being recovered on a pass-through basis under periodically adjusted rates.

Unitil Energy distributes electricity to approximately 73,800 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 2013 electric operating revenue was $136.7 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 supplied and distributed by Fitchburg to approximately 28,600 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 and printing, publishing and associated industries and educational institutions. Fitchburg’s 2013 electric operating revenue was $54.0 million, of which approximately 53% was derived from residential sales and 47% 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 heating season as a result of higher sales of natural gas due to cold weather. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the 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 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 $5.8 million in 2013.

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The results of Unitil’s other non-utility subsidiaries, Unitil Service and Unitil Realty, and the holding company, are included in the Company’s consolidated results of operations. The results of these non-utility operations are principally derived from income earned on short-term investments and real property owned for Unitil’s and its subsidiaries’ use and are reported, after intercompany eliminations, in Other segment income. For segment information, see Note 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

Northern Utilities—Base Rates—Maine—On December 27, 2013, the Maine Public Utilities Commission (MPUC) approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine operations, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed to implement a Targeted Infrastructure Replacement Adjustment (TIRA) to provide for annual adjustments to distribution base rates to recover costs associated with the Company’s investments in targeted operational and safety-related infrastructure replacement and upgrade projects. The TIRA will have an initial term of four years, and covers expenditures in each of the Calendar Years 2013, 2014, 2015, and 2016.

Northern Utilities—Base Rates—New Hampshire—In April 2013, Northern Utilities’ New Hampshire operations filed a rate case with the New Hampshire Public Utilities Commission (NHPUC) requesting approval to increase its natural gas distribution base rates by $5.2 million in gas distribution base revenue or approximately 9.4 percent over test year operating revenue. The filing included a proposed multi-year rate plan that included cost tracking mechanisms to recover future capital costs associated with Northern Utilities’ infrastructure replacements and safety and reliability improvements to the natural gas distribution system. Northern Utilities has been authorized to implement temporary rates to collect a $2.5 million increase (annualized) in gas distribution revenue, effective July 1, 2013. The Company is currently in settlement discussions with the NHPUC and expects a final rate order from the NHPUC in the first half of 2014. Once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were established, July 1, 2013.

Unitil Energy—Base Rates—Unitil Energy’s second step increase of $2.8 million went into effect on May 1, 2013, which included rate increases to recover capital improvements, increased spending for its vegetation management and reliability enhancement programs and an increase in its storm reserve fund. On April 26, 2011, the NHPUC approved a rate settlement that extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with a series of step adjustments to increase revenue in future years to support Unitil Energy’s continued capital improvements to its distribution system. Unitil Energy’s first step increase was approved as filed, effective May 1, 2012.

Granite State—Base Rates—In June 2013, Granite State submitted to the FERC its latest incremental annual rate adjustment, in the amount of $0.4 million, with rates effective August 1, 2013. The FERC approved the increase on July 30, 2013. Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file a limited Section 4 rate case that includes incremental annual rate adjustments to recover the revenue requirements for certain specified future capital cost additions to gas transmission plant projects.

Fitchburg—Electric Base Rates Filed—In July 2013, Fitchburg filed a rate case with the Massachusetts Department of Public Utilities (MDPU) requesting approval to increase its electric distribution rates. The Company requested an increase of $6.7 million in electric base revenue or approximately 11.5 percent over test year operating revenue. Included in the amount of this annual increase is approximately $2.1 million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to three severe storms, Tropical Storm Irene, the October 2011 snowstorm and Superstorm Sandy. The filing includes a proposed modified revenue decoupling mechanism by means of an annual revenue adjustment mechanism by either a capital cost tracker mechanism or a multi-year rate plan featuring a revenue cap index. The filing also includes a proposal to establish a major storm reserve fund to address the costs of future major storms by collecting $2.8 million per year through a reconciling storm

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recovery adjustment factor beginning January 1, 2015. The rate case filing is subject to regulatory review with hearings scheduled throughout January 2014 and approval with final rate orders expected in the second quarter of 2014.

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, in addition to earning 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.

As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most of Unitil’s customers have the opportunity to purchase their electricity or natural gas supplies from third-party energy supply vendors. Most customers, however, continue to purchase such supplies through the distribution utilities under regulated energy rates and tariffs. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual approved costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

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 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 have the opportunity to purchase their natural gas supply from third-party gas supply vendors, and third-party supply is prevalent among Northern Utilities’ larger C&I customers. Most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. Fitchburg’s residential and C&I business customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors. Many large and some medium C&I customers purchase their supplies 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. The approved costs associated with the acquisition of such wholesale natural gas supplies for 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.

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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 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), to truck supplies to storage facilities within Northern Utilities’ service territory.

Northern Utilities has available under firm contract 100,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 3.4 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 of one year or less, as well as from producers and marketers on the spot market. Fitchburg arranges for gas delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, or in the case of LNG or liquefied propane gas (LPG), to truck supplies to storage facilities within Fitchburg’s service territory.

Fitchburg has available under firm contract 14,057 MMbtu per day of year-round and seasonal transportation and 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

The restructuring of the electric utility industry in New Hampshire required the divestiture of Unitil’s power supply arrangements and the procurement of replacement supplies, which provided the flexibility for migration of customers to and from utility energy service. 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, Inc. (ISO-NE) markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s customers.

As a result of restructuring of the electric utility industry in Massachusetts and New Hampshire, Unitil’s customers in both New Hampshire and Massachusetts have the opportunity to purchase their electric supply from competitive third-party energy suppliers. As of December 2013, 69% of Unitil’s largest New Hampshire customers, representing 23% of total New Hampshire electric energy sales, and 78% of Unitil’s largest Massachusetts customers, representing 31% of total Massachusetts electric energy sales, are purchasing their electric power supply in the competitive market. However, most residential and small commercial customers continue to purchase their electric supply through Unitil’s distribution utilities under regulated energy rates and tariffs. We believe that the concentration of the competitive retail market on higher use customers has been a common experience throughout the New England electricity market.

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 with various wholesale suppliers.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. On July 31, 2012, the NHPUC approved Unitil Energy’s request to modify its Default Service solicitation to a process where 100% of the Default Service requirements are acquired for six months. Unitil Energy completed the transition to this procurement strategy in late 2013. Currently, Unitil Energy Default Service power supply contracts for small, medium and large customers are acquired every six months, are 12 months in duration and provide 100% of the supply requirements.

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Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service energy supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential, 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 its pro-rata share of 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 in the Commonwealth, and the MDPU’s regulations implementing the legislation. The facility associated with one of these contracts has been constructed and is operating. The other contracts are pending approval by the MDPU as well as subsequent facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg will recover its 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 believes it is in material compliance with applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2013, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you 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.

Northern Utilities Manufactured Gas Plant Sites—Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites that were operated from the

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mid-1800s through the mid-1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. This program has also documented the presence of MGP sites in Lewiston and Portland, Maine and a former MGP disposal site in Scarborough, Maine. Northern Utilities has worked with the environmental regulatory agencies in both New Hampshire and Maine to address environmental concerns with these sites.

Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, Lewiston and Scarborough sites. The site in Portland has been investigated and remedial activities are ongoing with the most recent phase completed in December 2013. Although Northern Utilities recently finalized a long-term lease on the Portland property, the State of Maine has announced its intention to acquire the site in the short-term for the expansion of the adjacent marine terminal. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs pending either State acquisition or until all remedial activities are completed.

The NHPUC and MPUC have approved the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over a seven-year amortization period. For Northern Utilities’ Maine division, the MPUC authorized the recovery of environmental remediation costs over a rolling five-year amortization schedule.

Fitchburg’s Manufactured Gas Plant Site—Fitchburg is in the process of seeking regulatory approval to implement a permanent remediation solution at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts. 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, without carrying costs.

The Company’s ultimate liability for future environmental remediation costs, including MGP site costs, may vary from estimates, which may be adjusted as new information or future developments become available. 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.

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, 2013, the Company and its subsidiaries had 477 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of December 31, 2013, a total of 158 employees of certain of the Company’s subsidiaries were represented by labor unions. There are 45 union employees of Fitchburg covered by a collective bargaining agreement (CBA) which expires on May 31, 2019; 34 union employees of Northern Utilities’ New Hampshire division covered by a separate CBA which expires on June 5, 2014; 37 union employees of Northern Utilities’ Maine division and Granite State covered by a separate CBA which expires on March 31, 2017; 37 union employees of Unitil Energy Systems covered by a separate CBA which expires on May 31, 2018 and 5 union employees of Unitil Service Corp. covered by a separate CBA which expires on May 31, 2016. The agreements 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 its website, the Company makes available, free of charge, its Securities and Exchange Commission (SEC) fillings, 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. These reports are made available free of charge through the Investors section of Unitil’s website.

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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 Tuesday, April 22, 2014, at 10:30 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.

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.

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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 power to impose financial penalties and other sanctions on the Company, which could adversely affect the Company’s financial condition or 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, 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 or 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 or 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 or 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 or results or operations could be adversely affected.

In addition, certain regulatory authorities have the power 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 or results of operations.

Severe weather events have struck, and may strike, the New England region, causing extensive damage to the Company’s utility operations and the loss of service to significant numbers of the Company’s customers. If the Company is unable to recover a significant amount of storm costs in its rates, or if the Company’s recovery of storm costs in its rates is significantly delayed, then the Company’s financial condition or results of operations could be adversely affected.

The New England region in which the Company operates has been and will likely continue to be struck from time to time by severe weather events, including snow, wind and ice storms. These storms have in the past caused extensive damage to the Company’s utility operations and loss of service to the Company’s customers, and future severe weather events are likely to do so as well. If the Company cannot recover a significant amount of storm costs in its rates, or if the recovery of these costs is significantly delayed, then the Company’s financial condition and results of operations could be adversely affected. Please see the sections entitled Regulatory Matters in Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operation) and Regulatory Matters in Note 8 (Commitments and Contingencies) to the Company’s Consolidated Financial Statements for a more detailed discussion of the effects of severe weather events on the Company’s financial condition and results of operations.

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As a result of electric industry restructuring, the Company has a significant amount of stranded electric generation and power supply related supply costs. If the Company is unable to recover a significant amount of stranded costs in its rates, or if the Company’s recovery of stranded costs in its rates is significantly delayed, then the Company’s financial condition or results of operations could be adversely affected.

The stranded electric generation and power supply related supply costs resulting from the implementation of electric industry restructuring mandated by the states of New Hampshire and Massachusetts are recovered by the Company on a pass-through basis through periodically reconciled rates. Any unrecovered balance of stranded costs is deferred for future recovery as a regulatory asset. Such regulatory assets are subject to periodic regulatory review and approval for recovery in future periods.

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. The remaining balance of these assets, to be recovered principally over the next year, is $12.7 million as of December 31, 2013, including $10.2 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet. Unitil’s distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

If the Company is unable to recover a significant amount of such stranded costs in its rates, or if the Company’s recovery of such stranded costs in its rates is significantly delayed, then the Company’s financial condition or results or operations could be adversely affected. Please see the sections entitled Regulatory Matters—Overview in Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Regulatory Matters—Overview in Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for a more detailed discussion of the effect of various regulatory matters on the Company and its subsidiaries.

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 or 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 territory directly affects the Company’s business. As a result, adverse changes in the economy may adversely affect the Company’s financial condition or results or operations.

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 or 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 debt under its current credit facility, as needed. 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 or 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 or results or operations.

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Declines in the valuation of capital markets could require the Company to make substantial cash contributions to cover its pension obligations. If the Company is unable to recover a significant amount of pension obligation costs in its rates, or if the Company’s recovery of pension obligation costs in its rates is significantly delayed, then the Company’s financial condition or results of operations could be adversely affected.

The amount of cash contributions the Company is required to make in respect of its pension 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 of its pension 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 a such costs in rates or if such recovery is significantly delayed. Please see the section entitled Critical Accounting Policies—Pension Benefit Obligations in 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.

Increases in interest rates could increase the Company’s interest expense and adversely affect the Company’s financial condition or results of operations.

The Company and its utility subsidiaries have ongoing capital expenditure and cash funding requirements, which they frequently fund by issuing short-term debt and long-term debt.

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 or results of operations. As of December 31, 2013, the Company had approximately $60.2 million in short-term debt outstanding under its revolving credit facility.

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 or results of operations. See the sections entitled Liquidity, Commitments and Capital Requirements in 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 the effects of changes in interest rates on the Company.

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 or results of operations.

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 or 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 or results of operations. See the sections entitled Liquidity, Commitments and Capital Requirements in 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.

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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 or 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 60% 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 or 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.

In addition, the Company’s results of operations generally reflect seasonality. In particular, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher (due to heating-related requirements), and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.

Long-term global climate change could adversely affect customer demand or cause extreme weather events that could disrupt the Company’s electric and natural gas distribution services.

Milder winter and summer temperatures that may be due to long-term global climate change could cause a decrease in the amount of natural gas and electricity sold by the Company. Conversely, colder winter temperatures and warmer summer temperatures that may be due to long-term global climate change could cause an increase in the amount of natural gas and electricity sold by the Company.

In addition, extreme weather events (such as hurricanes and severe winter storms) that may be related to long-term global climate change could damage facilities or result in increased service interruptions and outages and increase the Company’s operations and maintenance costs. If the Company is unable to recover a significant amount of such costs in its rates, or if the Company’s recovery of such costs in its rates is significantly delayed, then the Company’s financial condition or results or operations may be adversely affected.

The Company is unable to predict the impacts on its financial condition and results or operations due to changes in weather that may be related to long-term global climate change.

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 agencies.

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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.

The Company’s current annual dividend is $1.38 per share of common stock, payable quarterly. However, the Company’s Board of Directors reviews Unitil’s dividend policy periodically in light of the factors referred to above, and the Company cannot assure the amount of dividends, if any, that may be paid in the future.

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 and 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 and mechanical problems. 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 and results of operations.

The Company maintains insurance against some, but not all, of these risks and losses in accordance with customary industry practice. The location of pipelines, storage facilities and electric distribution equipment near populated areas (including residential areas, commercial business centers and industrial sites) could increase the level of damages associated with these hazards and operating risks. The occurrence of any of these events could adversely affect the Company’s financial position or results of operations.

The Company’s 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 or 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 or 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 provide electric or natural gas distribution services to its customers for an extended period, which could adversely affect the Company’s financial condition and results of operations.

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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 to establish a “Smart Grid” to monitor and manage the nation’s interconnected electric transmission grids. 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, viruses, human errors, acts of war or terrorism and other reasons. If the Company’s information technology systems were to fail or be materially impaired, the Company might be unable to fulfill critical business functions and serve its customers, which could have a material effect on the Company’s financial conditions, results of operations, and cash flows.

In addition, in the ordinary course of its business, the Company collects and retains sensitive information 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 could subject the Company to penalties for violation of applicable privacy laws or claims from third parties and could harm the Company’s reputation.

Public utility companies are subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and increased regulatory oversight or other sanctions.

Utility companies, including the Company’s distribution utility subsidiaries, have a large consumer customer base and, as a result, are subject to public criticism focused on the reliability of their distribution services and the speed with which they are able to respond to outages caused by storm damage or other unanticipated events. Adverse publicity of this nature may render legislatures, public utility commissions and other regulatory authorities and government officials, less likely to view public utility companies in a favorable light, and may cause the Company to be susceptible to less favorable legislative and regulatory outcomes or increased regulatory oversight. Unfavorable regulatory outcomes can include more stringent laws and regulations governing the Company’s operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material negative impact on the Company’s results of operations, cash flow and financial condition.

The Company’s business could be adversely affected if it is unable to retain its existing customers or attract new customers.

The success of the Company’s business depends, in part, on its ability to maintain and increase its customer base. The Company’s failure to maintain or increase its customer base could adversely affect its financial condition and results of operations.

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The Company’s energy brokering 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.

The Company’s non-regulated energy brokering business 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. The Company’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.

Our stock price may decline when our results decline or when events occur that are adverse to us or our industry.

You can expect the market price of our common stock to decline when our results of operations decline or at any time when events actually or potentially adverse to us or the natural gas and electric industry occur.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

As of December 31, 2013, 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.

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

Natural Gas Operations

	Northern Utilities				Fitchburg		Granite State		Total
Description	NH		ME
Underground Natural Gas Mains—Miles		514		536		274		—		1,324
Natural Gas Transmission Pipeline—Miles		—		—		—		86		86
Service Pipes		21,854		19,985		10,949		—		52,788

Electric Operations

Description	Unitil Energy		Fitchburg		Total
Primary Transmission and Distribution Pole Miles—Overhead		1,266		442		1,708
Conduit Distribution Bank Miles—Underground		210		60		270
Transmission and Distribution Substations		33		16		49
Capacity of Substations		215,100 kVa		441,700 kVa		656,800 kVa

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 a liquid natural gas (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 (74%), coated and wrapped cathodically protected steel (18%), cast/wrought iron (5%), and unprotected bare and coated steel (3%). Fitchburg’s gas mains are primarily made up of steel (49%), polyethylene plastic (27%), and cast iron (24%).

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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 telephone 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.

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 the Company’s financial position.

In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (Fitchburg), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman 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 Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit would now proceed with only the twelve named plaintiffs seeking damages; however, the plaintiffs have appealed this decision to the Massachusetts Supreme Judicial Court (the “SJC”). The SJC has accepted the matter for review. The Town of Lunenburg has also filed a separate action in Massachusetts Worcester County Superior Court arising out of the December 2008 ice storm. The parties to this action have agreed to put this matter on hold pending the decision of the Supreme Judicial Court in Bellermann. The Company continues to believe these suits are without merit and will continue to defend itself vigorously.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Shareholder 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, 2013, there were 1,518 shareholders of record of our common stock.

Common Stock Data

Dividends per Common Share	2013		2012
1st Quarter	$	0.345	$	0.345
2nd Quarter		0.345		0.345
3rd Quarter		0.345		0.345
4th Quarter		0.345		0.345
Total for Year	$	1.38	$	1.38

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

	2013				2012
Price Range of Common Stock	High/Ask		Low/Bid		High/Ask		Low/Bid
1st Quarter	$	28.31	$	26.01	$	29.00	$	26.25
2nd Quarter	$	30.82	$	27.65	$	27.40	$	24.76
3rd Quarter	$	32.07	$	27.78	$	27.98	$	26.23
4th Quarter	$	31.94	$	29.00	$	27.51	$	24.15

Information regarding securities authorized for issuance under our equity compensation plans, as of December 31, 2013, 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
Second Amended and Restated 2003 Stock Plan(1)		N/A		N/A		492,436
Equity compensation plans not approved by security holders
N/A		N/A		N/A		N/A
Total		N/A		N/A		492,436

NOTES: (also see Note 6 to the accompanying Consolidated Financial Statements)

⁽¹⁾ The Second Amended and Restated 2003 Stock Plan, formerly known as the Restricted Stock Plan (the Plan), was approved by shareholders in April 2003, 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 187,085 shares of restricted stock have been awarded to Plan participants through December 31, 2013, of which 2,021 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, 2008 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, 2008.

Comparative Five-Year Total Returns

NOTE:

⁽¹⁾ The graph above assumes $100 invested on December 31, 2008, 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

Holders of record of the Company’s common stock, no par value, and the Company’s employees who hold shares of the Company’s common stock through the Company’s Tax Deferred Savings and Investment Plan are eligible to participate in the Company’s Dividend Reinvestment and Stock Purchase Plan (DRSPP). Pursuant to the DRSPP, participants may automatically reinvest dividends on the Company’s common stock and/or invest cash payments in shares of the Company’s common stock. The Company recently discovered that it was not eligible to use the registration statement on Form S-3 that it previously filed with the SEC to register the shares of its common stock to be issued under the DRSPP when it continued to sell shares to participants in the DRSPP during 2013. During 2013, the Company sold a total of approximately 22,403 shares of common stock to participants in the DRSPP for an aggregate of $652,083. These sales were not registered under the Securities Act of 1933, as amended, and may not have been made pursuant to an exemption from registration under the Securities Act of 1933, as amended. The Company used, or will use, the proceeds from these sales for general corporate purposes.

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 by the Company on March 28, 2013, 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 $91,800 in value of shares have been purchased or, if sooner, on March 28, 2014.

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, 2013.

	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
10/1/13 – 10/31/13		2,044	$	29.34		2,044	$	16,079
11/1/13 – 11/30/13		—		—		—	$	16,079
12/1/13 – 12/31/13		260	$	29.91		260	$	8,303
Total		2,304	$	29.40		2,304

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Item 6. Selected Financial Data

For the Years Ended December 31,	2013			2012			2011			2010			2009
(all data in millions except shares, % and per share data) Consolidated Statements of Earnings:
Operating Revenue	$	366.9		$	353.1		$	352.8		$	358.4		$	367.0
Operating Income		53.5			47.5			47.2			32.5			31.5
Interest Expense, net		18.8			18.1			20.4			18.1			15.8
Other Expense (Income), net		0.4			0.2			0.4			0.3			0.3
Income Before Income Taxes		34.3			29.2			26.4			14.1			15.4
Income Taxes		12.7			11.0			10			4.5			5.4
Net Income		21.6			18.2			16.4			9.6			10.0
Dividends on Preferred Stock		—			0.1			0.1			0.1			0.1
Earnings Applicable to Common Shareholders	$	21.6		$	18.1		$	16.3		$	9.5		$	9.9
Balance Sheet Data (as of December 31,):
Utility Plant (Original Cost)	$	909.1		$	833.2		$	776.9		$	728.4		$	682.7
Total Assets	$	920.6		$	892.3		$	856.1		$	806.8		$	766.0
Capitalization:
Common Stock Equity	$	265.0		$	260.4		$	191.7		$	189.0		$	193.1
Preferred Stock		0.2			0.2			2.0			2.0			2.0
Long-Term Debt, less current portion		284.8			287.3			287.8			288.3			248.9
Total Capitalization	$	550.0		$	547.9		$	481.5		$	479.3		$	444.0
Current Portion of Long-Term Debt	$	2.5		$	0.5		$	0.5		$	0.5		$	0.4
Short-term Debt	$	60.2		$	49.4		$	87.9		$	66.8		$	64.5
Capital Structure Ratios (as of December 31,):
Common Stock Equity		48	%		47	%		40	%		39	%		43	%
Preferred Stock		1	%		1	%		1	%		1	%		1	%
Long-Term Debt		51	%		52	%		59	%		60	%		56	%
Earnings Per Share Data:
Earnings Per Average Share	$	1.57		$	1.43		$	1.50		$	0.88		$	1.03
Common Stock Data:
Shares of Common Stock—(Diluted Weighted Average Outstanding, 000’s)		13,775			12,672			10,883			10,824			9,647
Dividends Paid Per Share	$	1.38		$	1.38		$	1.38		$	1.38		$	1.38
Book Value Per Share (Year-End)	$	19.14		$	18.90		$	17.50		$	17.35		$	17.83
Electric and Gas Sales:
Electric Distribution Sales (Millions kWh)		1,668.3			1,653.8			1,682.1			1,691.1			1,618.8
Firm Natural Gas Distribution Sales (Millions Therms)		200.7			181.3			186.9			172.9			178.7
Customers Served (Year-End):
Electric:
Residential		87,692			87,062			86,780			86,344			86,055
Commercial & Industrial		14,701			14,612			14,574			14,514			14,443
Total Electric		102,393			101,674			101,354			100,858			100,498
Natural Gas:
Residential		57,616			56,745			55,663			54,944			54,208
Commercial & Industrial		18,304			16,977			16,232			15,807			15,763
Total Natural Gas		75,920			73,722			71,895			70,751			69,971

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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 178,300 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 102,400 electric customers and 75,900 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 $665.6 million at December 31, 2013. Unitil’s total revenue was $366.9 million in 2013, 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 consulting services to a national client base of large commercial and industrial customers. Usource’s total revenues were $5.8 million in 2013. 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.

Rate Case Activity

Northern Utilities—Base Rates—Maine—On December 27, 2013, the Maine Public Utilities Commission (MPUC) approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine operations, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed to implement a Targeted Infrastructure Replacement Adjustment (TIRA) to provide for annual adjustments to distribution base rates to recover costs associated with the Company’s investments in targeted operational and safety-related infrastructure replacement and upgrade projects. The TIRA will have an initial term of four years, and covers expenditures in each of the Calendar Years 2013, 2014, 2015, and 2016.

Northern Utilities—Base Rates—New Hampshire—In April 2013, Northern Utilities’ New Hampshire operations filed a rate case with the New Hampshire Public Utilities Commission (NHPUC)

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requesting approval to increase its natural gas distribution base rates by $5.2 million in gas distribution base revenue or approximately 9.4 percent over test year operating revenue. The filing included a proposed multi-year rate plan that included cost tracking mechanisms to recover future capital costs associated with Northern Utilities’ infrastructure replacements and safety and reliability improvements to the natural gas distribution system. Northern Utilities has been authorized to implement temporary rates to collect a $2.5 million increase (annualized) in gas distribution revenue, effective July 1, 2013. The Company is currently in settlement discussions with the NHPUC and expects a final rate order from the NHPUC in the first half of 2014. Once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were established, July 1, 2013.

Unitil Energy—Base Rates—Unitil Energy’s second step increase of $2.8 million went into effect on May 1, 2013, which included rate increases to recover capital improvements, increased spending for its vegetation management and reliability enhancement programs and an increase in its storm reserve fund. On April 26, 2011, the NHPUC approved a rate settlement that extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with a series of step adjustments to increase revenue in future years to support Unitil Energy’s continued capital improvements to its distribution system. Unitil Energy’s first step increase was approved as filed, effective May 1, 2012.

Granite State—Base Rates—In June 2013, Granite State submitted to the FERC its latest incremental annual rate adjustment, in the amount of $0.4 million, with rates effective August 1, 2013. The FERC approved the increase on July 30, 2013. Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file a limited Section 4 rate case that includes incremental annual rate adjustments to recover the revenue requirements for certain specified future capital cost additions to gas transmission plant projects.

Fitchburg—Electric Base Rates Filed—In July 2013, Fitchburg filed a rate case with the Massachusetts Department of Public Utilities (MDPU) requesting approval to increase its electric distribution rates. The Company requested an increase of $6.7 million in electric base revenue or approximately 11.5 percent over test year operating revenue. Included in the amount of this annual increase is approximately $2.1 million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to three severe storms, Tropical Storm Irene, the October 2011 snowstorm and Superstorm Sandy. The filing includes a proposed modified revenue decoupling mechanism by means of an annual revenue adjustment mechanism by either a capital cost tracker mechanism or a multi-year rate plan featuring a revenue cap index. The filing also includes a proposal to establish a major storm reserve fund to address the costs of future major storms by collecting $2.8 million per year through a reconciling storm recovery adjustment factor beginning January 1, 2015. The rate case filing is subject to regulatory review with hearings scheduled throughout January 2014 and approval with final rate orders expected in the second quarter of 2014.

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 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, in addition to earning a return on their capital investment in utility assets. In addition,

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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.

As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most of Unitil’s customers have the opportunity to purchase their electricity or natural gas supplies from third-party energy supply vendors. Most customers, however, continue to purchase such supplies through the distribution utilities under regulated energy rates and tariffs. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual approved costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

On August 1, 2011, the MDPU issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of Fitchburg. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of its electricity or natural gas sales. One of the primary purposes of decoupling is to eliminate the disincentive a utility otherwise has to encourage and promote energy conservation programs designed to reduce energy usage. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011 forward, distribution revenues for Fitchburg based on established revenue targets. The established revenue targets for the gas division may be subject to periodic adjustments to account for customer growth and special contracts, for which RDM does not apply. The difference between distribution revenue amounts billed to customers and the targeted amounts is recognized as increases or decreases in Accrued Revenue which form the basis for future reconciliation adjustments in periodically resetting rates for future cash recoveries from, or credits to, customers. The Company estimates that RDM applies to approximately 27% and 11% of its annual electric and natural gas sales volumes, respectively. As a result, the sales margins resulting from those sales are no longer sensitive to weather and economic factors. The Company’s other electric and natural gas distribution utilities are not subject to RDM.

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 heating season as a result of higher sales of natural gas due to cold weather. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the 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 in both the winter and summer seasons.

On May 16, 2012, the Company sold 2,760,000 shares of its common stock at a price of $25.25 per share in a registered public offering. The Company used the net proceeds of approximately $65.7 million from this offering to make equity capital contributions to its regulated utility subsidiaries, repay short-term debt and for general corporate purposes. Overall, the results of operations and earnings reflect the higher number of average shares outstanding year over year.

Net Income and EPS Overview

2013 Compared to 2012—The Company’s Earnings Applicable to Common Shareholders were $21.6 million and $1.57 per share for the year ended December 31, 2013, an improvement of $3.5 million and $0.14 per share compared to 2012. Results for 2013 were driven by increases in natural gas and electric sales margins, partially offset by higher utility operating costs. Also, earnings per share reflect the sale of 2,760,000 common shares on May 16, 2012, discussed above.

Natural gas sales margins were $85.2 million in 2013, an increase of $9.0 million compared to 2012. Natural gas sales margins in 2013 were positively affected by higher therm unit sales, a growing customer base and higher base distribution rates. Therm sales of natural gas increased 10.7% in 2013 compared to

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2012, driven by the colder winter weather in 2013 compared to 2012 coupled with strong growth in the number of new residential and commercial and industrial (C&I) customers. Based on weather data collected in the Company’s service areas, there were 16% more Heating Degree Days in 2013 compared to 2012. Weather-normalized gas therm sales, excluding decoupled sales, in 2013 are estimated to be up 4.2% compared to 2012. Approximately 11% of Unitil’s natural gas therm sales are decoupled and changes in these sales due to the weather do not affect sales margins.

Electric sales margins were $76.2 million in 2013, an increase of $4.3 million compared to 2012, reflecting higher electric kilowatt-hour (kWh) sales and higher electric base distribution rates. Electric kWh sales increased 0.9% in 2013 compared to 2012, driven by the colder winter weather in 2013 compared to 2012 coupled with the addition of new residential and C&I customers. Electric sales margins in 2013 also reflect higher recovery of $1.3 million of vegetation management and electric reliability enhancement expenditures as well as an increase of $0.7 million in the recovery of major storm restoration costs, which are offset by a corresponding increase in operating expenses, discussed below.

Approximately 27% of Unitil’s electric kWh sales are decoupled and changes in these sales due to the weather do not affect sales margins.

Total Operation & Maintenance (O&M) expenses increased $4.0 million in 2013 compared to 2012. The change in O&M expenses reflects higher utility operating costs of $1.9 million, higher compensation and benefit costs of $1.0 million, higher professional fees of $0.9 million and higher all other O&M expenses, net of $0.2 million. The increase in utility operating costs includes $1.3 million in new spending on vegetation management programs which is recovered through cost tracker rate mechanisms that result in a corresponding and offsetting increase in revenue and margin in the period.

Depreciation and Amortization expense increased $2.6 million in 2013 compared to 2012, reflecting higher depreciation of $1.6 million on normal utility plant additions, higher amortization of major storm restoration costs of $0.7 million and an increase in all other amortization of $0.3 million. The increase in major storm restoration cost amortization is also recovered in current electric rates.

Taxes Other Than Income Taxes increased $1.0 million in 2013 compared to 2012, reflecting higher local property taxes on higher levels of utility plant in service.

Other Expense (Income), net increased $0.2 million in 2013 compared to 2012.

Interest Expense, net increased $0.7 million in 2013 compared to 2012 reflecting lower net interest income on regulatory assets, partially offset by lower average rates on lower short-term borrowings.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $5.8 million in 2013, an increase of $0.3 million compared to 2012. 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 increased $1.7 million in 2013 due to higher pre-tax earnings in 2013 compared to 2012.

In 2013, Unitil’s annual common dividend was $1.38, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January 2014 meeting, the Unitil Board of Directors declared a quarterly dividend on the Company’s common stock of $0.345 per share.

2012 Compared to 2011—The Company’s Earnings Applicable to Common Shareholders were $18.1 million for the year ended December 31, 2012, an increase of $1.8 million, or 11%, over the $16.3 million the Company earned in 2011. Earnings per common share (EPS) were $1.43 for 2012 compared to $1.50 per share in 2011. As discussed above, the 2012 EPS reflect the higher number of average shares outstanding year over year. The results for 2012 were positively affected by higher natural gas and electric sales margins due to higher distribution rates and new customer growth. Margins were negatively affected in 2012 by the effect on sales of fluctuations in seasonal weather conditions year over year. The Company estimates that the mild weather in 2012 negatively impacted earnings for the gas division by about $1.6

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million, or $0.13 per share, and the electric division by about $0.1 million, or $0.01 per share. According to the National Oceanic and Atmospheric Administration, 2012 was the warmest year on record for the northeast region of the United States, in which the Company’s service areas are located.

A more detailed discussion of the Company’s 2013 and 2012 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 increased 10.7% in 2013 compared to 2012. Sales to residential and C&I customers increased 14.4% and 9.8%, respectively, in 2013 compared to 2012. The increase in gas therm sales in the Company’s utility service areas was driven by the colder winter weather in 2013 compared to 2012 coupled with strong growth in the number of new residential and C&I customers. Based on weather data collected in the Company’s service areas, there were 16% more Heating Degree Days in 2013 compared to 2012. Weather-normalized gas therm sales, excluding decoupled sales, in 2013 are estimated to be up 4.2% compared to 2012. Approximately 11% of the Company’s total therm sales of natural gas are decoupled and changes in these sales do not affect sales margins. Under revenue decoupling for Fitchburg, distribution revenues, which are included in sales margin, have been recognized in the Company’s Consolidated Statements of Earnings from August 1, 2011 forward, on established revenue targets and are no longer dependent on sales volumes.

Unitil’s total therm sales of natural gas decreased 3.0% in 2012 compared to 2011. The decrease in gas therm sales in the Company’s utility service areas reflects the effect of milder winter weather in 2012 compared to 2011. Based on weather data collected in the Company’s service areas, there were 11% and 16% fewer Heating Degree Days in 2012 compared to 2011 and normal, respectively. Weather-normalized gas therm sales (excluding decoupled sales) in 2012 are estimated to be 3.3% higher compared to 2011. The increase in weather-normalized gas therm sales reflects the addition of new residential and C&I customers during the year.

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

Therm Sales (millions)							Change
							2013 vs. 2012				2012 vs. 2011
	2013		2012		2011		Therms		%		Therms			%
Residential		39.8		34.8		37.7		5.0		14.4%		(2.9	)		(7.7	%)
Commercial / Industrial		160.9		146.5		149.2		14.4		9.8%		(2.7	)		(1.8	%)
Total Therm Sales		200.7		181.3		186.9		19.4		10.7%		(5.6	)		(3.0	%)

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

Gas Operating Revenues and Sales Margin (millions)
							Change
							2013 vs. 2012					2012 vs. 2011
	2013		2012		2011		$		%(1)			$			%(1)
Gas Operating Revenue:
Residential	$	68.5	$	65.3	$	65.1	$	3.2		2.0	%	$	0.2			0.1	%
Commercial / Industrial		101.9		95.3		94.1		6.6		4.1	%		1.2			0.8	%
Total Gas Operating Revenue	$	170.4	$	160.6	$	159.2	$	9.8		6.1	%	$	1.4			0.9	%
Cost of Gas Sales	$	85.2	$	84.4	$	91.3	$	0.8		0.5	%	$	(6.9	)		(4.3	%)
Gas Sales Margin	$	85.2	$	76.2	$	67.9	$	9.0		5.6	%	$	8.3			5.2	%

⁽¹⁾  Represents change as a percent of Total Gas Operating Revenue.

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The Company analyzes operating results using Gas Sales Margin. Gas Sales Margin is calculated as Total Gas Operating Revenue less Cost of Gas Sales. The Company believes Gas Sales Margin is a better measure to analyze profitability than Total Gas Operating Revenue because the approved cost of sales are tracked costs that are passed through directly to the customer, resulting in an equal and offsetting amount reflected in Total Gas Operating Revenue.

Natural gas sales margins were $85.2 million in 2013, an increase of $9.0 million compared to 2012, reflecting higher gas distribution rates of $4.0 million, higher gas therm sales of $2.6 million and customer growth of $2.4 million.

The increase in Total Gas Operating Revenues of $9.8 million, or 6.1%, in 2013 compared to 2012 reflects higher gas sales margins of $9.0 million and higher costs of sales of $0.8 million, which are tracked costs that are passed through directly to customers.

Natural gas sales margins were $76.2 million in 2012, or an increase of $8.3 million compared to 2011, reflecting higher gas distribution rates of $12.9 million and customer growth of $1.8 million, partially offset by lower gas therm sales of $1.9 million, and the recovery, in 2011, of $4.5 million of Cost of Gas Sales costs that had been charged off in a prior period.

The increase in Total Gas Operating Revenues of $1.4 million, or 0.9%, in 2012 compared to 2011 reflects higher gas sales margins of $8.3 million. These higher gas sales margins were partially offset by lower Cost of Gas Sales of $6.9 million, which are tracked costs that are passed through directly to customers.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales—Unitil’s total electric kWh sales increased 0.9% in 2013 compared to 2012. Sales to residential and C&I customers increased 1.9% and 0.1%, respectively, in 2013 compared to 2012, driven by the effect of colder winter weather in 2013 compared to 2012 coupled with the addition of new residential and C&I customers. Approximately 27% of Unitil’s total electric kWh sales are decoupled and changes in these sales do not affect sales margins. Under revenue decoupling for Fitchburg, distribution revenues, which are included in sales margin, have been recognized in the Company’s Consolidated Statements of Earnings from August 1, 2011 forward, on established revenue targets and are no longer dependent on sales volumes.

Unitil’s total electric kWh sales decreased 1.7% in 2012 compared to 2011, primarily reflecting the effect of milder winter weather in 2012 compared to 2011. As discussed above, there were 11% and 16% fewer Heating Degree Days in 2012 compared to 2011 and normal, respectively. Weather-normalized kWh sales (excluding decoupled sales) in 2012 are estimated to be about the same compared to 2011.

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

kWh Sales (millions)							Change
							2013 vs. 2012				2012 vs. 2011
	2013		2012		2011		kWh		%		kWh			%
Residential		690.9		677.7		682.8		13.2		1.9%		(5.1	)		(0.7	%)
Commercial / Industrial		977.4		976.1		999.3		1.3		0.1%		(23.2	)		(2.3	%)
Total kWh Sales		1,668.3		1,653.8		1,682.1		14.5		0.9%		(28.3	)		(1.7	%)

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

Electric Operating Revenues and Sales Margin (millions)
							Change
							2013 vs. 2012						2012 vs. 2011
	2013		2012		2011		$			%(1)			$			%(1)
Electric Operating Revenue:
Residential	$	104.1	$	102.2	$	100.8	$	1.9			1.0	%	$	1.4			0.7	%
Commercial / Industrial		86.6		84.8		87.3		1.8			1.0	%		(2.5	)		(1.3	%)
Total Electric Operating Revenue	$	190.7	$	187.0	$	188.1	$	3.7			2.0	%	$	(1.1	)		(0.6	%)
Cost of Electric Sales	$	114.5	$	115.1	$	120.5	$	(0.6	)		(0.3	%)	$	(5.4	)		(2.9	%)
Electric Sales Margin	$	76.2	$	71.9	$	67.6	$	4.3			2.3	%	$	4.3			2.3	%

⁽¹⁾  Represents change as a percent of Total Electric Operating Revenue.

The Company analyzes operating results using Electric Sales Margin. Electric Sales Margin is calculated as Total Electric Operating Revenues less Cost of Electric Sales. The Company believes Electric Sales Margin is a better measure to analyze profitability than Total Electric Operating Revenues because the approved cost of sales are tracked costs that are passed through directly to the customer resulting in an equal and offsetting amount reflected in Total Electric Operating Revenues.

Electric sales margins were $76.2 million in 2013, an increase of $4.3 million compared to 2012, reflecting higher electric distribution rates of $3.7 million, customer growth of $0.5 million and higher electric kWh sales of $0.1 million. As discussed previously, electric sales margins in 2013 reflect higher recovery of $1.3 million of vegetation management and electric reliability enhancement expenditures as well as an increase of $0.7 million in the recovery of major storm restoration costs, which are offset by a corresponding increase in operating expenses.

The increase in Total Electric Operating Revenue of $3.7 million, or 2.0%, in 2013 compared to 2012 reflects higher electric sales margins of $4.3 million partially offset by lower costs of sales of $0.6 million, which are tracked costs that are passed through directly to customers.

Electric sales margins were $71.9 million in 2012, or an increase of $4.3 million compared 2011, reflecting higher electric distribution rates of $4.0 million and customer growth of $0.6 million, partially offset by reduced margins on lower unit sales of $0.3 million.

The decrease in Total Electric Operating Revenue of $1.1 million, or 0.6%, in 2012 compared to 2011 reflects lower Cost of Sales of $5.4 million, which are tracked costs that are passed through directly to customers. These lower costs of sales were partially offset by higher electric sales margins of $4.3 million.

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 2013 were $5.8 million, an increase of $0.3 million compared to 2012. Usource’s revenues in 2012 were on par with 2011 at $5.5 million. 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 does not take title to the energy but solicits energy bids from qualified competitive energy suppliers on behalf of its clients. Usource’s revenues reflect fees that it charges for its services, which are paid by the transacting supplier, typically over the term of the energy contract.

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

Other Revenue (millions)
							Change
							2013 vs. 2012					2012 vs. 2011
	2013		2012		2011		$		%			$		%
Usource	$	5.8	$	5.5	$	5.5	$	0.3		5.5	%	$	—		—
Total Other Revenue	$	5.8	$	5.5	$	5.5	$	0.3		5.5	%	$	—		—

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 increased $0.8 million, or 1.0%, in 2013 compared to 2012. This increase reflects higher sales of natural gas and increased spending on energy efficiency programs, partially offset by lower wholesale natural gas prices and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. The Company 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 2012, Cost of Gas Sales decreased $6.9 million, or 7.6%, compared to 2011. This decrease reflects lower wholesale natural gas prices, a decline in sales of natural gas compared to the prior period and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. These factors were partially offset by a credit recorded in 2011 of $4.5 million for the recovery of purchased gas costs that had previously been charged off in a prior period and increased spending on energy efficiency programs.

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 $0.6 million, or 0.5%, in 2013 compared to 2012. This decrease reflects lower wholesale electricity prices and an increase in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by higher electric kWh sales and increased spending on energy efficiency programs. The Company recovers the approved Cost of Electric Sales in its rates at cost and therefore changes in approved expenses do not affect earnings.

In 2012, Cost of Electric Sales decreased $5.4 million, or 4.5%, compared to 2011. This decrease reflects an increase in the amount of electricity purchased by customers directly from third-party suppliers and lower kWh sales, partially offset by increased spending on energy efficiency programs.

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 increased $4.0 million, or 7.0%, in 2013 compared to 2012. The change in O&M expenses reflects higher utility operating costs of $1.9 million, higher compensation and benefit costs of $1.0 million, higher professional fees of $0.9 million and higher all other O&M expenses, net of $0.2 million. The increase in utility operating costs includes $1.3 million in new spending on vegetation management programs which is recovered through cost tracker rate mechanisms that result in a corresponding and offsetting increase in revenue and margin in the period. Also, the increase in utility operating costs includes $0.3 million in higher bad debt expense and $0.3 million in higher electric and natural gas maintenance costs.

In 2012, total O&M expense increased $5.5 million, or 10.7%, compared to 2011. The change in O&M expenses reflects higher utility operating costs of $3.7 million, higher employee compensation and benefit costs of $0.5 million, and higher professional fees of $0.3 million. The increase in utility operating costs in 2012 compared to 2011 includes an increase of $2.6 million in new spending on vegetation management and electric reliability enhancement programs of which approximately $1.8 million is recovered through cost tracker rate mechanisms that result in corresponding and offsetting increase in revenue and electric sales margin in the period. Also, the increase in utility operating costs includes $0.5 million in higher bad debt expense, $0.3 million in higher storm costs and all other utility operating cost increases of $0.3 million. The increase in O&M costs in 2012 over the prior also reflects lower O&M expenses recorded in the first quarter of 2011 due to the receipt of a non-recurring insurance payment of $1.0 million.

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Depreciation and Amortization—Depreciation and Amortization expense increased $2.6 million, or 7.4%, in 2013 compared to 2012, reflecting higher depreciation of $1.6 million on normal utility plant additions, higher amortization of major storm restoration costs of $0.7 million and an increase in all other amortization of $0.3 million. The increase in major storm restoration cost amortization is also recovered in current electric rates.

In 2012, Depreciation and Amortization expense increased $5.8 million, or 19.8%, compared to 2011, principally reflecting normal utility plant additions and amortization of regulatory assets.

Taxes Other Than Income Taxes—Taxes Other Than Income Taxes increased $1.0 million, or 7.1%, in 2013 compared to 2012, reflecting higher local property taxes on higher levels of utility plant in service.

In 2012, Taxes Other Than Income Taxes increased $1.0 million, or 7.7%, compared to 2011, reflecting higher local property taxes on higher levels of utility plant in service.

Other Expense (Income), net—Other Expense (Income), net increased $0.2 million in 2013 compared to 2012 and decreased $0.2 million in 2012 compared to 2011.

Income Taxes—Income Taxes increased $1.7 million in 2013 compared to 2012 due to higher pre-tax earnings in 2013 compared to 2012 (See Note 9 to the accompanying Consolidated Financial Statements).

In 2012, Income Taxes increased $1.0 million compared to 2011 due to higher pre-tax earnings in 2012 compared to 2011.

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. 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 $0.7 million in 2013 compared to 2012 reflecting lower net interest income on regulatory assets, partially offset by lower average rates on lower short-term borrowings.

In 2012, Interest Expense, net decreased $2.3 million compared to 2011 primarily reflecting lower interest rates and lower borrowing balances as a result of the equity offering in 2012 as well as the recognition of a non-recurring pre-tax charge, in 2011, against interest income of $1.8 million to charge-off previously accrued carrying costs that were disallowed for rate recovery.

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 bank borrowings, as needed, under its unsecured short-term 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

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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, 2013 and December 31, 2012, 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 (the “Credit Facility”) with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 and provides for a new 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 plus 1.375%. 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 following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2013 and December 31, 2012:

Revolving Credit Facility (millions)
	December 31,
	2013		2012
Limit	$	120.0	$	60.0
Outstanding	$	60.2	$	49.4
Available	$	59.8	$	10.6

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, 2013, 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.)

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 significant contractual obligations as of December 31, 2013.

			Payments Due by Period
Significant Contractual Obligations (millions) as of December 31, 2013	Total		2014		2015- 2016		2017- 2018		2019 & Beyond
Long-term Debt	$	287.3	$	2.5	$	21.4	$	47.3	$	216.1
Interest on Long-term Debt		224.2		19.9		39.1		34.7		130.5
Gas Supply Contracts		171.4		39.6		74.3		49.8		7.7
Electric Supply Contracts		10.7		1.1		2.2		1.8		5.6
Other (Including Capital and Operating Lease Obligations)		4.8		1.6		2.2		1.0		—
Total Contractual Cash Obligations	$	698.4	$	64.7	$	139.2	$	134.6	$	359.9

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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, 2013, there were approximately $19.1 million of guarantees outstanding and the longest term guarantee extends through October 2014.

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 $12.5 million and $10.7 million of natural gas storage inventory at December 31, 2013 and 2012, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2013, which was payable in January 2014, is $2.7 million and recorded in Accounts Payable at December 31, 2013. The amount of natural gas inventory released in December 2012, which was payable in January 2013, is $2.1 million and recorded in Accounts Payable at December 31, 2012.

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, 2013, the principal amount outstanding for the 8% Unitil Realty note was $2.3 million, and the principal amount outstanding for the 7.15% Granite State note was $10.0 million.

Benefit Plan Funding

The Company, along with its subsidiaries, made cash contributions to its Pension Plan in the amount of $3.7 million and $9.4 million in 2013 and 2012, respectively. The Company, along with its subsidiaries, contributed $3.3 million and $2.2 million to Voluntary Employee Benefit Trusts (VEBTs) in 2013 and 2012, respectively. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan and the VEBTs in 2014 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. 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 2013 and 2012.

	2013		2012
Cash Provided by Operating Activities	$	96.3	$	66.7

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Cash Provided by Operating Activities—Cash Provided by Operating Activities was $96.3 million in 2013, an increase of $29.6 million over 2012. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes, was $71.6 million in 2013 compared to $64.1 million in 2012, representing an increase of $7.5 million. Working capital changes in Current Assets and Liabilities resulted in a $5.8 million net source of cash in 2013 compared to a $1.1 million source of cash in 2012. Deferred Regulatory and Other Charges resulted in a $15.0 million source of cash in 2013, compared to a $5.4 million source of cash in 2012. All Other, net operating activities resulted in a source of cash of $3.9 million in 2013 compared to a use of cash of ($3.9) million in 2012.

	2013			2012
Cash (Used in) Investing Activities	$	(89.5	)	$	(68.5	)

Cash (Used in) Investing Activities—Cash Used in Investing Activities was ($89.5) million for 2013 compared to ($68.5) million in 2012. The capital spending in both periods is representative of distribution utility capital expenditures reflecting electric and gas utility system additions. The increase in capital spending in 2013 compared to 2012 primarily reflects plant additions to connect new gas customers to the Company’s gas distribution system. Capital expenditures are projected to be approximately ($91) million in 2014 reflecting a higher level of capital spending on information system and utility facility projects and planned increases in gas customer additions.

	2013			2012
Cash (Used in) Provided by Financing Activities	$	(7.2	)	$	4.1

Cash (Used in) Provided by Financing Activities—Cash Used in Financing Activities was ($7.2) million in 2013 compared to cash provided of $4.1 million in 2012. In 2013, sources of cash from financing activities included proceeds from issuance of common stock of $1.1 million, proceeds from short-term debt of $10.8 million and an increase in gas inventory financing of $1.2 million. Uses of cash from financing activities included payment of long-term debt of ($0.5) million and regular quarterly dividend payments on common and preferred stock of ($19.1) million. All other financing activities resulted in a use of ($0.7) million.

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.

The long-term debt of Unitil, Unitil Energy, Fitchburg, Northern Utilities, Granite State and Unitil Realty are private placements, and the Company does not issue commercial paper. For these reasons, the debt securities of Unitil and its subsidiaries are not publicly rated.

Unitil’s Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65% tested on a quarterly basis. At December 31, 2013, 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.

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DIVIDENDS

Unitil’s annualized common dividend was $1.38 per common share in 2013, 2012 and 2011. 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 2014 meeting, the Unitil Board of Directors declared a quarterly dividend on the Company’s common stock of $0.345 per share. 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 the Company’s financial position.

In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (Fitchburg), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman 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 Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit would now proceed with only the twelve named plaintiffs seeking damages; however, the plaintiffs have appealed this decision to the Massachusetts Supreme Judicial Court (the “SJC”). The SJC has accepted the matter for review. The Town of Lunenburg has also filed a separate action in Massachusetts Worcester County Superior Court arising out of the December 2008 ice storm. The parties to this action have agreed to put this matter on hold pending the decision of the Supreme Judicial Court in Bellermann. The Company continues to believe these suits are without merit and will continue to defend itself vigorously.

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 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

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investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms. As a result of the restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers have the opportunity 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.

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. The remaining balance of these assets, to be recovered principally over the next year, is $12.7 million as of December 31, 2013 including $10.2 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet. Unitil’s distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Northern Utilities—Base Rates—Maine—On December 27, 2013, the MPUC approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine operations, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed to implement a TIRA to provide for annual adjustments to distribution base rates to recover costs associated with the Company’s investments in targeted operational and safety-related infrastructure replacement and upgrade projects. The TIRA will have an initial term of four years, and covers expenditures in each of the Calendar Years 2013, 2014, 2015, and 2016. The settlement agreement also provides for Earning Sharing where Northern would be allowed to retain all earnings up to a return of 10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement continues and revises the service quality plan (SQP) that Northern has been operating under since 2004 and established in Docket No. 2002-140. The revised SQP consists of seven metrics with an appurtenant administrative penalty for failure to meet any of the seven metrics. The settlement agreement further provides that Northern will be subject to a maximum annual penalty of $500,000 if it fails to meet any of the baseline performance targets under the revised SQP.

Northern Utilities—Base Rates—New Hampshire—In April 2013, Northern Utilities’ New Hampshire operations filed a rate case with the NHPUC requesting approval to increase its natural gas distribution base rates by $5.2 million in gas distribution base revenue or approximately 9.4 percent over test year operating revenue. The filing included a proposed multi-year rate plan that included cost tracking mechanisms to recover future capital costs associated with Northern Utilities’ infrastructure replacements and safety and reliability improvements to the natural gas distribution system. Northern Utilities has been authorized to implement temporary rates to collect a $2.5 million increase (annualized) in gas distribution revenue, effective July 1, 2013. The Company is currently in settlement discussions with the NHPUC and expects a final rate order from the NHPUC in the first half of 2014. Once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were established, July 1, 2013.

Unitil Energy—Base Rates—Unitil Energy’s second step increase of $2.8 million went into effect on May 1, 2013, which included rate increases to recover capital improvements, increased spending for its vegetation management and reliability enhancement programs and an increase in its storm reserve fund. On April 26, 2011, the NHPUC approved a rate settlement with a permanent increase of $5.2 million in annual revenue effective July 1, 2010, and an additional increase of $5.0 million in annual revenue effective May 1, 2011. The settlement extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with step increases in annual revenue on May 1, 2012, May 1, 2013 and May 1, 2014, to support Unitil Energy’s continued capital improvements to its distribution system. Unitil Energy’s first step increase was approved as filed, effective May 1, 2012.

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Granite State—Base Rates—In June 2013, Granite State submitted to the FERC its latest incremental annual rate adjustment, in the amount of $0.4 million, with rates effective August 1, 2013. The FERC approved the increase on July 30, 2013. Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file a limited Section 4 rate case that includes incremental annual rate adjustments to recover the revenue requirements for certain specified future capital cost additions to gas transmission plant projects.

Fitchburg—Electric Base Rates Filed—In July 2013, Fitchburg filed a rate case with the MDPU requesting approval to increase its electric distribution rates. The Company requested an increase of $6.7 million in electric base revenue or approximately 11.5 percent over test year operating revenue. Included in the amount of this annual increase is approximately $2.1 million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to three severe storms, Tropical Storm Irene, the October 2011snowstorm and Superstorm Sandy. The filing includes a proposed modified revenue decoupling mechanism by means of an annual revenue adjustment mechanism by either a capital cost tracker mechanism or a multi-year rate plan featuring a revenue cap index. The filing also includes a proposal to establish a major storm reserve fund to address the costs of future major storms by collecting $2.8 million per year through a reconciling storm recovery adjustment factor beginning January 1, 2015. The rate case filing is subject to regulatory review with hearings scheduled throughout January 2014 and approval with final rate orders expected in the second quarter of 2014.

Major Storms—Fitchburg and Unitil Energy

Superstorm Sandy—On October 29-30, 2012, a severe storm struck the eastern seaboard of the United States, causing extensive damage to electric facilities and loss of service to significant numbers of customers of several utilities. Fitchburg and Unitil Energy incurred approximately $1.1 million and $2.7 million, respectively, in costs for the repair and replacement of electric distribution systems damaged during the storm, including $0.3 million and $0.4 million related to capital construction for Fitchburg and Unitil Energy, respectively. The amount and timing of the cost recovery of these storm restoration expenditures for Fitchburg will be determined in its rate case. The cost recovery for Unitil Energy has been approved as discussed below. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations.

Fitchburg—Storm Cost Deferral—On May 1, 2012 the MDPU approved Fitchburg’s request to defer $4.3 million of storm costs associated with two severe storms which occurred in 2011, and Fitchburg is seeking recovery of these costs in the electric rate case it filed in July 2013.

Unitil Energy—2012 Storm Costs—On April 25, 2013, the NHPUC approved the recovery of $2.3 million of costs to repair damage to Unitil Energy’s electrical system resulting from Superstorm Sandy over a five-year period, with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, applied to the uncollected balance through the recovery period.

Fitchburg—Electric Operations—On November 15, 2013, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing also includes the reconciliation of costs and revenues for a number of other surcharges and cost factors which are subject to review and approval by the MDPU. Many of the surcharges and cost factors were redesigned based on cost-based rate design in compliance with a MDPU order in its Investigation into Cost-Based Rate Design for Reconciliation Factors, which resulted from the “Act Relative to Competitively Priced Electricity in the Commonwealth”, signed into law by the Governor of Massachusetts on August 3, 2012. All of the rates were approved effective January 1, 2014 for billing purposes, subject to reconciliation, pending investigation by the MDPU. This matter remains pending.

Fitchburg—Service Quality—On March 1, 2013, Fitchburg submitted its 2012 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. On March 29, 2013, the MDPU issued its order approving the 2011 Service Quality Report for Fitchburg’s gas division. The 2011-2012 Service Quality reports for Fitchburg’s electric division remain pending.

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On December 11, 2012, the MDPU opened an investigation into the service quality provided by the gas and electric distribution companies in Massachusetts and the Service Quality guidelines currently in effect. The MDPU investigation will review existing and potential new reliability, safety, and customer satisfaction metrics; potential penalties for downed wire response; potential clean energy metrics; penalty provisions, including penalty offsets for superior performance in other metrics for poor performance on a different metric; and review of historic data for use in establishing service quality benchmarks. Fitchburg has been an active participant in this docket, which remains pending.

Fitchburg—Other—On February 5, 2013, there was a natural gas explosion in the city of Fitchburg, Massachusetts in an area served by Fitchburg’s gas division resulting in property damage to a number of commercial and residential properties. The MDPU, pursuant to its authority under state and federal law, has commenced an investigation of the incident, with which Fitchburg is cooperating. The Company does not believe this incident or investigation will have a material adverse impact on the Company’s financial condition or results of operations.

On February 11, 2009, the Massachusetts Supreme Judicial Court (SJC) issued its decision in the Attorney General’s (AG) appeal of the MDPU orders relating to Fitchburg’s recovery of bad debt expense. The SJC agreed with the AG that the MDPU was required to hold hearings regarding changes in Fitchburg’s tariff and rates, and on that basis vacated the MDPU orders. The SJC, however, declined to rule on an appropriate remedy, and remanded the cases back to the MDPU for consideration of that issue. In the Company’s August 1, 2011 rate decision, the MDPU held that the approval of dollar for dollar collection of supply-related bad debt in the Company’s rate cases in 2006 (gas) and 2007 (electric) satisfied the requirement for a hearing ordered by the SJC. The MDPU has opened a docket to address the amounts collected by Fitchburg between the time the MDPU first approved dollar for dollar collection of the Company’s bad debt, and the rate decisions in 2006 and 2007. Briefs were filed in June 2013. This matter remains pending before the MDPU.

On July 2, 2008, the Governor of Massachusetts signed into law “The Green Communities Act” (the GC Act), an energy policy statute designed to substantially increase energy efficiency and the development of renewable energy resources in Massachusetts. The GC Act provides for utilities to recover in rates the incremental costs associated with its various mandated programs. Several regulatory proceedings have been initiated to implement various provisions of the GC Act, including provisions for each distribution company to file enhanced three-year energy efficiency investment plans, plans to establish smart grid pilot programs, proposals to purchase long-term contracts for renewable energy, special tariffs to allow the net metering of customer-owned renewable generation, and terms and conditions for purchasing supplier receivables. Fitchburg’s first two three-year energy efficiency investment plans, plans to establish smart grid pilot programs, net metering tariffs and proposals to purchase long-term contracts for renewable energy have been approved by the MDPU. Terms and conditions for purchasing supplier receivables are under review in a separately designated docket.

On August 3, 2012, the Governor of Massachusetts signed into law “An Act Relative to Competitively Priced Electricity in the Commonwealth”, which both increases electric distribution companies’ obligations to purchase renewable energy resources and the availability of net metering. This act also includes changes to the MDPU’s ratemaking procedures and authority for reviewing mergers and acquisitions for electric and gas distribution companies. With these changes, electric distribution companies are required to file rate schedules every five years, and gas distribution companies every ten years. The MDPU also opened a proceeding, as mandated by the act, to establish a cost-based rate design for costs that are currently recovered from distribution customers through a reconciling factor. On December 17, 2013, the MDPU issued an order establishing the new rate design allocation methodologies. Fitchburg has participated with the other electric utilities and entered into long-term renewable contracts for its pro-rata share of renewable energy projects. The facility associated with one of these contracts has been constructed and is operating. The other contracts are pending approval by the MDPU as well as subsequent facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

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On August 6, 2012, the Governor of Massachusetts also signed into law “An Act Relative to the Emergency Response of Public Utilities”, which establishes a new storm trust fund and requires that penalties levied by the MDPU for violations of its emergency preparedness rules be credited to customers.

On December 23, 2013 the MDPU issued two orders related to Grid Modernization. The MDPU opened an investigation on its own motion into Modernization of the Electric Grid and, in a separate but related order, opened an investigation into Electric Vehicles and Electric Vehicle Charging. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices” and all related objectives. It sets forth a straw proposal which would require each electric distribution company to submit a ten-year strategic grid modernization plan (GMP) within six months of a final Order. As part of the GMP each company must also include a comprehensive advanced metering plan (CAMP), and each company is required to achieve advanced metering functionality. The filing of a GMP will be 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. A cost recovery mechanism is proposed only for investments in advanced metering. The MDPU also proposes to address in separate, upcoming proceedings (1) time varying rates, (2) cybersecurity, privacy, and access to meter data, and (3) electric vehicles (EVs). In the Electric Vehicle Order, the MDPU seeks to establish policies and regulations that will help facilitate and accommodate the widespread adoption of EVs. Among other objectives, the proceeding looks to evaluate (1) EV charging and its impact on the electric distribution system, (2) electric distribution company involvement in EV charging, (3) residential metering practices and rates for EVs, and (4) consumer protection issues. Both of these matters remain pending.

Unitil Corporation—FERC Audit—On November 3, 2011, the FERC commenced an audit of Unitil Corporation, including its associated service company and its electric and natural gas distribution companies. Among other requirements, the audit evaluated the Company’s compliance with: i) cross-subsidization restrictions on affiliate transactions; ii) regulations under the Energy Policy Act of 2005; and the iii) uniform system of accounts for centralized service companies. The final audit report was issued on February 28, 2013 and the Company submitted its plan to address the audit findings and implement the audit recommendations on March 29, 2013. The Company submitted its quarterly progress update on the implementation of the audit recommendations on April 30, 2013. On June 5, 2013 the FERC advised the Company that the audit is complete; no further action is required by the Company. The audit findings did not have an 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 believes it is in material compliance with applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2013, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you 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.

Northern Utilities Manufactured Gas Plant Sites—Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites that were operated from the mid-1800s through the mid-1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. This program has also documented the presence of MGP sites in Lewiston and Portland, Maine and a former MGP disposal site in Scarborough, Maine. Northern Utilities has worked with the environmental regulatory agencies in both New Hampshire and Maine to address environmental concerns with these sites.

Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, Lewiston and Scarborough sites. The site in Portland has been investigated and remedial activities are ongoing with the most recent phase completed in December 2013. Although Northern Utilities recently finalized a long-term lease on the Portland property, the State of Maine has announced its intention to acquire the site in the short-term for the expansion of the adjacent marine

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terminal. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs pending either State acquisition or until all remedial activities are completed.

The NHPUC and MPUC have approved the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over a seven-year amortization period. For Northern Utilities’ Maine division, the MPUC authorized the recovery of environmental remediation costs over a rolling five-year amortization schedule.

Fitchburg’s Manufactured Gas Plant Site—Fitchburg is in the process of seeking regulatory approval to implement a permanent remediation solution at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts. 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, without carrying costs.

The Company’s ultimate liability for future environmental remediation costs, including MGP site costs, may vary from estimates, which may be adjusted as new information or future developments become available. 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.

Also, see Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on Environmental Matters.

EMPLOYEES AND EMPLOYEE RELATIONS

As of December 31, 2013, the Company and its subsidiaries had 477 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of December 31, 2013, a total of 158 employees of certain of the Company’s subsidiaries were represented by labor unions. There are 45 union employees of Fitchburg covered by a collective bargaining agreement (CBA) which expires on May 31, 2019; 34 union employees of Northern Utilities’ New Hampshire division covered by a separate CBA which expires on June 5, 2014; 37 union employees of Northern Utilities’ Maine division and Granite State covered by a separate CBA which expires on March 31, 2017; 37 union employees of Unitil Energy Systems covered by a separate CBA which expires on May 31, 2018 and 5 union employees of Unitil Service Corp. covered by a separate CBA which expires on May 31, 2016. The agreements provide discrete salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.

CRITICAL ACCOUNTING POLICIES

The preparation of the Company’s 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.

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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. 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.

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.

On August 1, 2011, the MDPU issued an order approving RDM for the electric and natural gas divisions of Fitchburg. 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. One of the primary purposes of decoupling is to eliminate the disincentive a utility otherwise has to encourage and promote energy conservation programs designed to reduce energy usage. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011 forward, distribution revenues for Fitchburg based on established revenue targets. The established revenue targets for the gas division may be subject to periodic adjustments to account for customer growth and special contracts, for which RDM does not apply. The difference between distribution revenue amounts billed to customers and the targeted amounts is recognized as increases or decreases in Accrued Revenue which form the basis for future reconciliation adjustments in periodically resetting rates for future cash recoveries from, or credits to, customers. The Company’s other electric and natural gas distribution utilities are not subject to RDM.

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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. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company. 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 an unfunded 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 years ended December 31, 2013 and 2012, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $431,000 and $367,000, respectively, in the Net Periodic Benefit Cost for the Pension Plan. For the years ended December 31, 2013 and 2012, a 1.0% increase in the assumption of health care cost trend rates would have resulted in increases in the Net Periodic Benefit Cost for the PBOP Plan of $1,169,000 and $981,000, respectively. Similarly, a 1.0% decrease in the assumption of health care cost trend rates for those same time periods would have resulted in decreases in the Net Periodic Benefit Cost for the PBOP Plan of $895,000 and $756,000, respectively. (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.

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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 current and 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 which 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, 2013, 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 Accounting 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 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 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%, 2.0%, and 2.2% during 2013, 2012, and 2011, 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 Shareholders of Unitil Corporation and subsidiaries:

We have audited the accompanying consolidated balance sheets of Unitil Corporation and subsidiaries (“the Company”) as of December 31, 2013 and 2012, and the related consolidated statements of earnings, cash flows and changes in common stock equity for each of the years in the three-year period ended December 31, 2013. We also have audited Unitil Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 1992. 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 audits 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 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 (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (b) 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 (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, Unitil Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 1992.

/s/ McGladrey LLP

Boston, Massachusetts

January 29, 2014

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CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except common shares and per share data)

Year Ended December 31,	2013		2012		2011
Operating Revenues:
Gas	$	170.4	$	160.6	$	159.2
Electric		190.7		187.0		188.1
Other		5.8		5.5		5.5
Total Operating Revenues		366.9		353.1		352.8
Operating Expenses:
Cost of Gas Sales		85.2		84.4		91.3
Cost of Electric Sales		114.5		115.1		120.5
Operation and Maintenance		61.0		57.0		51.5
Depreciation and Amortization		37.7		35.1		29.3
Taxes Other Than Income Taxes		15.0		14.0		13.0
Total Operating Expenses		313.4		305.6		305.6
Operating Income		53.5		47.5		47.2
Interest Expense, net		18.8		18.1		20.4
Other Expense (Income), net		0.4		0.2		0.4
Income Before Income Taxes		34.3		29.2		26.4
Income Taxes		12.7		11.0		10.0
Net Income		21.6		18.2		16.4
Less Dividends on Preferred Stock		—		0.1		0.1
Earnings Applicable to Common Shareholders	$	21.6	$	18.1	$	16.3
Earnings per Common Share—Basic and Diluted	$	1.57	$	1.43	$	1.50
Average Common Shares Outstanding—Basic		13,772,855		12,669,309		10,880,025
Average Common Shares Outstanding—Diluted		13,775,245		12,671,609		10,882,971

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

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CONSOLIDATED BALANCE SHEETS (Millions)

ASSETS

December 31,	2013		2012
Current Assets:
Cash and Cash Equivalents	$	9.4	$	9.8
Accounts Receivable, net		52.2		47.7
Accrued Revenue		56.6		63.4
Exchange Gas Receivable		10.8		9.4
Gas Inventory		1.2		1.1
Material and Supplies		5.0		4.1
Prepayments and Other		4.8		4.2
Total Current Assets		140.0		139.7
Utility Plant:
Gas		477.3		424.4
Electric		375.6		356.9
Common		31.6		30.9
Construction Work in Progress		24.6		21.0
Utility Plant		909.1		833.2
Less: Accumulated Depreciation		243.5		232.0
Net Utility Plant		665.6		601.2
Other Noncurrent Assets:
Regulatory Assets		100.1		134.6
Other Assets		14.9		16.8
Total Other Noncurrent Assets		115.0		151.4
TOTAL ASSETS	$	920.6	$	892.3

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

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CONSOLIDATED BALANCE SHEETS (cont.) (Millions)

LIABILITIES AND CAPITALIZATION

December 31,	2013		2012
Current Liabilities:
Accounts Payable	$	38.1	$	32.7
Short-Term Debt		60.2		49.4
Long-Term Debt, Current Portion		2.5		0.5
Energy Supply Obligations		14.4		13.8
Deferred Income Taxes		6.7		13.4
Interest Payable		3.1		3.1
Regulatory Liabilities		9.7		6.8
Other Current Liabilities		10.0		11.4
Total Current Liabilities		144.7		131.1
Noncurrent Liabilities:
Energy Supply Obligations		2.5		3.3
Deferred Income Taxes		73.2		38.7
Cost of Removal Obligations		57.3		51.4
Retirement Benefit Obligations		77.3		103.7
Environmental Obligations		13.8		13.8
Other Noncurrent Liabilities		1.8		2.4
Total Noncurrent Liabilities		225.9		213.3
Capitalization:
Long-Term Debt, Less Current Portion		284.8		287.3
Common Stock Equity:
Common Equity		232.1		230.0
Retained Earnings		32.9		30.4
Total Common Stock Equity		265.0		260.4
Preferred Stock		0.2		0.2
Total Capitalization		550.0		547.9
TOTAL LIABILITIES AND CAPITALIZATION	$	920.6	$	892.3

(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,	2013			2012			2011
Operating Activities:
Net Income	$	21.6		$	18.2		$	16.4
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		37.7			35.1			29.3
Deferred Taxes Provision		12.3			10.8			8.7
Changes in Working Capital Items:
Accounts Receivable		(4.5	)		(2.6	)		(7.4	)
Accrued Revenue		6.8			(0.7	)		(7.7	)
Regulatory Liabilities		2.9			(4.4	)		5.0
Taxes Refundable / Payable		(0.5	)		(0.3	)		8.5
Exchange Gas Receivable		(1.4	)		4.1			(4.3	)
Accounts Payable		5.4			5.4			—
Other Changes in Working Capital Items		(2.9	)		(0.4	)		(1.3	)
Deferred Regulatory and Other Charges		15.0			5.4			1.0
Other, net		3.9			(3.9	)		(2.3	)
Cash Provided by Operating Activities		96.3			66.7			45.9
Investing Activities:
Property, Plant and Equipment Additions		(89.5	)		(68.5	)		(57.1	)
Cash (Used In) Investing Activities		(89.5	)		(68.5	)		(57.1	)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net		10.8			(38.5	)		21.1
Repayment of Long-Term Debt		(0.5	)		(0.5	)		(0.5	)
Net Increase (Decrease) in Gas Inventory Financing		1.2			(3.8	)		4.6
Dividends Paid		(19.1	)		(17.2	)		(15.2	)
Retirement of Preferred Stock		—			(1.8	)		—
Proceeds from Issuance of Common Stock		1.1			66.8			1.0
Other, net		(0.7	)		(0.9	)		(1.2	)
Cash (Used In) Provided by Financing Activities		(7.2	)		4.1			9.8
Net Increase (Decrease) in Cash		(0.4	)		2.3			(1.4	)
Cash at Beginning of Year		9.8			7.5			8.9
Cash at End of Year	$	9.4		$	9.8		$	7.5
Supplemental Information:
Interest Paid	$	20.8		$	21.2		$	21.2
Income Taxes Paid (Refunded)	$	0.8		$	0.7		$	(7.3	)
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	0.7		$	1.9		$	2.6

(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)

	Common Equity		Retained Earnings			Total
Balance at January 1, 2011	$	160.8	$	28.2		$	189.0
Net Income for 2011				16.4			16.4
Dividends				(15.2	)		(15.2	)
Shares Issued Under Stock Plans		0.5					0.5
Issuance of 39,473 Common Shares		1.0					1.0
Balance at December 31, 2011		162.3		29.4			191.7
Net Income for 2012				18.2			18.2
Dividends				(17.2	)		(17.2	)
Shares Issued Under Stock Plans		0.9					0.9
Issuance of 41,752 Common Shares		1.1					1.1
Issuance of 2,760,000 Common Shares (See Note 6)		65.7					65.7
Balance at December 31, 2012		230.0		30.4			260.4
Net Income for 2013				21.6			21.6
Dividends				(19.1	)		(19.1	)
Shares Issued Under Stock Plans		1.0					1.0
Issuance of 39,559 Common Shares		1.1					1.1
Balance at December 31, 2013	$	232.1	$	32.9		$	265.0

(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 results will reflect the seasonal nature of the natural gas distribution business. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher due to heating-related requirements, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.

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.

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.

On August 1, 2011, the Massachusetts Department of Public Utilities (MDPU) issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of Fitchburg. 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. One of the primary purposes of decoupling is to eliminate the disincentive a utility otherwise has to encourage and promote energy conservation programs designed to reduce energy usage. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011 forward, distribution revenues for Fitchburg based on established revenue targets. The established revenue targets for the gas division may be subject to periodic adjustments to account for customer growth and special contracts, for which RDM does not apply. The difference between distribution revenue amounts billed to customers and the targeted amounts is recognized as increases or decreases in Accrued Revenue which form the basis for future reconciliation adjustments in periodically resetting rates for future cash recoveries from, or credits to, customers. The Company’s other electric and natural gas distribution utilities are not subject to RDM.

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

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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 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: 2013 – 3.59%, 2012 – 3.60% and 2011 – 3.43%.

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 current and 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. Deferred income taxes are reflected as Current and Noncurrent Deferred Income Taxes on the Consolidated Balance Sheets based on the nature of the underlying timing item.

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 years ended December 31, 2013, 2012 and 2011, the Company paid quarterly dividends of $0.345 per share, resulting in an annual dividend rate of $1.38 per common 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. On December 31, 2013 and 2012, the Unitil subsidiaries had deposited $7.3 million and $5.4 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. On December 31, 2013 and 2012, there was $0 and $1.2 million, respectively, deposited for this purpose.

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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. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company.

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below and unbilled revenues (see Utility Revenue Recognition below.) The following table shows the components of Accrued Revenue as of December 31, 2013 and 2012.

Accrued Revenue (millions)	December 31,
	2013		2012
Regulatory Assets—Current	$	43.6	$	51.9
Unbilled Revenues		13.0		11.5
Total Accrued Revenue	$	56.6	$	63.4

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. Prior to March 31, 2013, the exchange gas amounts had been recorded in Gas Inventory on the Company’s Consolidated Balance Sheets. Amounts previously reported have been reclassified to conform to current year presentation. 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, 2013 and 2012.

Exchange Gas Receivable (millions)	December 31,
	2013		2012
Northern Utilities	$	9.8	$	8.7
Fitchburg		1.0		0.7
Total Exchange Gas Receivable	$	10.8	$	9.4

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, 2013 and 2012.

Gas Inventory (millions)	December 31,
	2013		2012
Natural Gas	$	0.8	$	0.6
Propane		0.3		0.4
Liquefied Natural Gas & Other		0.1		0.1
Total Gas Inventory	$	1.2	$	1.1

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 1.92%, 2.04% and 2.28% in 2013, 2012 and 2011, 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, 2013 and 2012, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $57.3 million and $51.4 million, respectively.

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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 Massachusetts Department of Public Utilities (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 Financial Accounting Standards Board (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,
	2013		2012
Energy Supply & Other Regulatory Tracker Mechanisms	$	32.5	$	41.0
Deferred Restructuring Costs		9.3		20.1
Retirement Benefits		42.6		62.5
Income Taxes		11.9		10.2
Environmental		16.1		16.8
Deferred Storm Charges		25.6		27.8
Other		5.7		8.1
Total Regulatory Assets	$	143.7	$	186.5
Less: Current Portion of Regulatory Assets(1)		43.6		51.9
Regulatory Assets—noncurrent	$	100.1	$	134.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets.

Regulatory Liabilities consist of the following (millions)	December 31,
	2013		2012
Regulatory Tracker Mechanisms	$	9.7	$	6.8
Total Regulatory Liabilities	$	9.7	$	6.8

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.

Prior to June 30, 2013, certain regulatory tracker mechanisms which are currently recorded in Regulatory Liabilities had been recorded in Accrued Revenue and Other Current Liabilities on the Consolidated Balance Sheets. Amounts previously reported have been reclassified to conform to current year presentation.

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

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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 a portion of its gas supply costs for the coming year of service. In order to fix these costs, the Company purchases natural gas futures and options contracts on the New York Mercantile Exchange (NYMEX) that correspond to the associated delivery month. Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through a regulatory commission approved recovery mechanism. 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 Purchased Gas when the gains and losses are passed through to customers in accordance with rate reconciling mechanisms.

As of December 31, 2013 and December 31, 2012, the Company had 1.8 billion and 1.9 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 Purchased Gas. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Other Current Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.

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

		Fair Value
Description	Balance Sheet Location	December 31, 2013		December 31, 2012
Derivative Assets
Natural Gas Futures Contracts	Prepayments and Other	$	0.1	$	—
Natural Gas Futures Contracts	Other Noncurrent Assets		0.1		—
Total Derivative Assets		$	0.2	$	—
Derivative Liabilities
Natural Gas Futures Contracts	Other Current Liabilities	$	—	$	0.7
Natural Gas Futures Contracts	Other Noncurrent Liabilities		—		—
Total Derivative Liabilities		$	—	$	0.7

	Twelve Months Ended December 31,
	2013		2012
Amount of Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	0.3	$	1.0
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings(1):
Purchased Gas	$	1.2	$	2.6

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

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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, 2013, the unamortized balance of the bargain purchase adjustment is $12.2 million, to be amortized over the next five years.

Energy Supply Obligations—The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

	December 31,
Energy Supply Obligations consist of the following: (millions)	2013		2012
Current:
Exchange Gas Obligation	$	9.8	$	8.7
Renewable Energy Portfolio Standards		3.7		4.2
Power Supply Contract Divestitures		0.9		0.9
Total Energy Supply Obligations—Current	$	14.4	$	13.8
Long-Term:
Power Supply Contract Divestitures	$	2.5	$	3.3
Total Energy Supply Obligations	$	16.9	$	17.1

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 a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker rate mechanism.

Power Supply Contract Divestitures—As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity 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 on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion).

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Massachusetts Green Communities Act—In compliance with the Massachusetts Green Communities Act, discussed below in Note 8, Commitments and Contingencies, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The facility associated with one of these contracts has been constructed and is operating. The other contracts are pending approval by the MDPU as well as subsequent facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

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 an unfunded 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, 2013, 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, 2013, 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, 2013, 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 December 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” The amendments in this ASU require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The Company adopted ASU 2011-11 and it did not have any impact on the Company’s Consolidated Financial Statements.

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 impacted its Consolidated Financial Statements.

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Reclassifications—Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. Most significant has been the reclassification of certain regulatory tracker mechanisms from Accrued Revenue and Other Current Liabilities to Regulatory Liabilities, the reclassification of exchange gas amounts from Gas Inventory to Exchange Gas Receivable on the Company’s Consolidated Balance Sheets, as discussed above in Regulatory Accounting and Exchange Gas Receivable, respectively. Also, energy efficiency program expenses, which were previously presented as Conservation & Load Management on the Company’s Consolidated Statements of Earnings are now included in Cost of Gas Sales and Cost of Electric Sales.

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,
	2013		2012		2013			2012			2013		2012		2013		2012
Total Operating Revenues	$	118.2	$	114.2	$	66.4		$	68.8		$	72.5	$	71.3	$	109.8	$	98.8
Operating Income	$	21.9	$	19.3	$	4.5		$	4.3		$	5.6	$	5.0	$	21.5	$	18.9
Net Income (Loss) Applicable to Common	$	10.8	$	9.0	$	(0.1	)	$	(0.4	)	$	0.6	$	0.5	$	10.3	$	9.0
	Per Share Data:
Earnings Per Common Share	$	0.79	$	0.83	$	(0.01	)	$	(0.03	)	$	0.04	$	0.03	$	0.75	$	0.66
Dividends Paid Per Common Share	$	0.345	$	0.345	$	0.345		$	0.345		$	0.345	$	0.345	$	0.345	$	0.345

Note 3: Segment Information

Unitil reports four segments: utility gas operations, utility electric operations, non-regulated, and other. Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capitol 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.

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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.

The following table provides significant segment financial data for the years ended December 31, 2013, 2012 and 2011 (millions):

Year Ended December 31, 2013	Gas		Electric		Non- Regulated		Other			Total
Revenues	$	170.4	$	190.7	$	5.8	$	—		$	366.9
Interest Income		0.5		2.2		0.1		0.4			3.2
Interest Expense		11.0		9.5		—		1.5			22.0
Depreciation & Amortization Expense		17.2		19.5		—		1.0			37.7
Income Tax Expense (Benefit)		7.5		5.1		0.8		(0.7	)		12.7
Segment Profit (Loss)		12.5		7.6		1.2		0.3			21.6
Segment Assets		502.3		402.8		6.2		9.3			920.6
Capital Expenditures		61.1		23.6		—		4.8			89.5
Year Ended December 31, 2012
Revenues	$	160.6	$	187.0	$	5.5	$	—		$	353.1
Interest Income		0.8		2.9		0.1		0.4			4.2
Interest Expense		11.1		9.5		—		1.7			22.3
Depreciation & Amortization Expense		15.7		18.0		—		1.4			35.1
Income Tax Expense (Benefit)		5.8		4.8		0.9		(0.5	)		11.0
Segment Profit (Loss)		8.9		7.6		1.3		0.3			18.1
Segment Assets		471.7		409.3		5.7		5.6			892.3
Capital Expenditures		43.9		21.2		—		3.4			68.5
Year Ended December 31, 2011
Revenues	$	159.2	$	188.1	$	5.5	$	—		$	352.8
Interest Income		0.5		0.9		0.1		0.1			1.6
Interest Expense		10.7		9.6		—		1.7			22.0
Depreciation & Amortization Expense		13.6		14.2		—		1.5			29.3
Income Tax Expense		4.3		5.2		1.1		(0.6	)		10.0
Segment Profit		6.7		7.8		1.7		0.1			16.3
Segment Assets		442.2		401.9		5.5		6.5			856.1
Capital Expenditures		33.6		20.3		—		3.2			57.1

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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 2013, 2012 and 2011, the Company recorded provisions for the energy commodity portion of bad debts of $1.4 million, $1.9 million and $1.8 million, respectively. These provisions were recognized in Purchased Electricity and Purchased Gas expense as the associated electric and gas utility revenues were billed. Purchased Electricity and Purchased Gas costs are recovered from customers through periodic rate reconciling mechanisms.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2011 – 2013 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2013
Electric	$	1.1	$	2.6	$	0.2	$	2.6	$	1.3
Gas		0.7		2.0		0.2		2.7		0.2
Other		0.1		—		—		—		0.1
	$	1.9	$	4.6	$	0.4	$	5.3	$	1.6
Year Ended December 31, 2012
Electric	$	1.7	$	1.4	$	0.3	$	2.3	$	1.1
Gas		0.5		2.2		0.3		2.3		0.7
Other		0.1		—		—		—		0.1
	$	2.3	$	3.6	$	0.6	$	4.6	$	1.9
Year Ended December 31, 2011
Electric	$	1.8	$	2.1	$	0.2	$	2.4	$	1.7
Gas		0.7		2.2		0.3		2.7		0.5
Other		0.1		—		—		—		0.1
	$	2.6	$	4.3	$	0.5	$	5.1	$	2.3

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

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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 Unitil Energy and Fitchburg 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 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.

At December 31, 2013, there were no restrictions on Unitil’s Retained Earnings for the payment of common dividends. Unitil Energy, Fitchburg, Northern Utilities and Granite State pay dividends to their sole shareholder, Unitil Corporation, and these dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders.

Debt Repayment—The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $541,938, $500,405, and $462,055 in 2013, 2012, and 2011, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2013 is: 2014 – $2,486,919; 2015 – $4,035,633; 2016 – $17,421,724; 2017 – $17,160,985 and 2018 – $30,133,332, respectively.

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 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

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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,
	2013		2012
Estimated Fair Value of Long- Term Debt	$	327.3	$	349.7

Details on long-term debt at December 31, 2013 and 2012 are shown below:

Long-Term Debt (millions)	December 31,
	2013		2012
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0
Unitil Energy First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0
8.49% Series, Due October 14, 2024		15.0		15.0
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		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0
Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		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
Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0
Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		2.3		2.8
Total Long-Term Debt		287.3		287.8
Less: Current Portion		2.5		0.5
Total Long-Term Debt, Less Current Portion	$	284.8	$	287.3

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.

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.

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A summary of interest expense and interest income is provided in the following table:

Interest Expense, net (millions)
	2013			2012			2011
Interest Expense
Long-term Debt	$	20.2		$	20.3		$	20.3
Short-term Debt		1.2			1.5			1.7
Regulatory Liabilities		0.6			0.5			—
Subtotal Interest Expense		22.0			22.3			22.0
Interest Income
Regulatory Assets		(2.3	)		(3.4	)		(1.1	)
AFUDC(1) and Other		(0.9	)		(0.8	)		(0.5	)
Subtotal Interest Income		(3.2	)		(4.2	)		(1.6	)
Total Interest Expense, net	$	18.8		$	18.1		$	20.4

⁽¹⁾ AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 and provides for a new 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 plus 1.375%. 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 following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2013 and December 31, 2012:

Revolving Credit Facility (millions)
	December 31,
	2013		2012
Limit	$	120.0	$	60.0
Outstanding	$	60.2	$	49.4
Available	$	59.8	$	10.6

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, 2013, 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%, 2.0%, and 2.2% during 2013, 2012, and 2011, respectively.

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

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price at which it sold the natural gas inventory to the asset manager. There was $12.5 million and $10.7 million of natural gas storage inventory at December 31, 2013 and 2012, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2013, which was payable in January 2014, is $2.7 million and recorded in Accounts Payable at December 31, 2013. The amount of natural gas inventory released in December 2012, which was payable in January 2013, is $2.1 million and recorded in Accounts Payable at December 31, 2012.

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, 2013, 2012 and 2011 amounted to $1.2 million, $1.3 million and $1.4 million respectively.

The following is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2013:

Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2014	$	1,244	$	390
2015		1,114		174
2016		926		40
2017		647		—
2018		294		—
2019 – 2023		15		—
Total Payments	$	4,240	$	604

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, 2013, there were approximately $19.1 million of guarantees outstanding and the longest term guarantee extends through October 2014.

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, 2013, the principal amount outstanding for the 8% Unitil Realty note was $2.3 million, and the principal amount outstanding for the 7.15% Granite State note was $10.0 million.

Note 6: Equity

The Company has common stock outstanding and Unitil Energy 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”. On April 21, 2011, the Company’s shareholders approved an increase in the authorized shares of the Company’s common stock. Shareholders approved an amendment to the Company’s Articles of Incorporation to increase the authorized number of shares of the Company’s common stock, from 16,000,000 shares to 25,000,000 shares in the aggregate. The Company had 13,841,400 and 13,780,601 shares of common stock outstanding at December 31, 2013 and December 31, 2012, respectively.

Unitil Corporation Common Stock Offering—On May 16, 2012, the Company issued and sold 2,760,000 shares of its common stock at a price of $25.25 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering were approximately $65.7 million and were used to make equity capital contributions to the Company’s regulated utility subsidiaries, repay short-term debt and for general corporate purposes.

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Dividend Reinvestment and Stock Purchase Plan—During 2013, the Company sold 39,559 shares of its common stock, at an average price of $29.01 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.1 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 2012 and 2011, the Company raised $1.1 million and $1.0 million, respectively, through the issuance of 41,752 and 39,473 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 March 28, 2013, 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 2013, 2012 and 2011, the Company repurchased 2,969, 6,368 and 8,765 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, $0.2 million and $0.2 million in 2013, 2012 and 2011, respectively.

During 2013, 2012 and 2011, 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. Awards may be grossed up to offset the participant’s tax obligations in connection with the 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 2011 – 2013 in conjunction with the Stock Plan are presented in the following table:

Issuance Date	Shares	Aggregate Market Value (millions)
2/9/11	24,330	$0.6
2/3/12	25,600	$0.7
2/4/13	21,240	$0.6

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There were 53,480 and 53,932 non-vested shares under the Stock Plan as of December 31, 2013 and 2012, respectively. The weighted average grant date fair value of these shares was $25.99 per share and $24.67 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 $0.7 million, $1.3 million and $0.7 million in 2013, 2012 and 2011, respectively. At December 31, 2013, there was approximately $0.7 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.4 years. There were no restricted shares forfeited or cancelled under the Stock Plan during 2013.

Restricted Stock Units

Restricted Stock Units 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. There were no Restricted Stock Units issued in conjunction with the Stock Plan during 2011.

The equity portion of Restricted Stock Units activity during 2013 and 2012 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	2013				2012
	Units		Weighted Average Stock Price		Units		Weighted Average Stock Price
Beginning Restricted Stock Units		3,883	$	27.39		—
Restricted Stock Units Granted		10,710	$	29.43		3,829	$	27.43
Dividend Equivalents Earned		310	$	29.47		54	$	24.62
Restricted Stock Units Settled		—				—
Ending Restricted Stock Units		14,903	$	28.90		3,883	$	27.39

Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2013 and 2012 is $0.2 million and less than $0.1 million, respectively, representing the fair value of liabilities associated with the portion of fully vested Restricted Stock Units that will be settled in cash.

Preferred Stock

Unitil Energy, has an aggregate of $0.2 million of 6.00% Series Non-Redeemable, Non-Cumulative Preferred Stock outstanding at December 31, 2013.

On December 1, 2012, Fitchburg redeemed and retired the two outstanding issues of its Redeemable, Cumulative Preferred Stock. The 8.00% Series was redeemed at par (aggregate par value of $1.0 million). The 5.125% Series was redeemed at par plus a premium of 1.28% (aggregate value of $0.8 million). Fitchburg used operating cash to effect this transaction.

Fitchburg was required to offer to redeem annually a given number of shares of each series of its Redeemable, Cumulative Preferred Stock and to purchase such shares that were tendered by holders of the respective stock. In addition, Fitchburg had the option to redeem the Redeemable, Cumulative Preferred Stock at a given redemption price, plus accrued dividends.

The aggregate purchases of Redeemable, Cumulative Preferred Stock during 2013, 2012 and 2011 related to the annual redemption offer were $0, $8,000 and $8,600, respectively.

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Earnings Per Share

The following table reconciles basic and diluted earnings per share.

(Millions except shares and per share data)	2013		2012		2011
Earnings Available to Common Shareholders	$	21.6	$	18.1	$	16.3
Weighted Average Common Shares Outstanding—Basic (000’s)		13,773		12,669		10,880
Plus: Diluted Effect of Incremental Shares (000’s)		2		3		3
Weighted Average Common Shares Outstanding—Diluted (000’s)		13,775		12,672		10,883
Earnings per Share—Basic and Diluted	$	1.57	$	1.43	$	1.50

For 2013, 2012 and 2011, respectively, 4,481, 24,325 and 1,642 weighted average non-vested restricted shares were not included in the above computation because the effect would have been antidilutive.

Note 7: Energy Supply

Natural Gas Supply

Unitil 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’ commercial & industrial (C&I) customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors, and third-party supply is prevalent among Northern Utilities’ larger C&I customers. Most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. Fitchburg’s residential and C&I business customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors. Many large and some medium C&I customers purchase their supplies 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. The approved costs associated with the acquisition of such wholesale natural gas supplies for 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 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), to truck supplies to storage facilities within Northern Utilities’ service territory.

Northern Utilities has available under firm contract 100,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 3.4 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 of one year or less, as well as from producers and marketers on the spot market. Fitchburg arranges for gas delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, or in the case of LNG or liquefied propane gas (LPG), to truck supplies to storage facilities within Fitchburg’s service territory.

Fitchburg has available under firm contract 14,057 MMbtu per day of year-round and seasonal transportation and 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.

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Electric Power Supply

The restructuring of the electric utility industry in New Hampshire required the divestiture of Unitil’s power supply arrangements and the procurement of replacement supplies, which provided the flexibility for migration of customers to and from utility energy service. Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the ISO-NE markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s customers.

As a result of restructuring of the electric utility industry in Massachusetts and New Hampshire, Unitil’s customers in both New Hampshire and Massachusetts have the opportunity to purchase their electric supply from competitive third-party energy suppliers. As of December 2013, 69% of Unitil’s largest New Hampshire customers, representing 23% of total New Hampshire electric energy sales, and 78% of Unitil’s largest Massachusetts customers, representing 31% of total Massachusetts electric energy sales, are purchasing their electric power supply in the competitive market. However, most residential and small commercial customers continue to purchase their electric supply through Unitil’s distribution utilities under regulated energy rates and tariffs. We believe that the concentration of the competitive retail market on higher use customers has been a common experience throughout the New England electricity market.

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 with various wholesale suppliers.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. On July 31, 2012, the NHPUC approved Unitil Energy’s request to modify its Default Service solicitation to a process where 100% of the Default Service requirements are acquired for six months. Unitil Energy completed the transition to this procurement strategy in late 2013. Currently, Unitil Energy Default Service power supply contracts for small, medium and large customers are acquired every six months, are 12 months in duration and provide 100% of the supply requirements.

Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service energy supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential, 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

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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 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 in the Commonwealth, and the MDPU’s regulations implementing the legislation. Fitchburg will recover its 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 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. As a result of the restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most of Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers have the opportunity 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.

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. The remaining balance of these assets, to be recovered principally over the next year, is $12.7 million as of December 31, 2013 including $10.2 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet. Unitil’s distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Northern Utilities—Base Rates—Maine—On December 27, 2013, the MPUC approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine operations, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed to implement a Targeted Infrastructure Replacement Adjustment (TIRA) to provide for annual adjustments to distribution base rates to recover costs associated with the Company’s investments in targeted operational and safety-related infrastructure replacement and upgrade projects. The TIRA will have an initial term of four years, and covers expenditures in each of the Calendar Years 2013, 2014, 2015, and 2016. The settlement agreement also provides for Earning Sharing where Northern would be allowed to retain all earnings up to a return of 10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement continues and revises the service quality plan (SQP) that Northern has been operating under since 2004 and established in Docket No. 2002-140. The revised SQP consists of

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seven metrics with an appurtenant administrative penalty for failure to meet any of the seven metrics. The settlement agreement further provides that Northern will be subject to a maximum annual penalty of $500,000 if it fails to meet any of the baseline performance targets under the revised SQP.

Northern Utilities—Base Rates—New Hampshire—In April 2013, Northern Utilities’ New Hampshire operations filed a rate case with the NHPUC requesting approval to increase its natural gas distribution base rates by $5.2 million in gas distribution base revenue or approximately 9.4 percent over test year operating revenue. The filing included a proposed multi-year rate plan that included cost tracking mechanisms to recover future capital costs associated with Northern Utilities’ infrastructure replacements and safety and reliability improvements to the natural gas distribution system. Northern Utilities has been authorized to implement temporary rates to collect a $2.5 million increase (annualized) in gas distribution revenue, effective July 1, 2013. The Company is currently in settlement discussions with the NHPUC and expects a final rate order from the NHPUC in the first half of 2014. Once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were established, July 1, 2013.

Unitil Energy—Base Rates—Unitil Energy’s second step increase of $2.8 million went into effect on May 1, 2013, which included rate increases to recover capital improvements, increased spending for its vegetation management and reliability enhancement programs and an increase in its storm reserve fund. On April 26, 2011, the NHPUC approved a rate settlement with a permanent increase of $5.2 million in annual revenue effective July 1, 2010, and an additional increase of $5.0 million in annual revenue effective May 1, 2011. The settlement extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with step increases in annual revenue on May 1, 2012, May 1, 2013 and May 1, 2014, to support Unitil Energy’s continued capital improvements to its distribution system. Unitil Energy’s first step increase was approved as filed, effective May 1, 2012.

Granite State—Base Rates—In June 2013, Granite State submitted to the FERC its latest incremental annual rate adjustment, in the amount of $0.4 million, with rates effective August 1, 2013. The FERC approved the increase on July 30, 2013. Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file a limited Section 4 rate case that includes incremental annual rate adjustments to recover the revenue requirements for certain specified future capital cost additions to gas transmission plant projects.

Fitchburg—Electric Base Rates Filed—In July 2013, Fitchburg filed a rate case with the MDPU requesting approval to increase its electric distribution rates. The Company requested an increase of $6.7 million in electric base revenue or approximately 11.5 percent over test year operating revenue. Included in the amount of this annual increase is approximately $2.1 million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to three severe storms, Tropical Storm Irene, the October 2011 snowstorm and Superstorm Sandy. The filing includes a proposed modified revenue decoupling mechanism by means of an annual revenue adjustment mechanism by either a capital cost tracker mechanism or a multi-year rate plan featuring a revenue cap index. The filing also includes a proposal to establish a major storm reserve fund to address the costs of future major storms by collecting $2.8 million per year through a reconciling storm recovery adjustment factor beginning January 1, 2015. The rate case filing is subject to regulatory review with hearings scheduled throughout January 2014 and approval with final rate orders expected in the second quarter of 2014.

Major Storms—Fitchburg and Unitil Energy

Superstorm Sandy – On October 29-30, 2012, a severe storm struck the eastern seaboard of the United States, causing extensive damage to electric facilities and loss of service to significant numbers of customers of several utilities. Fitchburg and Unitil Energy incurred approximately $1.1 million and $2.7 million, respectively, in costs for the repair and replacement of electric distribution systems damaged during the storm, including $0.3 million and $0.4 million related to capital construction for Fitchburg and Unitil Energy, respectively. The amount and timing of the cost recovery of these storm restoration expenditures for Fitchburg will be determined in its rate case. The cost recovery for Unitil Energy has been approved as discussed below. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations.

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Fitchburg—Storm Cost Deferral—On May 1, 2012 the MDPU approved Fitchburg’s request to defer $4.3 million of storm costs associated with two severe storms which occurred in 2011, and Fitchburg is seeking recovery of these costs in the electric rate case it filed in July 2013.

Unitil Energy—2012 Storm Costs—On April 25, 2013, the NHPUC approved the recovery of $2.3 million of costs to repair damage to Unitil Energy’s electrical system resulting from Superstorm Sandy over a five-year period, with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, applied to the uncollected balance through the recovery period.

Fitchburg—Electric Operations—On November 15, 2013, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing also includes the reconciliation of costs and revenues for a number of other surcharges and cost factors which are subject to review and approval by the MDPU. Many of the surcharges and cost factors were redesigned based on cost-based rate design in compliance with a MDPU order in its Investigation into Cost-Based Rate Design for Reconciliation Factors, which resulted from the “Act Relative to Competitively Priced Electricity in the Commonwealth”, signed into law by the Governor of Massachusetts on August 3, 2012. All of the rates were approved effective January 1, 2014 for billing purposes, subject to reconciliation, pending investigation by the MDPU. This matter remains pending.

Fitchburg—Service Quality—On March 1, 2013, Fitchburg submitted its 2012 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. On March 29, 2013, the MDPU issued its order approving the 2011 Service Quality Report for Fitchburg’s gas division. The 2011-2012 Service Quality reports for Fitchburg’s electric division remain pending.

On December 11, 2012, the MDPU opened an investigation into the service quality provided by the gas and electric distribution companies in Massachusetts and the Service Quality guidelines currently in effect. The MDPU investigation will review existing and potential new reliability, safety, and customer satisfaction metrics; potential penalties for downed wire response; potential clean energy metrics; penalty provisions, including penalty offsets for superior performance in other metrics for poor performance on a different metric; and review of historic data for use in establishing service quality benchmarks. Fitchburg has been an active participant in this docket, which remains pending.

Fitchburg—Other—On February 5, 2013, there was a natural gas explosion in the city of Fitchburg, Massachusetts in an area served by Fitchburg’s gas division resulting in property damage to a number of commercial and residential properties. The MDPU, pursuant to its authority under state and federal law, has commenced an investigation of the incident, with which Fitchburg is cooperating. The Company does not believe this incident or investigation will have a material adverse impact on the Company’s financial condition or results of operations.

On February 11, 2009, the Massachusetts Supreme Judicial Court (SJC) issued its decision in the Attorney General’s (AG) appeal of the MDPU orders relating to Fitchburg’s recovery of bad debt expense. The SJC agreed with the AG that the MDPU was required to hold hearings regarding changes in Fitchburg’s tariff and rates, and on that basis vacated the MDPU orders. The SJC, however, declined to rule on an appropriate remedy, and remanded the cases back to the MDPU for consideration of that issue. In the Company’s August 1, 2011 rate decision, the MDPU held that the approval of dollar for dollar collection of supply-related bad debt in the Company’s rate cases in 2006 (gas) and 2007 (electric) satisfied the requirement for a hearing ordered by the SJC. The MDPU has opened a docket to address the amounts collected by Fitchburg between the time the MDPU first approved dollar for dollar collection of the Company’s bad debt, and the rate decisions in 2006 and 2007. Briefs were filed in June 2013. This matter remains pending before the MDPU.

On July 2, 2008, the Governor of Massachusetts signed into law “The Green Communities Act” (the GC Act), an energy policy statute designed to substantially increase energy efficiency and the development of renewable energy resources in Massachusetts. The GC Act provides for utilities to recover in rates the incremental costs associated with its various mandated programs. Several regulatory proceedings have been initiated to implement various provisions of the GC Act, including provisions for each distribution company

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to file enhanced three-year energy efficiency investment plans, plans to establish smart grid pilot programs, proposals to purchase long-term contracts for renewable energy, special tariffs to allow the net metering of customer-owned renewable generation, and terms and conditions for purchasing supplier receivables. Fitchburg’s first two three-year energy efficiency investment plans, plans to establish smart grid pilot programs, net metering tariffs and proposals to purchase long-term contracts for renewable energy have been approved by the MDPU. Terms and conditions for purchasing supplier receivables are under review in a separately designated docket.

On August 3, 2012, the Governor of Massachusetts signed into law “An Act Relative to Competitively Priced Electricity in the Commonwealth”, which both increases electric distribution companies’ obligations to purchase renewable energy resources and the availability of net metering. This act also includes changes to the MDPU’s ratemaking procedures and authority for reviewing mergers and acquisitions for electric and gas distribution companies. With these changes, electric distribution companies are required to file rate schedules every five years, and gas distribution companies every ten years. The MDPU also opened a proceeding, as mandated by the act, to establish a cost-based rate design for costs that are currently recovered from distribution customers through a reconciling factor. On December 17, 2013, the MDPU issued an order establishing the new rate design allocation methodologies. Fitchburg has participated with the other electric utilities and entered into long-term renewable contracts for its pro-rata share of renewable energy projects. The facility associated with one of these contracts has been constructed and is operating. The other contracts are pending approval by the MDPU as well as subsequent facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

On August 6, 2012, the Governor of Massachusetts also signed into law “An Act Relative to the Emergency Response of Public Utilities”, which establishes a new storm trust fund and requires that penalties levied by the MDPU for violations of its emergency preparedness rules be credited to customers.

On December 23, 2013 the MDPU issued two orders related to Grid Modernization. The MDPU opened an investigation on its own motion into Modernization of the Electric Grid and, in a separate but related order, opened an investigation into Electric Vehicles and Electric Vehicle Charging. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices” and all related objectives. It sets forth a straw proposal which would require each electric distribution company to submit a ten-year strategic grid modernization plan (GMP) within six months of a final Order. As part of the GMP each company must also include a comprehensive advanced metering plan (CAMP), and each company is required to achieve advanced metering functionality. The filing of a GMP will be 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. A cost recovery mechanism is proposed only for investments in advanced metering. The MDPU also proposes to address in separate, upcoming proceedings (1) time varying rates, (2) cybersecurity, privacy, and access to meter data, and (3) electric vehicles (EVs). In the Electric Vehicle Order, the MDPU seeks to establish policies and regulations that will help facilitate and accommodate the widespread adoption of EVs. Among other objectives, the proceeding looks to evaluate (1) EV charging and its impact on the electric distribution system, (2) electric distribution company involvement in EV charging, (3) residential metering practices and rates for EVs, and (4) consumer protection issues. Both of these matters remain pending.

Unitil Corporation—FERC Audit—On November 3, 2011, the FERC commenced an audit of Unitil Corporation, including its associated service company and its electric and natural gas distribution companies. Among other requirements, the audit evaluated the Company’s compliance with: i) cross-subsidization restrictions on affiliate transactions; ii) regulations under the Energy Policy Act of 2005; and the iii) uniform system of accounts for centralized service companies. The final audit report was issued on February 28, 2013 and the Company submitted its plan to address the audit findings and implement the audit recommendations on March 29, 2013. The Company submitted its quarterly progress update on the implementation of the audit recommendations on April 30, 2013. On June 5, 2013 the FERC advised the Company that the audit is complete; no further action is required by the Company. The audit findings did not have an impact on the Company’s financial condition or results of operations.

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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 the Company’s financial position.

In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (Fitchburg), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman 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 Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit would now proceed with only the twelve named plaintiffs seeking damages; however, the plaintiffs have appealed this decision to the Massachusetts Supreme Judicial Court (the “SJC”). The SJC has accepted the matter for review. The Town of Lunenburg has also filed a separate action in Massachusetts Worcester County Superior Court arising out of the December 2008 ice storm. The parties to this action have agreed to put this matter on hold pending the decision of the Supreme Judicial Court in Bellermann. The Company continues to believe these suits are without merit and will continue to defend itself vigorously.

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 believes it is in material compliance with applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2013, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you 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.

Northern Utilities Manufactured Gas Plant Sites—Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites that were operated from the mid-1800s through the mid-1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. This program has also documented the presence of MGP sites in Lewiston and Portland, Maine and a former MGP disposal site in Scarborough, Maine. Northern Utilities has worked with the environmental regulatory agencies in both New Hampshire and Maine to address environmental concerns with these sites.

Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, Lewiston and Scarborough sites. The site in Portland has been investigated and remedial activities are ongoing with the most recent phase completed in December 2013. Although Northern Utilities recently finalized a long-term lease on the Portland property, the State of Maine has announced its intention to acquire the site in the short-term for the expansion of the adjacent marine terminal. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs pending either State acquisition or until all remedial activities are completed.

The NHPUC and MPUC have approved the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over a seven-year amortization period. For Northern Utilities’ Maine division, the MPUC authorized the recovery of environmental remediation costs over a rolling five-year amortization schedule.

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Included in Environmental Obligations on the Company’s Consolidated Balance Sheet at December 31, 2013 are accrued liabilities totaling $1.8 million associated with Northern Utilities’ environmental remediation obligations for former MGP sites. In addition to the amounts noted above, there are $1.0 million of accrued liabilities in Other Current Liabilities on the Company’s Consolidated Balance Sheet at December 31, 2013 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 is in the process of seeking regulatory approval to implement a permanent remediation solution at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts. Included in Environmental Obligations on the Company’s Consolidated Balance Sheets at December 31, 2013 are accrued liabilities totaling $12.0 million related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site. A corresponding Regulatory Asset was recorded to reflect that the recovery of this environmental remediation cost is 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, without carrying costs.

The Company’s ultimate liability for future environmental remediation costs, including MGP site costs, may vary from estimates, which may be adjusted as new information or future developments become available. 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.

The following table shows the balances and activity in the Company’s liability for Environmental Obligations for 2013 and 2012.

ENVIRONMENTAL OBLIGATIONS

(Millions)	December 31,
	2013		2012
Total Environmental Obligations—Balance at Beginning of Period	$	14.8	$	14.7
Changes in Estimates		—		0.1
Liabilities Assumed		—		—
Less: Payments / Reductions		—		—
Total Environmental Obligations—Balance at End of Period		14.8		14.8
Less: Current Portion(1)		1.0		1.0
Environmental Obligations—noncurrent—Balance at End of Period	$	13.8	$	13.8

⁽¹⁾  Reflects amounts included in Other Current Liabilities on the Company’s Consolidated Balance Sheets.

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Note 9: Income Taxes

Provisions for Federal and State Income Taxes in the accompanying consolidated statements of earnings for the years ended December 31, 2013, 2012 and 2011 are shown in the table below:

	($000’s)
	2013			2012			2011
Current Federal Tax Provision (Benefit)
Current Benefit of Operating Loss Carrybacks	$	—		$	—		$	—
Total Current Federal Tax Provision (Benefit)		—			—			—
Deferred Federal Tax Provision (Benefit)
Utility Plant Differences		28,907			6,019			13,002
Net Operating Loss Carryforwards		(8,053	)		2,835			(4,844	)
Regulatory Assets and Liabilities		(11,483	)		472			513
Other, net		681			(241	)		(695	)
Total Deferred Federal Tax Provision (Benefit)		10,052			9,085			7,976
Total Federal Tax Provision		10,052			9,085			7,976
State
Current		386			132			1,358
Deferred		2,214			1,759			691
Total State Tax Provision		2,600			1,891			2,049
Total Provision for Federal and State Income Taxes	$	12,652		$	10,976		$	10,025

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:

	2013			2012			2011
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, Net		5			5			5
Utility Plant Differences		(2	)		(2	)		(1	)
Other, Net		—			1			—
Effective Income Tax Rate		37	%		38	%		38	%

Temporary differences which gave rise to current deferred tax assets and liabilities in 2013 and 2012, are shown below:

Current Deferred Income Taxes (000’s)	2013		2012
Accrued Revenue, Current Portion	$	6,583	$	13,568
Other, net		108		(168	)
Total Current Deferred Income Tax Liabilities	$	6,691	$	13,400

Temporary differences which gave rise to noncurrent deferred tax assets and liabilities in 2013 and 2012, are shown below:

Noncurrent Deferred Income Taxes (000’s)	2013			2012
Utility Plant Differences	$	102,479		$	66,907
Net Operating Loss Carryforwards		(17,403	)		(8,521	)
AMT Tax Credit Carryforwards		(1,538	)		(1,538	)
Regulatory Assets & Liabilities		17,174			17,872
Retirement Benefit Obligations		(28,287	)		(38,644	)
Other, net		754			2,606
Total Noncurrent Deferred Income Tax Liabilities	$	73,179		$	38,682

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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 which gave rise to the revision become known.

The Company filed its tax returns for the year ended December 31, 2012 with the Internal Revenue Service (IRS) in September 2013 and generated federal net operating loss (NOL) carryforward assets of $6.6 million principally due to tax repair expensing and bonus depreciation. As of December 31, 2013, the Company had recorded cumulative federal and state NOL carryforward assets of $17.4 million to offset against taxes payable in future periods. If unused, the Company’s state NOL carryforward assets will begin to expire in 2019 and the federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2013, the Company had $1.5 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

In the third quarter of 2013, the State of Massachusetts eliminated the classification of Public Service Corporation for utilities and now all public service entities, including utilities, will be taxed at the Massachusetts 8% corporate rate effective tax years beginning after January 1, 2014. Additionally, corporations in Massachusetts will now be able to carryforward NOLs created after January 1, 2014.

The Company evaluated its tax positions at December 31, 2013 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, 2010; December 31, 2011; and December 31, 2012.

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.

• The Unitil Corporation Supplemental Executive Retirement Plan (SERP)—The SERP is an unfunded retirement plan, with participation limited to executives selected by the Board of Directors.

Effective with the acquisitions of Northern Utilities and Granite State, the Company assumed the assets and obligations of the Northern Utilities and Granite State pension plans with respect to active union employees. All other active employees of Northern Utilities and Granite State effectively became members of the Company’s Pension Plan as of the acquisitions closing date.

Certain employees of Northern Utilities qualified for participation in the Company’s PBOP Plan effective with the acquisition closing date.

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The following table includes the key assumptions used in determining the Company’s benefit plan costs and obligations:

	2013			2012			2011
Used to Determine Plan costs for years ended December 31:
Discount Rate		4.00	%		4.60	%		5.35	%
Rate of Compensation Increase		3.00	%		3.00	%		3.50	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		6.50	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2017			2017			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	1,169		$	981		$	909
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(895	)	$	(756	)	$	(705	)
Used to Determine Benefit Obligations at December 31:
Discount Rate		4.80	%		4.00	%		4.60	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		8.00	%		6.50	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health care Cost Trend Rate is reached		2018			2017			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	9,957		$	11,808		$	9,109
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(7,942	)	$	(9,291	)	$	(7,217	)

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 2013, 2012 and 2011, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $431,000, $367,000 and $325,000, respectively, in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2013, 2012 and 2011 was 3.00%, 3.00% and 3.50%, based on the expected long-term increase in compensation costs for personnel covered by the plans.

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

	Pension Plan									PBOP Plan									SERP
	2013			2012			2011			2013			2012			2011			2013		2012		2011
Service Cost	$	3,573		$	3,227		$	2,941		$	2,523		$	2,066		$	1,918		$	73	$	289	$	285
Interest Cost		4,567			4,633			4,684			2,448			2,303			2,279			241		211		227
Expected Return on Plan Assets		(5,955	)		(5,390	)		(4,840	)		(722	)		(695	)		(818	)		—		—		—
Prior Service Cost Amortization		208			188			249			1,701			1,729			1,729			11		11		11
Transition Obligation Amortization		—			—			—			—			21			21			—		—		—
Actuarial Loss Amortization		4,229			3,617			3,132			786			129			—			184		64		78
Sub-total		6,622			6,275			6,166			6,736			5,553			5,129			509		575		601
Amounts Capitalized and Deferred		(2,929	)		(2,726	)		(2,590	)		(3,010	)		(2,127	)		(1,622	)		—		—		—
NPBC Recognized	$	3,693		$	3,549		$	3,576		$	3,726		$	3,426		$	3,507		$	509	$	575	$	601

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The estimated amortizations related to Actuarial Loss and Prior Service Cost included in the Company’s Retirement plan costs over the next fiscal year is $3.1 million, $1.7 million and $0.1 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 2013, 2012 and 2011 before capitalization and deferral was $6.6 million, $6.3 million and $6.2 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2013, 2012 and 2011 would have been $6.6 million, $6.7 million and $5.7 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:	2013			2012			2013			2012			2013			2012
Plan Assets at Beginning of Year	$	72,411		$	59,700		$	8,301		$	7,339		$	—		$	—
Actual Return on Plan Assets		10,204			7,780			1,154			837			—			—
Employer Contributions		3,700			9,387			3,280			2,190			53			53
Participant Contributions		—			—			36			18			—			—
Acquired Plan Assets		—			—			—			—			—			—
Benefits Paid		(3,764	)		(4,456	)		(1,942	)		(2,083	)		(53	)		(53	)
Plan Assets at End of Year	$	82,551		$	72,411		$	10,829		$	8,301		$	—		$	—
Change in PBO:
PBO at Beginning of Year	$	116,492		$	102,719		$	62,092		$	50,930		$	6,207		$	4,615
Service Cost		3,573			3,227			2,523			2,066			73			289
Interest Cost		4,567			4,633			2,448			2,303			241			211
Participant Contributions		—			—			36			18			—			—
Plan Amendments		—			617			(183	)		(318	)		—			—
Benefits Paid		(3,764	)		(4,456	)		(1,942	)		(2,083	)		(53	)		(53	)
Actuarial (Gain) or Loss		(12,573	)		9,752			(8,075	)		9,176			(611	)		1,145
PBO at End of Year	$	108,295		$	116,492		$	56,899		$	62,092		$	5,857		$	6,207
Funded Status: Assets vs PBO	$	(25,744	)	$	(44,081	)	$	(46,070	)	$	(53,791	)	$	(5,857	)	$	(6,207	)

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 of $42.6 million and $62.5 million at December 31, 2013 and 2012, respectively, to account for the future collection of these plan obligations in electric and gas rates.

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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 $96.9 million and $103.4 million as of December 31, 2013 and 2012, respectively. The ABO for the SERP was $5.1 million and $4.8 million as of December 31, 2013 and 2012, respectively. For the PBOP Plan, the ABO and PBO are the same.

On August 17, 2006, the Pension Protection Act of 2006 (PPA) was signed into law. Included in the PPA were new minimum funding rules which went into effect for plan years beginning in 2008. The funding target was 100% of a plan’s liability (as determined under the PPA) with any shortfall amortized over seven years, with lower (92% – 100%) funding targets available to well-funded plans during the transition period. Due to the significant declines in the valuation of capital markets during 2008, the Worker, Retiree, and Employer Recovery Act of 2008 (Recovery Act) was signed into law on December 23, 2008. Included in the Recovery Act are temporary modifications to the minimum funding rules set forth in the PPA such that all plans, except those that were subject to deficit reduction contribution requirements in 2007, are allowed to amortize any shortfall from the lower funding targets, rather than the 100% target, for the 2008—2010 plan years. The Company’s Pension Plan was 80% funded under the requirements of the Employee Retirement Income Security Act of 1974 (ERISA) as of January 1, 2010, which resulted in a shortfall of $10.2 million. This shortfall was being amortized over seven years with annual payments of $1.7 million, beginning in 2010. The $1.7 million payment for 2011 is included in the Employer Contributions amounts shown in the table below.

On June 25, 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 (Relief Act) was signed into law. The pension relief portion of the Relief Act provides two alternative shortfall amortization periods to the seven year amortization period required under the PPA. The Company evaluated the two alternative shortfall amortization periods under the Relief Act and made the decision to continue with the seven year amortization period.

On July 6, 2012, the Moving Ahead for Progress in the 21st Century Act (MAP-21) was signed into law. MAP-21 increased the interest rates used to determine pension liability. The Company elected to apply the provisions of MAP-21 for purposes of determining pension liability for minimum funding purposes for the 2012 plan year. As part of this decision, the Company contributed $3.1 million in additional contributions in 2012 for the 2011 plan year to achieve 100% funding on the MAP-21 basis as of January 1, 2012. This eliminated the amortization payments created in prior years, discussed above. In addition, the minimum required contribution for the 2012 plan year decreased from $6.1 million to $1.0 million.

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2014 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
	2013		2012		2011		2013		2012		2011		2013		2012		2011
Employer Contributions	$	3,700	$	9,387	$	8,813	$	3,280	$	2,190	$	—	$	53	$	53	$	53
Participant Contributions	$	—	$	—	$	—	$	36	$	18	$	13	$	—	$	—	$	—
Benefit Payments	$	3,764	$	4,456	$	3,438	$	1,942	$	2,083	$	1,644	$	53	$	53	$	53

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

Estimated Future Benefit Payments
	Pension		PBOP		SERP
2014	$	4,495	$	1,914	$	384
2015		4,617		2,056		380
2016		4,742		2,129		375
2017		5,050		2,277		369
2018		5,188		2,404		364
2019 - 2023	$	31,826	$	14,496	$	1,925

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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 48% in common stock equities, 37% in fixed income securities, 10% in real estate securities and 5% 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 2014			Actual Allocation at December 31,
				2013			2012			2011
Equity Funds		48	%		54	%		48	%		49	%
Debt Funds		37	%		32	%		47	%		46	%
Real Estate Fund		10	%		1	%		0	%		0	%
Asset Allocation Fund(1)		5	%		5	%		5	%		5	%
Other(2)		0	%		8	%		0	%		0	%
Total					100	%		100	%		100	%

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

⁽²⁾ Represents investments being held in cash equivalents as of December 31, 2013 pending transfer into a Real Estate Fund.

PBOP Plan	Target Allocation 2014			Actual Allocation at December 31,
				2013			2012			2011
Equity Funds		55	%		57	%		56	%		55	%
Debt Funds		45	%		43	%		44	%		45	%
Total					100	%		100	%		100	%

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.50% for 2013. 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, 2013 and 2012. 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 and are categorized in Level 3.

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Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2013 and 2012 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)
2013
Pension Plan Assets:
Equity Funds	$	44,201	$	44,201	$	—	$	—
Fixed Income Funds		26,276		26,276		—		—
Asset Allocation Fund		4,574		4,574		—		—
Real Estate Fund		1,125		—		—		1,125
Cash Equivalents		6,375		6,375		—		—
Total Assets	$	82,551	$	81,426	$	—	$	1,125
2012
Pension Plan Assets:
Equity Funds	$	34,742	$	34,742	$	—	$	—
Fixed Income Funds		34,251		34,251		—		—
Asset Allocation Fund		3,418		3,418		—		—
Total Assets	$	72,411	$	72,411	$	—	$	—

The following tables set forth additional disclosures of Pension Plan investments whose fair value is estimated using net asset value per share as of December 31, 2013. There were no Pension Plan investments whose fair value is estimated using net asset value per share as of December 31, 2012:

	Fair Value Estimated Using NAV Per Share
	December 31, 2013
Description	Fair Value	Unfunded Commitment	Redemption Frequency	Redemption Notice Period
SEI Core Property Collective Investment Trust Fund(1)	$1,125,000	$—	Quarterly	65 days

⁽¹⁾  The SEI Core Property Collective Investment Trust Fund, through the SEI Core Property Fund, seeks both current income and long-term capital appreciation through investing in underlying funds that acquire, manage, and dispose of commercial real estate properties.

The table below sets forth a summary of changes in the fair value of the Pension Plan’s Level 3 assets for the year ended December 31, 2013:

	Level 3 Assets
	SEI Core  Property Collective Investment Trust Fund
Balance at December 31, 2012	$	—
Purchases		1,125,000
Balance at December 31, 2013	$	1,125,000
Amount of Total Gains or Losses for the Year Attributable to the Change in Unrealized Gains or Losses Relating to Assets Still Held at December 31, 2013	$	—

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Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2013 and 2012 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)
2013
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	4,689	$	4,689	$	—	$	—
Index Funds		4,467		4,467
Equity Funds		1,673		1,673
Total Assets	$	10,829	$	10,829	$	—	$	—
2012
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	3,670	$	3,670	$	—	$	—
Index Funds		3,357		3,357
Equity Funds		1,274		1,274
Total Assets	$	8,301	$	8,301	$	—	$	—

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 $1,678,000, $1,387,000 and $1,190,000 for the years ended December 31, 2013, 2012, and 2011, 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, 2013. Based on this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of December 31, 2013 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, 2013, based upon criteria established in the “Internal Control—Integrated Framework” 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, 2013.

McGladrey LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2013, 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, 2013 that have materially affected, or are reasonably likely to materially affect, Unitil’s internal control over financial reporting.

Item 9B. Other Information

On January 29, 2014, the Company issued a press release announcing its results of operations for the quarter and year ended December 31, 2013. The press release is furnished with this Annual Report on Form 10-K as Exhibit 99.1.

83

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 22, 2014. 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 22, 2014. 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 22, 2014. 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 22, 2014.

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 22, 2014.

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 22, 2014, 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 22, 2014.

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 22, 2014.

84

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 Balance Sheets—December 31, 2013 and 2012

• Consolidated Statements of Earnings for the years ended December 31, 2013, 2012, and 2011

• Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012, and 2011

• Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2013, 2012, and 2011

• Notes to Consolidated Financial Statements

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions, are not applicable, or information required is included in the financial statements or notes thereto and, therefore, have been omitted.

(3) – LIST OF EXHIBITS

Exhibit Number		Description of Exhibit	Reference*
	3.1	Articles of Incorporation of Unitil Corporation.	Exhibit 3.1 to Form S-14 Registration Statement No. 2-93769 dated October 12, 1984
	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 3.4 to Post-Effective Amendment No. 1 to Form S-3 Registration Statement No. 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)
	3.6	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)
	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)

85

Exhibit Number		Description of Exhibit	Reference*
	4.2	Fitchburg Note Agreement dated November 30, 1993 for the 6.75% Notes due November 23, 2023.	Exhibit 4.18 to Form 10-K for 1993 (SEC File No. 1-8858)
	4.3	Fitchburg Note Agreement dated January 26, 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)
	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)

86

Exhibit Number		Description of Exhibit	Reference*
	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 (Amended and Restated Effective as of January 1, 2009), as amended to date	Filed herewith
	10.14***	Amended and Restated Employment Agreement effective as of November 1, 2012 by and between Unitil Corporation and Robert G. Schoenberger.	Exhibit 10.1 to Form 8-K dated September 19, 2012 (SEC File No. 1-8858)
	10.15***	Employment Agreement dated June 5, 2013 between Unitil Corporation and Robert G. Schoenberger	Exhibit 10.1 to Form 8-K dated June 5, 2013 (SEC File No. 1-8858)
	10.16	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)
	10.17	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—Compensation of Directors.	Exhibit 10.21 to Form 10-K for 2012 (SEC File No. 1-8858)
	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

87

Exhibit Number		Description of Exhibit	Reference*
	16.1	Letter Re: Change in Certifying Accountant	Exhibit 16.1 to Form 8-K dated September 19, 2013 (SEC File No. 1-8858)
	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 January 29, 2014 Announcing Earnings For the Quarter and Year Ended December 31, 2013	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.

88

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 January 29, 2014	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	January 29, 2014
/S/    MARK H. COLLIN         Mark H. Collin	Principal Financial Officer	January 29, 2014
/S/    LAURENCE M. BROCK         Laurence M. Brock	Principal Accounting Officer	January 29, 2014
/S/    ALBERT H. ELFNER, III         Albert H. Elfner, III	Director	January 29, 2014
/S/    M. BRIAN O’SHAUGHNESSY         M. Brian O’Shaughnessy	Director	January 29, 2014
/S/    WILLIAM D. ADAMS         William D. Adams	Director	January 29, 2014
/S/    DR. SARAH P. VOLL         Dr. Sarah P. Voll	Director	January 29, 2014
/S/    EBEN S. MOULTON         Eben S. Moulton	Director	January 29, 2014
/S/    DAVID P. BROWNELL         David P. Brownell	Director	January 29, 2014
/S/    EDWARD F. GODFREY         Edward F. Godfrey	Director	January 29, 2014
/S/    MICHAEL B. GREEN         Michael B. Green	Director	January 29, 2014
/S/    DR. ROBERT V. ANTONUCCI         Dr. Robert V. Antonucci	Director	January 29, 2014
/S/    LISA CRUTCHFIELD         Lisa Crutchfield	Director	January 29, 2014
/S/  DAVID A. WHITELEY         David A. Whiteley	Director	January 29, 2014

89

EXHIBIT INDEX

Exhibit No.		Description
	10.13	Unitil Corporation Tax Deferred Savings and Investment Plan (Amended and Restated Effective as of January 1, 2009), as amended to date
	11.1	Computation in Support of Earnings per Share
	12.1	Computation in Support of Ratio of Earnings to Fixed Charges
	21.1	Subsidiaries of Registrant
	23.1	Consent of Independent Registered Public Accounting Firm
	31.1-31.3	Certifications of Chief Executive Officer, Chief Financial Officer and 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.
	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.
	99.1	Unitil Corporation Press Release Dated January 29, 2014 Announcing Earnings For the Quarter and Year Ended December 31, 2013
	101.INS	XBRL Instance Document.
	101.SCH	XBRL Taxonomy Extension Schema Document.
	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
	101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

90

EX-10.13

Exhibit 10.13

UNITIL CORPORATION TAX DEFERRED

SAVINGS AND INVESTMENT PLAN

Amended and Restated Effective as of January 1, 2009

UNITIL CORPORATION TAX DEFERRED SAVINGS AND INVESTMENT PLAN

WHEREAS, Unitil Corporation (hereinafter referred to as the “Employer”) heretofore adopted the Unitil Corporation Tax Deferred Savings and Investment Plan (hereinafter referred to as the “Plan”) for the benefit of its eligible Employees, effective as of January 1, 1985; and

WHEREAS, the Employer reserved the right to amend the Plan; and

WHEREAS, the Employer wishes to amend the Plan in order to comply with changes permitted or required by the Economic Growth and Tax Relief Reconciliation Act of 2001 (“EGTRRA”), technical corrections made by the Job Creation and Worker Assistance Act of 2002 (“JCW AA”), and other regulations and guidance published by the Internal Revenue Service that are effective after December 31, 2001, including final regulations issued under Section 415 of the Internal Revenue Code of 1986, as amended (the “Code”) and to add or modify certain administrative provisions; and

WHEREAS, it is intended that the Plan is to continue to be a qualified profit sharing plan under Section 401 (a) and 501 (a) of the Internal Revenue Code for the exclusive benefit of the Participants and their Beneficiaries; and

WHEREAS, it is intended that the cash or deferral arrangement forming part of the Plan is to continue to qualify under Section 401(k) of the Internal Revenue Code;

NOW, THEREFORE, the Plan is hereby amended by restating the Plan, effective as of January 1, 2009, except where the provisions of the Plan (or the requirements of applicable law) shall otherwise specifically provide, in its entirety as follows:

TABLE OF CONTENTS

ARTICLE ONE—DEFINITIONS
1.1	Account	1
1.2	Administrator	1
1.3	Beneficiary	1
1.4	Break in Service	1
1.5	Code	1
1.6	Compensation	1
1.7	Disability	2
1.8	Effective Date	3
1.9	Employee	3
1.10	Employer	3
1.11	Employment Date	3
1.12	Fail-Safe Contribution	3
1.13	Highly-Compensated Employee	4
1.14	Hour of Service	4
1.15	Leased Employee	6
1.16	Local 341 Granite State Employee	6
1.17	Local B341 Northern-Portland Employee	6
1.18	Local 12012-6 Northern Portsmouth Employee	6
1.19	Nonhighly-Compensated Employee	6
1.20	Normal Retirement Date	6
1.21	Participant	6
1.22	Plan	6
1.23	Plan Year	7
1.24	Trust	7
1.25	Trustee	7
1.26	Valuation Date	7
1.27	Year of Service	7
ARTICLE TWO—SERVICE DEFINITIONS AND RULES
2.1	Year of Service	8
2.2	Break in Service	8
2.3	Leave of Absence	8
2.4	Rule of Parity on Return to Employment	9
2.5	Service in Excluded Job Classifications or with Related Companies	9
ARTICLE THREE—PLAN PARTICIPATION
3.1	Participation	11
3.2	Re-employment of Former Participant	11
3.3	Tennination of Eligibility	12
3.4	Compliance with USERRA	12

ARTICLE FOUR—ELECTIVE DEFERRALS, EMPLOYER CONTRIBUTIONS, ROLLOVERS AND TRANSFERS FROM OTHER PLANS
4.1	Elective Deferrals	13
4.2	Employer Contributions	14
4.3	Rollovers and Transfers of Funds from Other Plans	14
4.4	Timing of Contributions	15
4..5	Employee After-Tax Contributions	15
ARTICLE FIVE—ACCOUNTING RULES
5.1	Investment of Accounts and Accounting Rules	16
ARTICLE SIX—VESTING AND RETIREMENT BENEFITS
6.1	Vesting	18
6.2	Forfeiture of Nonvested Balance	18
6.3	Distribution of Less than Entire Vested Account Balance	19
6.4	Normal Retirement	19
6.5	Disability	19
ARTICLE SEVEN—MANNER AND TIME OF DISTRIBUTING BENEFITS
7.1	Manner of Payment	20
7.2	Time of Commencement of Benefit Payments	20
7.3	Furnishing Information	21
7.4	Minimum Distribution Requirements	21
7.5	Amount of Death Benefit	26
7.6	Designation of Beneficiary	26
7.7	Distribution of Death Benefits	26
7.8	Eligible Rollover Distributions	27
ARTICLE EIGHT—LOANS AND IN-SERVICE WITHDRAWALS
8.1	Loans	30
8.2	Hardship Distributions	31
8.3	Withdrawals After Age 51/2	32
8.4	Withdrawals of After-Tax Contributions	32
8.5	Withdrawals of Rollover Contributions	32
ARTICLE NINE—ADMINISTRATION OF THE PLAN
9.1	Plan Administration	33
9.2	Claims Procedure	34
9.3	Trust Agreement	37

ARTICLE TEN—SPECIAL COMPLIANCE PROVISIONS
10.1	Distribution of Excess Elective Deferrals	38
10.2	Limitations on 401(k) Contributions	39
10.3	Nondiscrimination Test for Employer Matching Contributions and After-Tax Contributions	42
ARTICLE ELEVEN—LIMITATION ON ANNUAL ADDITIONS
11.1	Rules and Definitions	46
ARTICLE TWELVE—AMENDMENT AND TERMINATION
12.1	Amendment	50
12.2	Termination of the Plan	50
ARTICLE THIRTEEN—TOP-HEAVY PROVISIONS
13.1	Applicability	52
13.2	Definitions	52
13.3	Allocation of Employer Contributions and Forfeitures for a Top-Heavy Plan Year	54
13.4	Vesting	55
ARTICLE FOURTEEN—MISCELLANEOUS PROVISIONS
14.1	Plan Does Not Affect Employment	56
14.2	Successor to the Employer	56
14.3	Repayments to the Employer	56
14.4	Benefits not Assignable	56
14.5	Merger of Plans	57
14.6	Investment Experience not a Forfeiture	57
14.7	Construction	57
14.8	Governing Documents	57
14.9	Governing Law	57
14.10	Headings	57
14.11	Counterparts	57
14.12	Location of Participant or Beneficiary Unknown	58
14.13	Distribution to Minor or Legally Incapacitated	58

ARTICLE ONE—DEFINITIONS

For purposes of the Plan, unless the context or an alternative definition specified within another Article provides otherwise, the following words and phrases shall have the definitions provided:

1.1 “ACCOUNT” shall mean the individual bookkeeping accounts maintained for a Participant under the Plan which shall record (a) the Participant’s allocations of Employer contributions and forfeitures, (b) amounts of Compensation deferred to the Plan pursuant to the Participant’s election, (c) any amounts transferred to this Plan under Section 4.3 from another qualified retirement plan, or from another qualified plan in connection with a plan merger, (d) any after-tax contributions made to the Plan under Section 4.5, and (e) the allocation of Trust investment experience.

1.2 “ADMINISTRATOR” shall mean the Plan Administrator appointed from time to time m accordance with the provisions of Article Nine hereof.

1.3 “BENEFICIARY” shall mean any person, trust, organization, or estate entitled to receive payment under the terms of the Plan upon the death of a Participant.

1.4 “BREAK IN SERVICE” shall have the meaning set forth in Article Two.

1.5 “CODE” shall mean the Internal Revenue Code of 1986, as amended from time to time.

1.6 “COMPENSATION” shall mean the base compensation paid to a Participant by the Employer for the Plan Year, exclusive of any amounts deferred under any other program of deferred compensation, any additional benefits payable other than in cash and any compensation received prior to his becoming a Participant in the Plan. In addition, and solely with respect to an Employee who is a Local 341 Granite State Employee, a Local B341 Northern-Portland Employee or a Local 12012-6 Northern-Portsmouth Employee, Compensation shall mean straight time wages, exclusive of all daily or weekly overtime, bonuses, supplementary compensation payments, retirement benefits and other forms of nonrecurring compensation, but inclusive of shift differentials, Saturday/Sunday premiums and compensation paid at an alternative rate. Compensation shall, however, include any amounts deferred under a salary reduction agreement in accordance with Section 4.1 or under a Code Section 125 plan maintained by the Employer. Notwithstanding the foregoing and solely with respect to a Participant who is not a Local 341 Granite State Employee, a Local B341 Northern-Portland Employee or a Local 12012-6 Northern-Portsmouth Employee, (a) for purposes of Section 4.1, such Participant may elect to have his Compensation include overtime, bonuses, commissions and incentive payments, and (b) Compensation for purposes of Section 4.2 shall nevertheless be exclusive of overtime pay and commissions.

1

Any compensation described in this Section 1.6 does not fail to be Compensation merely because it is paid after the Participant’s severance from employment with the Employer, provided the Compensation is paid by the later of 2¹/₂ months after severance from employment with the Employer or the end of the Plan Year that includes the date of severance from employment. However, any overtime, bonuses, commissions or incentive payments shall not be taken into account.

In addition, payment for unused accrued bona fide sick, vacation or other leave shall be included as Compensation if (i) the Participant would have been able to use the leave if employment had continued, (ii) such amounts are paid by the later of 2¹/₂ months after severance from employment with the Employer or the end of the Plan Year that includes the date of severance from employment, and (iii) such amounts would have been included as Compensation if they were paid prior to the Participant’s severance from employment with the Employer.

In addition to other applicable limitations set forth in the Plan, and notwithstanding any other provision of the Plan to the contrary, the annual Compensation of each Participant taken into account under the Plan shall not exceed $245,000 for the 2009 calendar year, and shall be adjusted annually by the Secretary of the Treasury or his delegate for increases in the cost of living in accordance with Section 401(a)(l7)(B) of the Code. The cost-of-living adjustment in effect for a calendar year applies to any period, not exceeding twelve (12) months, over which Compensation is determined (determination period) beginning in such calendar year. If a determination period consists of fewer than twelve (12) months, the annual compensation limit shall be multiplied by a fraction, the numerator of which is the number of months in the determination period, and the denominator of which is twelve (12).

For purposes of determining who is a Highly-Compensated Employee, Compensation shall mean “Compensation” as defined in Section 414(s) of the Code.

For purposes of applying the limitations described in Section 11.1, and for purposes of defining compensation under Section 1.13 and Article Thirteen of the Plan, compensation paid or made available during such limitations years (or Plan Years) shall include elective amounts that are not includible in the gross income of the Employee by reason of Section 125, 132(f)(4), 402(g)(3), 402(h)(l)(B), 457(b) or 403(b) of the Code.

1.7 “DISABILITY” shall mean a “permanent and total” disability incurred by a Participant while in the employ of the Employer. A Participant shall be deemed “disabled” if (a) he is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment as determined by the Administrator and based upon appropriate medical advice and examination furnished by a licensed physician approved by the Administrator, (b) on evidence that the Participant is eligible for disability benefits under any long-term disability plan sponsored by the Employer but administrated by an independent third party, or (c) on evidence that the Participant is eligible for total and permanent disability benefits under the Social Security Act in effect at the date of Disability.

2

1.8 “EFFECTIVE DATE.” The Plan’s initial Effective Date was January 1, 1985. The Effective Date of this restated Plan, on and after which it supersedes the terms of the existing Plan document, is January 1, 2009, except where the provisions of the Plan (or the requirements of applicable law) shall otherwise specifically provide. The rights of any Participant who terminated employment with the Employer prior to the applicable date shall be established under the terms of the Plan and Trust as in effect at the time of the Participant’s termination from employment, unless the Participant subsequently returns to employment with the Employer, or unless otherwise provided under the terms of the Plan. Rights of spouses and Beneficiaries of such Participants shall also be governed by those docun1ents.

1.9 “EMPLOYEE” shall mean a common Jaw employee of the Employer or of any other employer required to be aggregated with such Employer under Section 414(b), 414(c), 414(m) or 414(o) of the Code.

The term “Employee” shall also include any Leased Employee deemed to be an Employee of any Employer described in the previous paragraph as provided in Section 414(n) or 414(o) of the Code.

1.10 “EMPLOYER” shall mean Unitil Corporation and any subsidiary or affiliate which is a member of its “related group” (as defined in Section 2.5) which has adopted the Plan (a “Participating Affiliate”), and shall include any successor(s) thereto which adopt this Plan. Any such subsidiary or affiliate of Unitil Corporation may adopt the Plan with the approval of its board of directors (or noncorporate counterpart) subject to the approval of Unitil Corporation. The provisions of this Plan shall apply equally to each Participating Affiliate and its Employees except as specifically set forth in the Plan; provided, however, notwithstanding any other provision of this Plan, the amount and timing of contributions under Article 4 to be made by any Employer which is a Participating Affiliate shall be made subject to the approval of Unitil Corporation. For purposes hereof, each Participating Affiliate shall be deemed to have appointed Unitil Corporation as its agent to act on its behalf in all matters relating to the administration, amendment, termination of the Plan and the investment of the assets of the Plan. For purposes of the Code and ERISA, the Plan as maintained by Unitil Corporation and the Participating Affiliates shall constitute a single plan rather than a separate plan of each Participating Affiliate. All assets in the Trust shall be available to pay benefits to all Participants and their Beneficiaries.

1.11 “EMPLOYMENT DATE” shall mean the first date as of which an Employee is credited with an Hour of Service, provided that, in the case of a Break in Service, the Employment Date shall be the first date thereafter as of which an Employee is credited with an Hour of Service.

1.12 “FAIL-SAFE CONTRIBUTION” shall mean a qualified nonelective contribution which is a contribution (other than matching contributions or Qualified Matching Contributions (within the meaning of Section 10 .2)) made by the Employer and allocated to Participants’ accounts that the Participants may not elect to receive in cash until distribution from the Plan; that are nonforfeitable when made; and that are distributable only in accordance with the distribution provisions under Section 401(k) of the Code and the regulations promulgated thereunder.

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1.13 “HIGHLY-COMPENSATED EMPLOYEE” shall mean, effective for years beginning after December 31, 1996, any Employee of the Employer who:

(a) was a five percent (5%) owner of the Employer (as defined in Section 416(i)(1) of the Code) at any time during the “determination year” or “look-back year”; or

(b) earned more than $105,000 of Compensation from the Employer during the “look-back year” and was in the top twenty percent (20%) of Employees by Compensation for such year. The $105,000 amount shall be adjusted at the same time and in the same manner as under Section 415(d) of the Code, except that the base period is the calendar quarter ending September 30, 1996.

An Employee who terminated employment prior to the “determination year” shall be treated as a Highly-Compensated Employee for the “determination year” if such Employee was a Highly-Compensated Employee when such Employee terminated employment, or was a Highly-Compensated Employee at any time after attaining age fifty-five (55).

For purposes of this Section, the “determination year” shall be the Plan Year for which a determination is being made as to whether an Employee is a Highly-Compensated Employee. The “look-back year” shall be the twelve (12) month period immediately preceding the “determination year”.

1.14 “HOUR OF SERVICE” shall have the meaning set forth below:

(a) An Hour of Service is each hour for which an Employee is paid, or entitled to payment, for the performance of duties for the Employer, during the applicable computation period.

(b) An Hour of Service is each hour for which an Employee is paid, or entitled to payment, by the Employer on account of a period of time during which no duties are performed (irrespective of whether the employment relationship has terminated) due to vacation, holiday, illness, incapacity (including disability), layoff, jury duty, military duty, or leave of absence. Notwithstanding the preceding sentence,

(i) No more than five hundred and one (501) Hours of Service shall be credited under this paragraph (b) to any Employee on account of any single continuous period during which the Employee performs no duties (whether or not such period occurs in a single computation period). Hours under this paragraph will be calculated and credited pursuant to Section 2530.200b -2 of the Department of Labor Regulations which is incorporated herein by reference;

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(ii) An hour for which an Employee is directly or indirectly paid, or entitled to payment, on account of a period during which no duties are performed shall not be credited to the Employee if such payment is made or due under a plan maintained solely for the purpose of complying with applicable workmen’s compensation, or unemployment compensation or disability insurance laws; and

(iii) Hours of Service shall not be credited for a payment which solely reimburses an Employee for medical or medically related expenses incurred by the Employee.

For purposes of this paragraph (b), a payment shall be deemed to be made by or due from the Employer regardless of whether such payment is made by or due from the Employer directly, or indirectly through, among others, a trust fund, or insurer, to which the Employer contributes or pays premiums and regardless of whether contributions made or due to the trust fund, insurer or other entity are for the benefit of particular Employees or are on behalf of a group of Employees in the aggregate.

(c) An Hour of Service is each hour for which back pay, irrespective of mitigation of damages, is either awarded or agreed to by the Employer. The same Hours of Service shall not be credited both under paragraph (a) or paragraph (b), as the case may be, and under this paragraph (c). Thus, for example, an Employee who receives a back pay award following a determination that he was paid at an unlawful rate for Hours of Service previously credited shall not be entitled to additional credit for the same Hours of Service. Crediting of Hours of Service for back pay awarded or agreed to with respect to periods described in paragraph (b) shall be subject to the limitations set forth in that paragraph.

(d) Hours of Service under this Section shall be determined under the terms of the Family and Medical Leave Act of 1993 and the Uniformed Services Employment and Reemployment Rights Act of 1994.

In crediting Hours of Service for Employees who are paid on an hourly basis, the “actual” method shall be utilized. For this purpose, the “actual” method shall mean the determination of Hours of Service from records of hours worked and hours for which the Employer makes payment or for which payment is due from the Employer, subject to the limitations enumerated above. In crediting Hours of Service for Employees who are not paid on an hourly basis, the “days of employment” method shall be utilized. Under this method, an Employee shall be credited with ten (1 0) Hours of Service for each day for which the Employee would be required to be credited with at least one ( 1) Hour of Service pursuant to the provisions enumerated above.

Hours of Service shall be credited for employment with other members of an affiliated service group (under Section 414(m) of the Code), a controlled group of corporations (under Section 414(b) of the Code), or a group of trades or businesses under common control (under Section 414(c) of the Code) of which the Employer is a member, and any other entity required to be aggregated under Section 414(o) of the Code.

Hours of Service shall be credited for any individual considered an Employee for purposes of this Plan under Section 414(n) or Section 414(o) of the Code.

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1.15 “LEASED EMPLOYEE” shall mean any person (other than an employee of the recipient) who, pursuant to an agreement between the recipient Employer and any other person or organization, has performed services for the recipient Employer (determined in accordance with Section 414(n)(6) of the Code) on a substantially full-time basis for a period of at least one (1) year and where such services are performed under the primary direction or control of the recipient Employer. A person shall not be considered a Leased Employee if the total number of Leased Employees does not exceed twenty percent (20%) of the Nonhighly-Compensated Employees employed by the recipient Employer, and if any such person is covered by a money purchase pension plan providing (a) a nonintegrated employer contribution rate of at least ten percent (10%) of compensation, as defined in Section 11.1(b)(2) of the Plan but including amounts contributed pursuant to a salary reduction agreement which are excludable from the employee’s gross income under Sections 125, 402(e)(3), 402(g), 402(h)(l)(B), 403(b), or 457(b) of the Code, and shall also include elective amounts that are not includible in the gross income of the Employee by reason of Section 132(f) of the Code, (b) immediate participation, and (c) full and immediate vesting.

1.16 “LOCAL 341 GRANITE STATE EMPLOYEE” is an Employee of Granite State Gas Transmission, Inc. who is covered under a collective bargaining agreement between Granite State Gas Transmission, Inc. and Utility Workers Union of America, Local No. 341.

1.17 “LOCAL 8341 NORTHERN-PORTLAND EMPLOYEE” is an Employee of Northern Utilities, Inc. who is covered under a collective bargaining agreement between Northern Utilities, Inc., and Utility Workers Union of America, Local Union No. 341.

1.18 “LOCAL 12012-6 NORTHERN-PORTSMOUTH EMPLOYEE” is an Employee of Northern Utilities, Inc. who is covered under a collective bargaining agreement between Northern Utilities, Inc. and United Steelworkers of America, AFL-CIO-CLC, Local No. 12012-6.

1.19 “NONHIGHLY-COMPENSATED EMPLOYEE” shall mean an Employee of the Employer who is not a Highly-Compensated Employee.

1.20 “NORMAL RETIREMENT DATE” shall mean the Participant’s sixty-fifth (65) birthday. The date on which the Participant attains age sixty-five (65) shall be the Participant’s Normal Retirement Age.

1.21 “PARTICIPANT” shall mean any Employee who has satisfied the eligibility requirements of Article Three and who is participating in the Plan.

1.22 “PLAN” shall mean the Unitil Corporation Tax Deferred Savings and Investment Plan, as set forth herein and as may be amended from time to time.

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1.23 “PLAN YEAR” shall mean the twelve (12)-consecutive month period beginning January 1 and ending December 31.

1.24 “TRUST” shall mean the Trust Agreement entered into between the Employer and the Trustee forming part of this Plan, together with any amendments thereto. “Trust Fund” shall mean any and all property held by the Trustee pursuant to the Trust Agreement, together with income therefrom.

1.25 “TRUSTEE” shall mean the Trustee or Trustees appointed by the Employer, and any successors thereto.

1.26 “VALUATION DATE” shall mean each day on which the New York Stock Exchange is open for business.

1.27 “YEAR OF SERVICE” or “SERVICE” and the special rules with respect to crediting Service are in Article Two of the Plan.

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ARTICLE TWO—SERVICE DEFINITIONS AND RULES

Service is the period of employment credited under the Plan. Definitions and special rules related to Service are as follows:

2.1 YEAR OF SERVICE. For purposes of determining an Employee’s eligibility to participate in the Plan, an Employee shall be credited with a Year of Service if he completes at least one thousand (1,000) Hours of Service during the twelve (12)-consecutive month period commencing on his Employment Date. If an Employee fails to be credited with at least one thousand (1,000) Hours of Service during that computation period, he shall be credited with a Year of Service if he is credited with at least one thousand (1,000) Hours of Service in any Plan Year commencing on or after his Employment Date. For purposes of determining an Employee’s nonforfeitable right to that portion of his Account attributable to Employer contributions under the schedule set forth in Section 6.1, an Employee shall be credited with a Year of Service for each Plan Year in which he is credited with at least one thousand (1,000) Hours of Service. For eligibility purposes, an Employee shall be credited with a Year of Service as of the last day of each such twelve (12) month period. For vesting purposes, an Employee shall be credited with a Year of Service upon completion of the one thousandth (1,000^th) hour in each such twelve (12)-month period.

For an employee of Northern Utilities, Inc. who becomes an Employee on the date of the acquisition of Northern Utilities, Inc. by Unitil Corporation, service with Northern Utilities, Inc. and NiSource, Inc. and any other affiliates or predecessor companies shall be included in determining his Years of Service or consecutive days of employment for both eligibility to participate in the Plan and for determining the nonforfeitable portion of his Account.

For an employee of Granite State Gas Transmission, Inc. who becomes an Employee on the date of the acquisition of Granite State Gas Transmission, Inc. by Unitil Corporation, service with Granite State Gas Transmission, Inc. and NiSource, Inc. and any other affiliates or predecessor companies shall be included in determining his Years of Service for both eligibility to participate in the Plan and for determining the nonforfeitable portion of his Account.

2.2 BREAK IN SERVICE. A Break in Service shall be a twelve (12)-month computation period (as used for measuring Years of Service for vesting purposes) in which an Employee or Participant is not credited with at least five hundred and one (501) Hours of Service.

2.3 LEAVE OF ABSENCE. A Participant on an unpaid leave of absence pursuant to the Employer’s normal personnel policies shall be credited with Hours of Service at his regularly-scheduled weekly rate while on such leave, provided the Employer acknowledges in writing that the leave is with its approval. These Hours of Service shall be credited only for purposes of determining if a Break in Service has occurred and, unless specified otherwise by the Employer in writing, shall not be credited for eligibility to participate in the Plan, vesting, or qualification to receive an allocation of Employer contributions and forfeitures. Hours of Service during a paid leave of absence shall be credited as provided in Section 1.14.

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For any individual who is absent from work for any period by reason of the individual’s pregnancy, birth of the individual’s child, placement of a child with the individual in connection with the individual’s adoption of the child, or by reason of the individual’s caring for the child for a period beginning immediately following such birth or adoption, the Plan shall treat as Hours of Service, solely for determining if a Break in Service has occurred, the following Hours of Service:

(a) the Hours of Service which otherwise normally would have been credited to such individual but for such absence; or

(b) in any case where the Administrator is unable to determine the Hours of Service, on the basis of an assumed eight (8) hours per day.

In no event shall more than five hundred and one (501) of such hours be credited by reason of such period of absence. The Hours of Service shall be credited in the computation period (used for measuring Years of Service for vesting purposes) which starts after the leave of absence begins. However, the Hours of Service shall instead be credited in the computation period in which the absence begins if it is necessary to credit the Hours of Service in that computation period to avoid the occurrence of a Break in Service.

2.4 RULE OF PARITY ON RETURN TO EMPLOYMENT. An Employee who returns to employment after a Break in Service shall retain credit for his pre-Break Years of Service, subject to the following rules:

(a) If a Participant incurs five (5) or more consecutive Breaks in Service, any Years of Service performed thereafter shall not be used to increase the nonforfeitable interest in his Account accrued prior to such five (5) or more consecutive Breaks in Service.

(b) If when a Participant incurred a Break in Service, he was not vested in any portion of his Account derived from Employer contributions, his pre-Break Years of Service shall be disregarded if his consecutive Breaks in Service equal or exceed five (5). Effective for Plan Years beginning on and after January 1, 2006, the words “derived from Employer contributions” shall be removed from the preceding sentence.

Subject to the preceding paragraphs of this Section, an Employee’s pre-Break Years of Service and post-Break Years of Service shall count in determining the vested percentage of the Employee’s Account derived from all Employer contributions (i.e., Employer contributions attributable to employment before and after the Employee’s Break in Service).

2.5 SERVICE IN EXCLUDED JOB CLASSIFICATIONS OR WITH RELATED COMPANIES

(a) Service while a Member of an Ineligible Classification of Employees. An Employee who is a member of an ineligible classification of Employees shall not be eligible to participate in the Plan while a member of such ineligible classification. However, if any

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such Employee is transferred to an eligible classification, such Employee shall be credited with any prior Years of Service completed while a member of such an ineligible classification. For this purpose, an Employee shall be considered a member of an ineligible classification of Employees for any period during which he is employed in a job classification which is excluded from participating in the Plan under Section 3.1 below.

(b) Service with Related Group Members. Subject to Section 2.1, for each Plan Year in which the Employer is a member of a “related group”, as hereinafter defined, all Service of an Employee or Leased Employee (hereinafter collectively referred to as “Employee” solely for purposes of this Section 2.5(b)) with any one or more members of such related group shall be treated as employment by the Employer for purposes of determining the Employee’s Years of Service. The transfer of employment by any such Employee to another member of the related group shall not be deemed to constitute a retirement or other termination of employment by the Employee for purposes of this Section, but the Employee shall be deemed to have continued in employment with the Employer for purposes of determining the Employee’s Years of Service. For purposes of this subsection (b), “related group” shall mean the Employer and all corporations, trades or businesses (whether or not incorporated) which constitute a controlled group of corporations with the Employer, a group of trades or businesses under common control with the Employer, or an affiliated service group which includes the Employer, within the meaning of Section 414(b), Section 414(c), or Section 414(m), respectively, of the Code or any other entity required to be aggregated under Code Section 414(o).

(c) Construction. This Section is included in the Plan to comply with the Code provisions regarding the crediting of Service, and not to extend any additional rights to Employees in ineligible classifications other than as required by the Code and regulations thereunder.

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ARTICLE THREE—PLAN PARTICIPATION

3.1 PARTICIPATION. All Employees participating in the Plan prior to the Plan’s restatement shall continue to participate, subject to the terms hereof.

Each other Employee shall become a Participant under the Plan effective as of the first day of the calendar month, or as soon as administratively possible thereafter, following the later of the Employee’s completion of one (1) Year of Service and attainment of age eighteen (18).

Notwithstanding the provisions of this Section 3.1 to the contrary, (a) a Local 341 Granite State Employee and a Local B341 Northern-Portland Employee shall become a Participant under the Plan effective as of the first day of the month, or as soon as administratively possible thereafter, following such Employee’s completion of one (1) Year of Service, and (b) a Local 12012-6 Northern-Portsmouth Employee shall become a Participant under the Plan effective as of the first day of the month, or as soon as administratively possible thereafter, following such Employee’s completion of sixty (60) consecutive days of employment as an Employee.

Notwithstanding the provisions of this Section 3.1 to the contrary, an employee of Northern Utilities, Inc., who both becomes an Employee on the date of acquisition of Northern Utilities, Inc. by Unitil Corporation and has met the age and service requirements described above, shall become a Participant under the Plan as soon as administratively feasible on or after the acquisition date.

Notwithstanding the provisions of this Section 3.1 to the contrary, an employee of Granite State Gas Transmission, Inc., who both becomes an Employee on the date of acquisition of Granite State Gas Transmission, Inc. by Unitil Corporation and has met the age and service requirements described above, shall become a Participant under the Plan as soon as administratively feasible on or after the acquisition date.

In no event, however, shall any Employee (or other individual) participate under the Plan while he is: (i) included in a unit of Employees covered by a collective bargaining agreement between the Employer and the Employee representatives under which retirement benefits were the subject of good faith bargaining, unless the terms of such bargaining agreement expressly provides for the inclusion in the Plan; (ii) employed as an independent contractor on the payroll records of the Employer (regardless of any subsequent reclassification by the Employer, any governmental agency or court); (iii) employed as a Leased Employee; or (iv) employed as a nonresident alien who receives no earned income (within the meaning of Section 911 ( d)(2) of the Code) from the Employer which constitutes income from sources within the United States (within the meaning of Section 86l(a)(3) of the Code).

3.2 RE-EMPLOYMENT OF FORMER PARTICIPANT. A vested Participant (or a nonvested Participant whose prior Service cannot be disregarded) whose participation ceased because of termination of employment with the Employer shall resume participating upon his reemployment as an eligible Employee; provided, however, that such an individual shall be entitled to commence elective deferrals (within the meaning of Section 4.1) as soon as administratively possible following his return to participation in the Plan.

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3.3 TERMINATION OF ELIGIBILITY. In the event a Participant is no longer a member of an eligible class of Employees and he becomes ineligible to participate, such Employee shall resume participating upon his return to an eligible class of Employees; provided, however, that such an individual shall be entitled to commence elective deferrals (within the meaning of Section 4.1) as soon as administratively possible following his return to participation in the Plan.

In the event an Employee who is not a member of an eligible class of Employees becomes a member of an eligible class, such Employee shall participate upon becoming a member of an eligible class of Employees, if such Employee has otherwise satisfied the eligibility requirements of Section 3.1 and would have otherwise previously become a Participant; provided, however, that such an individual shall be entitled to commence elective deferrals (within the meaning of Section 4.1) as soon as administratively possible following his becoming a Participant.

3.4 COMPLIANCE WITH USERRA. Notwithstanding any provision of this Plan to the contrary, Participants shall receive service credit and be eligible to make deferrals and receive Employer contributions with respect to periods of qualified military service (within the meaning of Section 414(u)(5) of the Code) in accordance with Section 414(u) of the Code.

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ARTICLE FOUR—ELECTIVE DEFERRALS, EMPLOYER CONTRIBUTIONS, ROLLOVERS

AND TRANSFERS FROM OTHER PLANS

4.1 ELECTIVE DEFERRALS

(a) Elections. A Participant may elect to defer a portion of his Compensation for a Plan Year on a pre-tax basis. The amount of a Participant’s Compensation contributed in accordance with the Participant’s election shall be withheld by the Employer from the Participant’s Compensation on a ratable basis throughout the Plan Year. The amount deferred on behalf of each Participant shall be contributed by the Employer to the Plan and allocated to the portion of the Participant’s Account consisting of pre-tax contributions.

Each Participant may elect to contribute in the aggregate from one percent (1%) to eighty-five percent (85%) of such Participant’s Compensation as a pre-tax contribution.

Notwithstanding the provisions of this Section 4.1 to the contrary, a Participant who is a Local 341 Granite State Employee, a Local B341 Northern-Portland Employee or a Local 12012-6 Northern-Portsmouth Employee may elect to contribute from one percent (1%) to seventy-five percent (75%) of his Compensation.

(b) Changes in Election. A Participant may prospectively elect to change or revoke the amount (or percentage) of his elective deferrals during the Plan Year by filing a written election with the Employer, or via such other method as permitted by applicable law.

(c) Limitations on Deferrals. Except to the extent permitted under Section 4.1(e), no Participant shall be permitted to make elective deferrals during any taxable year in excess of the dollar limitation contained in Section 402(g) of the Code in effect for such taxable year.

(d) Administrative Rules. All elections made under this Section 4.1, including the amount and frequency of deferrals, shall be subject to the rules of the Administrator which shall be consistently applied and which may be changed from time to time.

(e) Catch-up Contributions. All Participants who are eligible to make elective deferrals under Section 4.1(a) and who have attained age fifty (50) before the close of the taxable year shall be eligible to make catch-up contributions in accordance with, and subject to the limitations of, Section 414(v) of the Code.

Such catch-up contributions shall not be taken into account for purposes of the provisions of the Plan implementing the required limitations of Section 402(g) and 415 of the Code. The Plan shall not be treated as failing to satisfy the requirements of the Plan implementing the requirements of Section 40l(k)(3), 401(k)(11), 401(k)(l2), 402A, 410(b), or 416 of the Code, as applicable, by reason of the making of such catch-up contributions. Any intended catch-up contribution shall not be subject to an Employer match.

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4.2 EMPLOYER CONTRIBUTIONS

Employer Matching Contributions. For each payroll period, the Employer may contribute to the Plan, on behalf of each Participant, a discretionary matching contribution equal to a percentage (as determined by the Employer’s board of directors) of the elective deferrals (within the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by each such Participant; provided, however, that the amount of such Employer matching contribution for any Participant in a Plan Year shall not exceed three percent (3%) of the Participant’s Compensation for the period during which elective deferrals and/or after-tax contributions are made by the Participant.

Notwithstanding the provisions of this Section 4.2 to the contrary and solely with respect to a Participant who is a Local 341 Granite State Employee, a Local B341 Northern-Portland Employee or a Local 12012-6 Northern-Portsmouth Employee, for each payroll period the Employer shall contribute to the Plan, on behalf of each such Participant who has completed a Year of Service, a matching contribution in an amount equal to 50% of the pre-tax elective deferrals made by such Participant during the payroll period which do not exceed 5% of Compensation of such Participant. Employer matching contributions shall commence with the payroll after the first day of the month following such Participant’s completion of one Year of Service.

The Employer’s board of directors may also determine to suspend or reduce its contributions under this Section for any Plan Year or any portion thereof. Allocations under this Section shall be subject to the special rules of Section 13.3 in any Plan Year in which the Plan is a Top-Heavy Plan (as defined in Section 13.2(b)).

4.3 ROLLOVERS AND TRANSFERS OF FUNDS FROM OTHER PLANS. With the approval of the Administrator, there may be paid to the Trustee amounts which have been held under the following types of plans:

(l) a qualified plan described in Section 40l(a) or 403(a) of the Code, excluding after-tax employee contributions and excluding designated Roth contributions under Section 402A of the Code;

(2) an annuity contract described in Section 403(b) of the Code, excluding after-tax employee contributions, and excluding designated Roth contributions under Section 402A of the Code;

(3) an eligible plan under Section 457(b) of the Code which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state, excluding after-tax employee contributions; and

(4) an individual retirement account which was used solely as a conduit from a qualified plan described in Section 401 (a) of the Code, excluding after-tax employee contributions.

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Any amounts so transferred on behalf of any Employee shall be nonforfeitable and shall be maintained under a separate Plan account, to be paid in addition to amounts otherwise payable under this Plan. The amount of any such account shall be equal to the fair market value of such account as adjusted for income, expenses, gains, losses, and withdrawals attributable thereto.

Notwithstanding anything contained herein to the contrary, in no event shall the Administrator accept on behalf of any Employee a transfer of funds from a qualified plan which would subject the Plan to the provisions of Section 401(a)(11) of the Code.

An Employee who would otherwise be eligible to participate in the Plan but for the failure to satisfy the age and/or service requirement for participation as set forth under Section 3.1, shall be eligible to complete a rollover to the Plan. Such an Employee shall also be eligible to obtain a loan or withdrawal in accordance with the provisions of Article Eight prior to satisfying such age and/or service requirement.

4.4 TIMING OF CONTRIBUTIONS. Employer contributions shall be made to the Plan no later than the time prescribed by law for filing the Employer’s federal income tax return (including extensions) for its taxable year ending with or within the Plan Year. Elective deferrals under Section 4.1 shall be paid to the Plan as soon as administratively possible, but no later than the fifteenth (15^th ) business day of the month following the month in which such deferrals would have been payable to the Participant in cash, or such later date as permitted or prescribed by the Department of Labor.

4.5 EMPLOYEE AFTER-TAX CONTRIBUTIONS. A Participant shall be permitted to make after-tax contributions to the Plan in accordance with procedures established by the Administrator which shall be consistently applied and which may be changed from time to time. A Participant may prospectively elect to change or revoke the amount (or percentage) of his after-tax contributions during the Plan Year in accordance with procedures established by the Administrator.

Employee after-tax contributions shall be subject to the limitations under Section 10.3 and Section 11.1 and for any Participant shall not, when combined with his deferrals under Section 4.1, exceed the limitations of Section 4.1.

Any after-tax contributions made by a Participant shall be contributed by the Employer to the Plan and allocated to the portion of the Participant’s Account consisting of after-tax contributions. A Participant shall have a nonforfeitable interest at all times in that portion of his Account attributable to any after-tax contributions made to the Plan pursuant to this Section 4.5. Any such after-tax contributions shall be distributed at the same time as other vested benefits would be distributed under the Plan.

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ARTICLE FIVE—ACCOUNTING RULES

5.1 INVESTMENT OF ACCOUNTS AND ACCOUNTING RULES

(a) Investment Funds. The investment of Participants’ Accounts shall be made in a manner consistent with the provisions of the Trust. The Administrator, in its discretion, may allow the Trust to provide for separate funds for the directed investment of each Participant’s Account. If investments are permitted in Employer stock, a separate Employer stock fund shall be created and a portion of such stock fund shall be invested in cash and cash equivalents for liquidity purposes.

(b) Participant Direction of Investments. In the event Participants’ Accounts are subject to their investment direction, each Participant (including, for this purpose, any former Employee, Beneficiary, or “alternate payee” (within the meaning of Section 14.4 below) with an Account balance) may direct how his Account or such portion thereof which is subject to his investment direction is to be invested among the available investment funds in the percentage multiples established by the Administrator. In the event a Participant fails to make an investment election, with respect to all or any portion of his Account subject to his investment direction, the Trustee shall invest all or such portion of his Account in the investment fund to be designated by the Administrator. A Participant may change his investment election, with respect to future contributions and, if applicable, forfeitures, and/or amounts previously accumulated in the Participant’s Account in accordance with procedures established by the Administrator. Any such change in a Participant’s investment election shall be effective at such time as may be prescribed by the Administrator. However, where it deems appropriate, and subject to the requirements of applicable law, the Administrator may decline to implement, or otherwise limit the frequency by which a Participant may direct the investment of his Account. If the Plan’s recordkeeper or investments are changed, the Administrator may apply such administrative rules and procedures as are necessary to provide for the transfer of records and/or assets, including without limitation, the suspension of Participant’s investment directions, withdrawals and distributions for such period of time as is necessary, and the transfer of Participants’ Accounts to designated funds or an interest bearing account until such change has been completed.

Notwithstanding the foregoing, if, pursuant to Section 4.02 of the Trust, an investment manager (within the meaning of Section 3(38) of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”)) is appointed by a named fiduciary pursuant to Section 402(c)(3) of ERISA, a Participant may elect to have such investment manager direct the investment of his Account in accordance with the provisions of the preceding paragraph.

(c) Allocation of Investment Experience. As of each Valuation Date, the investment fund(s) of the Trust shall be valued at fair market value, and the income, loss, appreciation and depreciation (realized and unrealized), and any paid expenses of the Trust attributable to such fund shall be apportioned among Participants’ Accounts within the fund based upon the value of each Account within the fund as of the preceding Valuation Date.

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(d) Allocation of Contributions. Employer contributions shall be allocated to the Account of each eligible Participant as of the last day of the period for which the contributions are made, or as soon as administratively possible thereafter. Forfeitures which arise in a Plan Year shall be allocated as of the last day of such Plan Year, or as soon as administratively possible thereafter.

(e) Manner and Time of Debiting Distributions. For any Participant who is entitled to receive a distribution from his Account, such distribution shall be made in accordance with the provisions of Section 7.1 and Section 7.2. The amount distributed shall be based upon the fair market value of the Participant’s vested Account as of the Valuation Date preceding the distribution.

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ARTICLE SIX—VESTING AND RETIREMENT BENEFITS

6.1 VESTING. A Participant shall at all times have a nonforfeitable (vested) right to his Account derived from elective deferrals (within the meaning of Section 4.1), after-tax contributions (under Section 4.5), Employer Fail-Safe Contributions, “Qualified Matching Contributions” (within the meaning of Section 10.2 below), and rollovers or transfers from other plans, as adjusted for investment experience. Except as otherwise provided with respect to Normal Retirement, Disability, or death, a Participant shall have a nonforfeitable (vested) right to a percentage of the value of his Account derived from Employer matching contributions under Section 4.2 as follows:

Years of Service	Vested Percentage
Less than 1 year		0	%
1 year but less than 2		33	%
2 years but less than 3		67	%
3 years and thereafter		100	%

Notwithstanding the provisions of this Section 6.1 to the contrary, a Participant who is either a Local 341 Granite State Employee, a Local B 341 Northern-Portland Employee or a Local 12012-6 Northern-Portsmouth Employee shall at all times have a nonforfeitable (vested) right to his account derived from elective deferrals, after-tax contributions, Employer matching contributions under Section 4.2, Employer Fail-Safe Contributions under Section 10.2, other Employer contributions pursuant to Section 10.2 and/or 10.3, and rollovers or transfers from other plans, as adjusted for investment experience.

6.2 FORFEITURE OF NONVESTED BALANCE. The nonvested portion of a Participant’s Account, as determined in accordance with Section 6.1, shall be forfeited as of the earlier of (i) as soon as administratively practical following the date on which the Participant receives distribution of his vested Account or (ii) as soon as administratively practical after the last day of the Plan Year in which the Participant incurs five (5) consecutive Breaks in Service. However, no forfeiture shall occur solely as a result of a Participant’s withdrawal of Employee after-tax contributions. The amount forfeited shall be used to pay Plan administrative expenses, used to reduce Employer contributions under Section 4.2 or used to restore previously forfeited amounts under this Section 6.2.

If the Participant returns to the employment of the Employer prior to incurring five (5) consecutive Breaks in Service, and prior to receiving distribution of his vested Account, the nonvested portion shall remain in the Participant’s Account. However, if the nonvested portion of the Participant’s Account was allocated as a forfeiture as the result of the Participant receiving distribution of his vested Account balance (including a “deemed” distribution under Section 7.2), the nonvested portion shall be restored if:

(a) the Participant resumes employment prior to incurring five (5) consecutive Breaks in Service; and

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(b) the Participant repays to the Plan, as of the earlier of (i) the date which is five (5) years after his reemployment date or (ii) the date which is the last day of the period in which the Participant incurs five (5) consecutive Breaks in Service, an amount equal to the total distribution derived from Employer contributions under Section 4.2 and, if applicable, Section 13.3.

Upon repayment, the Employer-derived benefit required to be restored by this Section shall not be less than in the account balance of the Employee, both the amount distributed and the amount forfeited, unadjusted by any subsequent gains or losses. The amount required to be restored shall be made by a special Employer contribution or from the next succeeding Employer contribution and forfeitures, as appropriate.

Any Years of Service for which a Participant received a cash-out shall be recognized for purposes of vesting and eligibility under the Plan.

6.3 DISTRIBUTION OF LESS THAN ENTIRE VESTED ACCOUNT BALANCE. If a distribution (including a withdrawal) of any portion of a Participant’s Account is made to the Participant at a time when he has a vested percentage in such Account equal to less than one-hundred percent (100%), a separate record shall be maintained of said Account balance. The Participant’s vested interest at any time in this separate account shall be an amount equal to the formula P(AB+D)-D, where P is the vested percentage at the relevant time, AB is the Account balance at the relevant time, and D is the amount of the distribution (or withdrawal) made to the Participant.

6.4 NORMAL RETIREMENT. A Participant who is in the employment of the Employer at his Normal Retirement Age shall have a nonforfeitable interest in one hundred percent (1 00%) of his Account, if not otherwise one hundred percent (100%) vested under the vesting schedule in Section 6.1. A Participant who continues employment with the Employer after his Normal Retirement Age shall continue to participate under the Plan.

6.5 DISABILITY. If a Participant incurs a Disability, the Participant shall have a nonforfeitable interest in one hundred percent (100%) of his Account, if not otherwise one hundred percent (1 00%) vested under the vesting schedule in Section 6.1. Payment of such Participant’s Account balance shall be made at the time and in the manner specified in Article Seven, following receipt by the Administrator of the Participant’s written distribution request.

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ARTICLE SEVEN—MANNER AND TIME OF DISTRIBUTING BENEFITS

7.1 MANNER OF PAYMENT. The Participant’s vested Account shall be distributed to the Participant (or to the Participant’s Beneficiary in the event of the Participant’s death) by any of the following methods, as elected by the Participant or, when applicable, the Participant’s Beneficiary:

(a) in a single lump-sum payment; or

(b) provided the Participant’s vested Account exceeds $1,000, in partial lump-sum payments, subject to rules and procedures established by the Administrator; or

(c) provided the Participant’s vested Account exceeds $5,000, in periodic installments (at least annual) subject to the following provisions of this Article Seven; or

(d) to the extent the Participant’s vested Account is invested in employer securities (within the meaning of Section 407(d)(l) of the Employee Retirement Income Security Act of 1974), in a single payment in the form of whole shares of stock, with any fractional shares, and the cash and cash equivalent portions of the underlying unitized stock account, being distributed in cash.

In addition, a Participant who elects installments under (c) above may subsequently revise such election, even after installment payments have commenced, and elect to (1) change the period in which installment payments are paid, provided the period does not exceed the period permitted by the Plan, and such change does not violate the minimum required distribution requirements of IRS Treasury Regulation 1.401(a)(9), as set forth under Section 7.4, or (2) receive the remainder of his vested Account in the form of a single lump-sum cash payment.

7.2 TIME OF COMMENCEMENT OF BENEFIT PAYMENTS. Subject to the following provisions of this Section, unless the Participant elects otherwise, distribution of the Participant’s vested Account shall normally be made or commence no later than the sixtieth ( 60) day after the later of the close of the Plan Year in which: (a) the Participant attains age sixty-five (65) (or Normal Retirement Date, if earlier), (b) occurs the tenth (10^th) anniversary of the year in which the Participant commenced participation in the Plan, or (c) the Participant severs employment with the Employer. Distribution shall not be made to a Participant without his consent (and spouse’s consent, if required) if his vested Account exceeds $1,000 and such Account is immediately distributable (within the meaning of Section 1.41l(a)-1l(c)(4) of the IRS Regulations).

Notwithstanding the foregoing, upon the Administrator’s actual knowledge of a pending divorce or divorce proceeding, or the issuance (or possible issuance) of a domestic relations order regarding a Participant’s Account, such Account shall be frozen to prevent the Participant from taking withdrawals, loans or distributions against the portion of the Account, subject to, or potentially subject to, the domestic relations order. This freeze shall be removed promptly following the qualification of the domestic relations order in accordance with the Plan’s procedures or at such earlier time as the Administrator may reasonably determine.

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Notwithstanding the foregoing, if the Participant’s vested Account does not exceed $1,000, the Participant’s entire vested Account shall be distributed to the Participant (or, in the event of the Participant’s death, his Beneficiary) in a lump-sum payment as soon as administratively practicable following the date the Participant retires, dies or otherwise terminates from employment.

A Participant who is not vested in any portion of his Account shall be deemed to have received distribution of such portion of his Account as of the end of the Plan Year following the Plan Year in which he terminates from employment.

In no event shall distribution of the Participant’s vested Account be made or commence later than the April 1st following the end of the calendar year in which the Participant attains age seventy and one-half (70¹/₂), or, except for a Participant who is a five percent (5%) owner of the Employer (within the meaning of Section 40l(a)(9)(C) of the Code), if later, the April 1st following the calendar year in which the Participant retires from employment with the Employer (the “required beginning date”).

7.3 FURNISHING INFORMATION. Prior to the payment of any benefit under the Plan, each Participant or Beneficiary may be required to complete such administrative forms and furnish such proof as may be deemed necessary or appropriate by the Employer, Administrator, and/or Trustee.

7.4 MINIMUM DISTRIBUTION REQUIREMENTS.

(a) General Rules.

(1) Effective Date. The provisions of this Article will apply for purposes of determining required minimum distributions. Unless otherwise specified, the provisions of this Article will apply to calendar years beginning after December 31,2002.

(2) Precedence. The requirements of this Article will take precedence over any inconsistent provisions of the Plan; provided, however, that this Article shall not require the Plan to provide any form of benefit, or any option, not otherwise provided under Section 7.1.

(3) Requirements of Treasury Regulations Incorporated. All distributions required under this Article will be determined and made in accordance with the Treasury regulations under Section 401( a)( 9) of the Code and the minimum distribution incidental benefit requirement of Section 40l(a)(9)(G) of the Code.

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(b) Time and Manner of Distribution

(1) Required Beginning Date. The Participant’s entire interest will be distributed, or begin to be distributed, to the Participant no later than the Participant’s required beginning date.

(2) Death of Participant Before Distributions Begin. If the Participant dies before distributions begin, the Participant’s entire interest will be distributed, or begin to be distributed, no later than as follows:

(A) If the Participant’s surviving spouse is the Participant’s sole designated Beneficiary, distributions to the surviving spouse will begin by December 31 of the calendar year immediately following the calendar year in which the Participant died, or by December 31 of the calendar year in which the Participant would have attained age 70 ¹⁄₂ , if later.

(B) If the Participant’s surviving spouse is not the Participant’s sole designated Beneficiary, and if distribution is to be made over the life or over a period certain not exceeding the life expectancy of the designated Beneficiary (if permitted under Section 7.1 of the Plan), distribution to the designated Beneficiary will begin by December 31 of the calendar year immediately following the calendar year in which the Participant died.

(C) If there is no designated Beneficiary as of September 30 of the year following the year of the Participant’s death, or if the provisions of subsection (A) and (B) do not otherwise apply, the Participant’s entire interest will be distributed by December 31 of the calendar year containing the fifth anniversary of the Participant’s death.

(D) If the Participant’s surviving spouse is the Participant’s sole designated Beneficiary and the surviving spouse dies after the Participant but before distributions to the surviving spouse begin, this Section 7.4(b), other than Section 7.4(b)(2)(A), will apply as if the surviving spouse were the Participant.

For purposes of Sections 7.4(b) and 7.4(d), unless Section 7.4(b)(2)(D) applies, distributions are considered to begin on the Participant’s required beginning date. If Section 7.4(b )(2)(D) applies, distributions are considered to begin on the date distributions are required to begin to the surviving spouse under Section 7.4(b)(2)(A). If distributions under an annuity purchased from an insurance company irrevocably commence to the Participant before the Participant’s required beginning date (or to the Participant’s surviving spouse before the date distributions are required to begin to the surviving spouse under Section 7.4(b)(2)(A)), the date distributions are considered to begin is the date distributions actually commence.

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(3) Forms of Distribution. Unless the Participant’s interest is distributed in the form of an annuity purchased from an insurance company or in a single sum on or before the required beginning date, as of the first distribution calendar year, distributions will be made in accordance with Sections 7.4(c) and (d). If the Participant’s interest is distributed in the form of an annuity purchased from an insurance company, distributions thereunder will be made in accordance with the requirements of Section 401(a)(9) of the Code and the Treasury regulations.

(c) Required Minimum Distributions During Participant’s Lifetime.

(1) Amount of Required Minimum Distribution for Each Distribution Calendar Year. During the Participant’s lifetime, the minimum amount that will be distributed for each distribution calendar year is the lesser of:

(A) the quotient obtained by dividing the Participant’s vested Account balance by the distribution period in the Uniform Lifetime Table set forth in Section 1.401(a)(9)-9, Q&A-2, of the Treasury regulations, using the Participant’s age as of the Participant’s birthday in the distribution calendar year; or

(B) if the Participant’s sole designated Beneficiary for the distribution calendar year is the Participant’s spouse, the quotient obtained by dividing the Participant’s vested Account balance by the number in the Joint and Last Survivor Table set forth in Section 1.40l(a)(9)-9, Q&A-3, of the Treasury regulations, using the Participant’s and spouse’s attained ages as of the Participant’s and spouse’s birthdays in the distribution calendar year.

(2) Lifetime Required Minimum Distributions Continue Through Year of Participant’s Death. Required minimum distributions will be determined under tins Section 7.4(c) beginning with the first distribution calendar year and up to and including the distribution calendar year that includes the Participant’s date of death.

(d) Required Minimum Distributions After Participant’s Death.

(1) Death On or After Date Distributions Begin.

(A) Participant Survived by Designated Beneficiary. Subject to the provisions of this Article, if the Participant dies on or after the date distributions begin and there is a designated Beneficiary, the minimum amount that will be distributed for each distribution calendar year after the year of the Participant’s death is the quotient obtained by dividing the Participant’s vested Account balance by the longer of the remaining life expectancy of the Participant or the remaining life expectancy of the Participant’s designated Beneficiary, determined as follows:

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(i) The Participant’s remaining life expectancy is calculated using the age of the Participant in the year of death, reduced by one for each subsequent year.

(ii) If the Participant’s surviving spouse is the Participant’s sole designated Beneficiary, the remaining life expectancy of the surviving spouse is calculated for each distribution calendar year after the year of the Participant’s death using the surviving spouse’s age as of the spouse’s birthday in that year. For distribution calendar years after the year of the surviving spouse’s death, the remaining life expectancy of the surviving spouse is calculated using the age of the surviving spouse as of the spouse’s birthday in the calendar year of the spouse’s death, reduced by one for each subsequent calendar year.

(iii) If the Participant’s surviving spouse is not the Participant’s sole designated Beneficiary, the designated Beneficiary’s remaining life expectancy is calculated using the age of the Beneficiary in the year following the year of the Participant’s death, reduced by one for each subsequent year.

(B) No Designated Beneficiary. If the Participant dies on or after the date distributions begin and there is no designated Beneficiary as of September 30 of the year after the year of the Participant’s death, the minimum amount that will be distributed for each distribution calendar year after the year of the Participant’s death is the quotient obtained by dividing the Participant’s vested Account balance by the Participant’s remaining life expectancy calculated using the age of the Participant in the year of death, reduced by one for each subsequent year.

(2) Death Before Date Distributions Begin.

(A) Participant Survived by Designated Beneficiary. If the Participant dies before the date distributions begin and there is a designated Beneficiary, the minimum amount that will be distributed for each distribution calendar year after the year of the Participant’s death is the quotient obtained by dividing the Participant’s vested Account balance by the remaining life expectancy of the Participant’s designated Beneficiary, determined as provided in Section 7.4(d)(1).

(B) No Designated Beneficiary. If the Participant dies before the date distributions begin and there is no designated Beneficiary as of September 30 of the year following the year of the Participant’s death, distribution of the Participant’s entire interest will be completed by December 31 of the calendar year containing the fifth anniversary of the Participant’s death.

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(C) Death of Surviving Spouse Before Distributions to Surviving Spouse Are Required to Begin. If the Participant dies before the date distributions begin, the Participant’s surviving spouse is the Participant’s sole designated Beneficiary, and the surviving spouse dies before distributions are required to begin to the surviving spouse under Section 7.4(b)(2)(A), this Section 7.4(d) will apply as if the surviving spouse were the Participant.

(e) Definitions.

(1) Designated Beneficiary. The individual who is designated as the Beneficiary under Section 7.6 of the Plan and is the designated Beneficiary under Section 401(a)(9) of the Code and Section 1.401(a)(9)-4, of the Treasury regulations.

(2) Distribution Calendar Year. A calendar year for which a minimum distribution is required. For distributions beginning before the Participant’s death, the first distribution calendar year is the calendar year immediately preceding the calendar year which contains the Participant’s required beginning date. For distributions beginning after the Participant’s death, the first distribution calendar year is the calendar year in which distributions are required to begin under Section 7.4(b)(2). The required minimum distribution for the Participant’s first distribution calendar year will be made on or before the Participant’s required beginning date. The required minimum distribution for other distribution calendar years, including the required minimum distribution for the distribution calendar year in which the Participant’s required beginning date occurs, will be made on or before December 31 of that distribution calendar year.

(3) Life Expectancy. Life expectancy as computed by use of the Single Life Table in Section 1.401(a)(9)-9, Q&A-1, of the Treasury regulations.

(4) Participant’s Vested Account Balance. The vested Account balance as of the last valuation date in the calendar year immediately preceding the distribution calendar year (valuation calendar year) increased by the amount of any contributions made and allocated or forfeitures allocated to the vested Account balance as of dates in the valuation calendar year after the valuation date and decreased by distributions made in the valuation calendar year after the valuation date. The vested Account balance for the valuation calendar year includes any amounts rolled over or transferred to the Plan either in the valuation calendar year or in the distribution calendar year if distributed or transferred in the valuation calendar year.

(5) Required Beginning Date. The date specified in Section 7.2 of the Plan.

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7.5 AMOUNT OF DEATH BENEFIT

(a) Death Before Termination of Employment. In the event of the death of a Participant while in the employ of the Employer, vesting in the Participant’s Account shall be one hundred percent (100%), if not otherwise one hundred percent (100%) vested under Section 6.1, with the credit balance of the Participant’s Account being payable to his Beneficiary.

(b) Death After Termination of Employment. In the event of the death of a former Participant after termination of employment, but prior to the complete distribution of his vested Account balance under the Plan, the undistributed vested balance of the Participant’s Account shall be paid to the Participant’s Beneficiary.

7.6 DESIGNATION OF BENEFICIARY. Each Participant shall designate a Beneficiary in a manner acceptable to the Administrator to receive payment of any death benefit payable hereunder if such Beneficiary should survive the Participant. However, no Participant who is married shall be permitted to designate a Beneficiary other than his spouse unless the Participant’s spouse has signed a written consent witnessed by a notary public, which provides for the designation of an alternate Beneficiary.

Subject to the above, Beneficiary designations may include primary and contingent Beneficiaries, and may be revoked or amended at any time in similar manner or form, and the most recent designation shall govern. A designation of a Beneficiary made by a Participant shall cease to be effective upon his marriage or remarriage. In addition, a spousal Beneficiary designation shall cease to be effective upon written notification to the Administrator of the divorce of the Participant and such spouse. In the absence of an effective designation of Beneficiary, or if no designated Beneficiary is surviving as of the date of the Participant’s death, any death benefit shall be paid to the surviving spouse of the Participant, or, if no surviving spouse, to the Participant’s surviving issue, by right of representation, or, if none, to the Participant’s surviving parents, or, if none, to the Participant’s estate. Notification to Participants of the death benefits under the Plan and the method of designating a Beneficiary shall be given at the time and in the manner provided by regulations and rulings under the Code.

In the event a Beneficiary survives the Participant, but dies before receipt of all payments due that Beneficiary hereunder, any benefits remaining to be paid to the Beneficiary shall be paid to the Beneficiary’s estate.

7.7 DISTRIBUTION OF DEATH BENEFITS. Subject to the provisions of Section 7.2, the Beneficiary shall be allowed to designate the mode of receiving benefits in accordance with Section 7.1, unless the Participant had designated a method in writing and indicated that the method was not revocable by the Beneficiary.

(a) Distribution Beginning Before Death - If the Participant dies after distribution of his vested Account has commenced, any survivor’s benefit must be paid at least as rapidly as under the method of payment in effect at the time of the Participant’s death.

(b) Distribution Beginning After Death - If the Participant dies before distribution of his vested Account has commenced, distribution of the Participant’s vested Account shall be completed by December 31 of the calendar year containing the fifth anniversary of the Participant’s death, except as provided below:

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(i) if any portion of the Participant’s vested Account is payable to a designated Beneficiary, and if distribution is to be made over the life or over a period certain not greater than the life expectancy of the designated Beneficiary (if permitted under Section 7.1 above) such payments shall commence on or before December 31 of the calendar year immediately following the calendar year in which the Participant died;

(ii) if the designated Beneficiary is the Participant’s surviving spouse, the date distribution is required to begin shall not be earlier than the later of (A) December 31 of the calendar year immediately following the calendar year in which the Participant died and (B) December 31 of the calendar year in which the Participant would have attained age seventy and one-half (70 ¹⁄₂).

For purposes of this paragraph (b), if the surviving spouse dies after the Participant, but before payments to such spouse begin, the provisions of this paragraph, with the exception of paragraph (ii) herein, shall be applied as if the surviving spouse were the Participant.

Notwithstanding the foregoing, if the Participant has no designated Beneficiary (within the meaning of Section 401(a)(9) of the Code and the regulations thereunder), distribution of the Participant’s vested Account must be completed by December 31 of the calendar year containing the fifth anniversary of the Participant’s death.

7.8 ELIGIBLE ROLLOVER DISTRIBUTIONS. Notwithstanding the foregoing provisions of this Article Seven, the provisions of this Section 7.8 shall apply to distributions made under the Plan after December 31, 2001.

(a) A “distributee” (as hereinafter defined) may elect, at the time and in the manner prescribed by the Administrator, to have any portion of an “eligible rollover distribution” (as hereinafter defined) paid directly to an eligible retirement plan specified by the distributee in a direct rollover.

(b) Definitions:

(i) Eligible Rollover Distribution. An eligible rollover distribution is any distribution of all or any portion of the balance to the credit of the distributee, except that an eligible rollover distribution does not include: any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the distributee or the joint lives (or joint life expectancies) of the distributee and the distributee’s designated Beneficiary, or for a specified period of ten (1 0) years or more; any distribution to the extent such distribution is required under Section 40l(a)(9) of the Code; and any hardship distribution described in Section 8.2. A portion of a distribution shall

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not fail to be an eligible rollover distribution merely because the portion consists of after-tax employee contributions which are not includible in gross income. However, such portion may be transferred only to an individual retirement account or annuity described in Section 408(a) or (b) of the Code (or described in Section 408A of the Code for “designated Roth contributions” (within the meaning of Section 402A of the Code)), or to a qualified defined contribution plan described in Section 401(a) or 403(a) of the Code that agrees to separately account for amounts so transferred, including separately accounting for the portion of such distribution which is includible in gross income and the portion of such distribution which is not so includible and, if applicable, as required under Section 402A of the Code.

(ii) Eligible Retirement Plan. An eligible retirement plan is an individual retirement account described in Section 408(a) of the Code, an individual retirement annuity described in Section 408(b) of the Code, an annuity plan described in Section 403(a) of the Code, a qualified trust described in Section 401 (a) of the Code, an annuity contract described in Section 403(b) of the Code and an eligible plan under Section 457(b) of the Code which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state and which agrees to separately account for amounts transferred into such plan from this Plan, that accepts the distributee’s eligible rollover distribution. The definition of eligible retirement plan shall also apply in the case of a distribution to a surviving spouse, or to a spouse or former spouse who is the alternate payee under a qualified domestic relations order, as defined in Section 414(p) of the Code.

If any portion of an eligible rollover distribution is attributable to payments or distributions from a designated Roth account, an eligible retirement plan with respect to such portion shall include only another designated Roth account of the individual from whose account the payments or distributions were made, or a Roth IRA of such individual.

(iii) Distributee. A distributee includes an Employee or former Employee. In addition, the Employee’s or former Employee’s surviving spouse, and the Employee’s or former Employee’s spouse or former spouse who is an alternate payee under a qualified domestic relations order, as defined in Section 414(p) of the Code, are distributees with regard to the interest of the spouse or former spouse.

(iv) Direct Rollover. A direct rollover is a payment by the Plan to the eligible retirement plan specified by the distributee.

(c) If a distribution is one to which Sections 401(a)(11) and 417 of the Code do not apply, such distribution may commence less than thirty (30) days after the notice required under Section 1.41l(a)-11(c) of the Income Tax Regulations is given, provided that:

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(i) the Administrator clearly informs the Participant that the Participant has a right to a period of at least thirty (30) days after receiving the notice to consider the decision of whether or not to elect a distribution (and, if applicable, a particular distribution option), and

(ii) the Participant, after receiving the notice, affirmatively elects a distribution.

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ARTICLE EIGHT—LOANS AND IN-SERVICE WITHDRAWALS

8.1 LOANS

(a) Permissible Amount and Procedures. Upon the application of a Participant, the Administrator may, in accordance with a uniform and nondiscriminatory policy, direct the Trustee to grant a loan to the Participant, which loan shall be secured by the Participant’s vested Account balance. The Participant’s signature shall be required on a promissory note. The rate of interest on any such loan shall be equal to the “Prime Rate” (as reported in The Wall Street Journal on the date the loan is initiated) plus one percent (1%). Participant loans shall be treated as segregated investments, and interest repayments shall be credited only to the Participant’s Account.

(b) Limitation on Amount of Loans. A Participant’s loan shall not exceed the lesser of:

(1) $50,000, which amount shall be reduced by the highest outstanding loan balance during the preceding twelve (12)-month period; or

(2) one-half (¹/₂) of the vested value of the Participant’s Account, determined as of the Valuation Date preceding the date of the Participant’s loan.

Any loan must be repaid within five (5) years (or such longer period permitted by law), unless made for the purpose of acquiring the primary residence of the Participant, in which case such loan may be repaid over a longer period of time not to exceed fifteen ( 15) years. The repayment of any loan must be made in at least quarterly installments of principal and interest; provided, however, that this requirement shall not apply for a period, not longer than one year, or such longer period as may apply under Section 414(u) of the Code, that a Participant is on a leave of absence (“Leave”), either without pay from the Employer or at a rate of pay (after income and employment tax withholding) that is less than the amount of the installment payments required under the terms of the loan. However, the loan must be repaid by the latest date permitted under Sections 72(p)(2)(B) and 414(u) of the Code and the installments due after the Leave ends (or, unless Section 414(u) of the Code applies, if earlier, upon the expiration of the first year of the Leave) must not be less than those required under the terms of the original loan.

If a Participant defaults on any outstanding loan, the unpaid balance, and any interest due thereon, shall become due and payable in accordance with the terms of the underlying promissory note; provided, however, that such foreclosure on the promissory note and attachment of security shall not occur until a distributable event occurs in accordance with the provisions of Article Seven.

If a Participant terminates employment while any loan balance is outstanding, the unpaid balance, and any interest due thereon, shall become due and payable in accordance with the terms of the underlying promissory note. If such amount is not paid to the Plan, it shall be charged against the amounts that are otherwise payable to the Participant or the Participant’s Beneficiary under the provisions of the Plan.

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In the case of a Participant who has loans outstanding from other plans of the Employer (or a member of the Employer’s related group (within the meaning of Section 2.5(b)), the Administrator shall be responsible for reporting to the Trustee the existence of said loans in order to aggregate all such loans within the limits of Section 72(p) of the Code.

8.2 HARDSHIP DISTRIBUTIONS. In the case of a financial hardship resulting from a proven immediate and heavy financial need, a Participant may receive a distribution not to exceed the lesser of (i) the vested value of the Participant’s Account, without regard to earnings received on elective deferrals (within the meaning of Section 4.1) after December 31, 1988, and without regard to any Fail-Safe Contributions or Qualified Matching Contributions (within the meaning of Section 10.2 below) or any other Employer contributions made pursuant to Section 10.2 and/or 10.3, or (ii) the amount necessary to satisfy the financial hardship. The amount of any such immediate and heavy financial need may include any amounts necessary to pay Federal, state or local income taxes reasonably anticipated to result from the distribution. Such distribution shall be made in accordance with nondiscriminatory and objective standards and procedures consistently applied by the Administrator.

Hardship distributions under this Section shall be deemed to be the result of an immediate and heavy financial need if such distribution is to: (a) pay expenses for (or to obtain) medical care that would be deductible under Section 213(d) of the Code determined without regard to whether the expenses exceed seven and one-half percent (7.5%) of adjusted gross income; (b) purchase the principal residence of the Participant (excluding mortgage payments); (c) pay tuition and related educational fees for the next twelve (12) months of post-secondary education for the Participant, Participant’s spouse, or any of the Participant’s dependents (as defined in Section 152 of the Code, and without regard to Section 152(b)(1), (b)(2) and (d)(1)(B) of the Code); (d) prevent the eviction of the Participant from his principal residence or foreclosure on the Participant’s principal residence; (e) pay funeral or burial expenses for the Participant’s deceased parent, spouse, children or dependents (as defined in Section 152 of the Code, and without regard to Section 152(d)(1)(B) of the Code); or (f) repair damage to the Participant’s principal residence that would qualify for a casualty loss deduction under Section 165 of the Code (determined without regard to whether the loss exceeds ten percent (10%) of adjusted gross income). Distributions paid pursuant to this Section shall be deemed to be made as of the Valuation Date immediately preceding the hardship distribution, and the Participant’s Account shall be reduced accordingly.

A distribution shall be deemed necessary to satisfy an immediate and heavy financial need of a Participant if all of the following requirements are satisfied:

(1) The distribution is not in excess of the amount of the immediate and heavy financial need of the Participant;

(2) The Participant has obtained all distributions (including distributions of ESOP dividends under Section 404(k) of the Code), other than hardship distributions, and all nontaxable (at the time of the loan) loans currently available under all plans maintained by the Employer;

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(3) The Participant is prohibited, under the terms of the Plan or an otherwise legally enforceable agreement, from making elective deferrals (within the meaning of Section 4.1) and any after-tax contributions under Section 4.5 to the Plan and all other plans maintained by the Employer for six (6) months after receipt of the hardship distribution. For this purpose the phrase “all other plans maintained by the Employer” means all qualified and nonqualified plans of deferred compensation maintained by the Employer. The phrase also includes a stock option, stock purchase, or similar plan, or a cash or deferred arrangement that is part of a cafeteria plan within the meaning of Section 125 of the Code. However, it does not include the mandatory employee contribution portion of a defined benefit plan. It also does not include a health or welfare benefit plan, including one that is part of a cafeteria plan within the. meaning of Section 125 of the Code.

8.3 WITHDRAWALS AFTER AGE 59 ¹⁄₂. After attaining age fifty-nine and one-half (59 ¹⁄₂), a Participant may withdraw from the Plan a sum (a) not in excess of the credit balance of his vested Account and (b) not less than such minimum amount as the Administrator may establish from time to time to facilitate administration of the Plan. Any such withdrawals shall be made in accordance with nondiscriminatory and objective standards and procedures consistently applied by the Administrator.

8.4 WITHDRAWALS OF AFTER-TAX CONTRIBUTIONS. A Participant may withdraw from the Plan a sum (a) not in excess of the credit balance of the Participant’s Account attributable to any after-tax contributions made to the Plan and (b) not less than such minimum amount as the Administrator may establish from time to time to facilitate administration of the Plan. Any such withdrawals shall be made in accordance with nondiscriminatory and objective standards and procedures consistently applied by the Administrator.

For purposes of this Section 8.4, a terminated Participant with a vested Account balance under the Plan may withdraw all or any portion of such vested Account attributable to any after-tax contributions made to the Plan, subject to the provisions of the foregoing paragraph.

8.5 WITHDRAWALS OF ROLLOVER CONTRIBUTIONS. A Participant may withdraw from the Plan a sum (a) not in excess of the credit balance of the Participant’s Account attributable to any rollover contributions made to the Plan and (b) not less than such minimum amount as the Administrator may establish from time to time to facilitate administration of the Plan. Any such withdrawals shall be made in accordance with nondiscriminatory and objective standards and procedures consistently applied by the Administrator.

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ARTICLE NINE —ADMINISTRATION OF THE PLAN

9.1 PLAN ADMINISTRATION. The Employer shall be the Plan Administrator, hereinbefore and hereinafter called the Administrator, and a “named fiduciary” (for purposes of Section 402(a)(1) of the Employee Retirement Income Security Act of 1974, as amended from time to time (“ERISA”)) of the Plan, unless the Employer, by action of its board of directors, shall designate a person or committee of persons to be the Administrator. The Employer, by action of its board or directors, may also designate a person, a committee of persons, and/or other entity as a named fiduciary or named fiduciaries. The administration of the Plan, as provided herein, including a determination of the payment of benefits to Participants and their Beneficiaries, shall be the responsibility of the Administrator; provided, however, that the Administrator may delegate any of its powers, authority, duties or responsibilities to any person or committee of persons, such delegation to be in accordance with ERISA Section 405. The Administrator shall have full discretion to interpret the terms of the Plan, to determine factual questions that arise in the course of administering the Plan, to adopt rules and regulations regarding the administration of the Plan, to determine the conditions under which benefits become payable under the Plan, and to make any other determinations that the Administrator believes are necessary and advisable for the administration of the Plan. Any determination made by the Administrator shall be final and binding on all parties, and shall be given the maximum deference allowed by law.

In the event more than one party shall act as Administrator, all actions shall be made by majority decisions. In the administration of the Plan, the Administrator may (a) employ agents to carry out nonfiduciary responsibilities (other than Trustee responsibilities), (b) consult with counsel, who may be counsel to the Employer, and (c) provide for the allocation of fiduciary responsibilities (other than Trustee responsibilities) among its members. Actions dealing with fiduciary responsibilities shall be taken in writing and the performance of agents, counsel and fiduciaries to whom fiduciary responsibilities have been delegated shall be reviewed periodically.

The expenses of administering the Plan and the compensation of all employees, agents, or counsel of the Administrator, including accounting fees, recordkeeper’s fees, and the fees of any benefit consulting firm, shall be paid by the Plan, or shall be paid by the Employer if, and to the extent, the Employer so elects. To the extent required by applicable law, compensation may not be paid by the Plan to full-time Employees of the Employer.

In the event the Employer pays the expenses of administering the Plan, the Employer may seek reimbursement from the Plan for the payment of such expenses. Reimbursement shall be permitted only for Plan expenses paid by the Employer within the last twelve (12)-month period.

The Administrator shall obtain from the Trustee, not less often than annually, a report with respect to the value of the assets held in the Trust Fund, in such form as may be required by the Administrator.

The Administrator shall administer the Plan and adopt such rules and regulations as, in the opinion of the Administrator, are necessary or advisable to implement and administer the Plan and to transact its business. As a named fiduciary, the Administrator is required to discharge its duties with respect to the Plan solely in the interest of the Participants and Beneficiaries and with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent man acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims.

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9.2 CLAIMS PROCEDURE

The provisions of paragraph (a) below shall apply to all benefit claims under the Plan, except as provided in paragraph (b) below.

(a) Pursuant to procedures established by the Administrator, claims for benefits under the Plan made by a Participant or Beneficiary (the “claimant”) must be submitted in writing to the Administrator. Approved claims shall be processed and instructions issued to the Trustee or custodian authorizing payment as claimed.

If a claim is denied in whole or in part, the Administrator shall notify the claimant within ninety (90) days after receipt of the claim (or within one hundred eighty (180) days, if special circumstances require an extension of time for processing the claim, and provided written notice indicating the special circumstances and the date by which a final decision is expected to be rendered is given to the claimant within the initial ninety (90) day period).

The notice of the denial of the claim shall be written in a manner calculated to be understood by the claimant and shall set forth the following:

(i) the specific reason or reasons for the denial of the claim;

(ii) the specific references to the pertinent Plan provisions on which the denial is based;

(iii) a description of any additional material or information necessary to perfect the claim, and an explanation of why such material or information is necessary;

(iv) a statement that any appeal of the denial must be made by giving to the Administrator, within sixty (60) days after receipt of the denial of the claim, written notice of such appeal, such notice to include a full description of the pertinent issues and basis of the claim; and

(v) a statement about the claimant’s right to bring civil action under Section 502(a) under ERISA if the claim is denied on review.

Upon denial of a claim in whole or part, the claimant (or his duly authorized representative) shall have the right to submit a written request to the Administrator for a full and fair review of the denied claim, to be permitted to review documents (free of charge) pertinent to the denial, and to submit issues and comments in writing. Any appeal of the denial must be given to the Administrator within the period of time prescribed under (a)(iv) above. If the claimant (or his duly authorized representative) fails to appeal the denial to the Administrator within the prescribed time, the Administrator’s adverse determination shall be final, binding and conclusive.

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The Administrator may hold a hearing or otherwise ascertain such facts as it deems necessary and shall render a decision which shall be binding upon both parties. The Administrator shall advise the claimant of the results of the review within sixty (60) days after receipt of the written request for the review, unless special circumstances require an extension of time for processing, in which case a decision shall be rendered as soon as possible but not later than one hundred twenty (120) days after receipt of the request for review. If such extension of time is required, written notice of the extension shall be furnished to the claimant prior to the commencement of the extension. The decision of the review shall be written in a manner calculated to be understood by the claimant and shall include specific reasons for the decision, specific references to the pertinent Plan provisions on which the decision is based, the claimant’s right to receive free of charge upon written request, reasonable access to and copies of, all Plan documents, records, and other information relevant to the claim, and a statement about the claimant’s right to bring a civil action under Section 502(a) of ERISA. The decision of the Administrator shall be final, binding and conclusive.

(b) The provisions of this subsection (b) shall apply to a claim involving a determination by the Administrator of a Participant’s Disability.

Such a claim for Disability benefits must be submitted in writing to the Vice President, Administration. Approved claims shall be processed and instructions issued to the Trustee or custodian authorizing payment as claimed.

If such a claim is denied in whole or in part, the Vice President, Administration shall notify the claimant within forty-five (45) days after receipt of the claim (or within seventy-five (75) days, if special circumstances require an extension of time for processing the claim, and provided written notice indicating the special circumstances and the date by which a final decision is expected to be rendered is given to the claimant within the initial forty-five (45) day period).

If, prior to the end of the seventy five (75) day extended period, the Vice President, Administration determines that a decision cannot be rendered within the initial extension period due to special circumstances, the period for making a determination may be extended for up to an additional thirty (30) days, provided written notice indicating the special circumstances and the date by which a final decision is expected to be rendered is given to the claimant within the originally extended seventy-five (75) day period.

The notice of the denial of the claim shall be written in a manner calculated to be understood by the claimant and shall set forth the following:

(i) the specific reason or reasons for the denial of the claim;

(ii) the specific references to the pertinent Plan provisions on which the denial is based;

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(iii) a description of any additional materials or information necessary to perfect the claim, and an explanation of why such material or information is necessary;

(iv) a statement that any appeal of the denial must be made by giving to the Administrator, within one hundred eighty (180) days after receipt of the denial of the claim, written notice of such appeal, such notice to include a full description of the pertinent issues and basis of the claim;

(v) a statement about the claimant’s right to bring a civil action under Section 502(a) of ERISA if the claim is denied on review; and

(vi) to the extent that an internal rule, guideline, protocol, or other similar criterion was relied upon in the denial, the notification shall set forth the specific rule, guideline, protocol, or criterion or indicate that such was relied upon and that a copy will be provided free of charge to the claimant upon request.

Upon denial of a claim in whole or in part, the claimant (or his duly authorized representative) shall have the right to submit a written request to the 40l(k) Committee for a full and fair review of the denied claim, to be permitted to review documents (free of charge) pertinent to the denial, and to submit issues and comments in writing. Any appeal of the denial must be given to the 401 (k) Committee within the period of time prescribed under (b)(iv) above. If the claimant (or his duly authorized representative) fails to appeal the denial to the 40l(k) Committee within the prescribed time, the Vice President, Administration’s initial adverse determination shall be final, binding and conclusive.

The 401(k) Committee shall consider the full record of the claimant’s appeal without deference to the initial determination and, if the determination is based in whole or in part on a medical judgment, shall consult with a health care professional experienced in the field of medicine involved in the medical judgment. The health care professional consulted on the appeal shall be an individual who was not consulted in connection with the initial denied claim (nor a subordinate of any individual consulted in connection with the initial denied claim) and whose identity shall be disclosed to the claimant upon written request of the claimant, regardless of whether the health care professional’s advice was relied upon in making the subsequent claim determination.

The 401(k) Committee shall render a decision that shall be binding upon both parties. The 40l(k) Committee shall advise the claimant of the results of their review within forty-five (45) days after receipt of the written request for the review, unless special circumstances require an extension of time for processing, in which case a decision shall be rendered as soon as possible but not later than ninety (90) days after receipt of the request for review. If such extension of time is required, written notice of the extension shall be furnished to the claimant prior to the commencement of the extension. The decision of the review shall be written in a manner calculated to be understood by the claimant and shall set forth the following:

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(A) the specific reason or reasons for the denial of the claim;

(B) the specific references to the pertinent Plan provisions on which the denial is based;

(C) the claimant’s right to receive free of charge, upon written request, reasonable access to and copies of, all Plan documents, records, and other information relevant to the claim;

(D) a statement about the claimant’s right to bring a civil action under Section 502(a) of ERISA; and

(E) to the extent that an internal rule, guideline, protocol, or other similar criterion was relied upon in the denial, the notification shall set forth the specific rule, guideline, protocol, or criterion or indicate that such was relied upon and that a copy will be provided free of charge to the claimant upon request.

The decision of the 401(k) Committee shall be final, binding and conclusive.

9.3 TRUST AGREEMENT. The Trust Agreement entered into by and between the Employer and the Trustee, including any supplements or amendments thereto, or any successor Trust Agreement, is incorporated by reference herein.

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ARTICLE TEN—SPECIAL COMPLIANCE PROVISIONS

10.1 DISTRIBUTION OF EXCESS ELECTIVE DEFERRALS. Notwithstanding any other provision of the Plan, “Excess Elective Deferrals” (as defined below) (and income or loss allocable thereto, including all earnings, expenses and appreciation or depreciation in value, whether or not realized) shall be distributed no later than each April 15 to Participants who claim Excess Elective Deferrals for the preceding calendar year.

“Excess Elective Deferrals” shall mean the amount of Elective Deferrals (as defined below) for a calendar year that the Participant designates to the Plan pursuant to the following procedure. The Participant’s designation: shall be submitted to the Administrator in writing no later than March 1; shall specify the Participant’s Excess Elective Deferrals for the preceding calendar year; and shall be accompanied by the Participant’s written statement that if the Excess Elective Deferrals is not distributed, it will, when added to amounts deferred under other plans or arrangements described in Section 401(k), 408(k) or 403(b) of the Code, exceed the limit imposed on the Participant by Section 402(g) of the Code for the year in which the deferral occurred. Excess Elective Deferrals shall mean those Elective Deferrals that are includible in a Participant’s gross income under Section 402(g) of the Code to the extent such Participant’s Elective Deferrals for a taxable year exceed the dollar limitation under such Code section.

An Excess Elective Deferral, and the income or loss allocable thereto, may be distributed before the end of the calendar year in which the Elective Deferrals were made. A Participant who has an Excess Elective Deferral for a taxable year, taking into account only his Elective Deferrals under the Plan or any other plans of the Employer (including any member of the Employer’s related group (within the meaning of Section 2.5(b)), shall be deemed to have designated the entire amount of such Excess Elective Deferral.

Excess Elective Deferrals shall be adjusted for any income or loss up to the date of distribution. For purposes of this Section 10.1, whenever reference is made to the income or loss allocable to an Excess Elective Deferral, such income or loss shall be determined as follows. The income or loss allocable to Excess Elective Deferrals allocated to each Participant is the sum of: (i) income or loss allocable to the Participant’s deferred amounts for the Plan Year multiplied by a fraction, the numerator of which is the Excess Elective Deferrals made on behalf of the Participant for the Plan Year, and the denominator of which is the sum of the Participant’s Account balances attributable to the Participant’s Elective Deferrals on the last day of the Plan Year; and (ii) ten percent (1 0%) of the amount determined under (i) multiplied by the number of whole calendar months between the end of the Plan Year and the date of distribution, counting the month of distribution if distribution occurs after the fifteenth (15^th) of such month.

For purposes of this Article Ten, “Elective Deferrals” shall mean any Employer contributions made to the Plan at the election of the Participant, in lieu of cash compensation, and shall include contributions made pursuant to a salary deferral reduction agreement or other deferral mechanism. With respect to any taxable year, a Participant’s Elective Deferrals is the sum of all Employer contributions made on behalf of such Participant pursuant to an election to defer under any qualified cash or deferred arrangement described in Section 401(k) of the Code, any salary reduction simplified employee pension described in Section 408(k)(6) of the Code, and SIMPLE

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IRA Plan described in Section 408(p) of the Code, any eligible deferred compensation plan under Section 457 of the Code, any plan described under Section 501(c)(18) of the Code, and any Employer contributions made on behalf of a Participant for the purchase of an annuity contract under Section 403(b) of the Code pursuant to a salary reduction agreement. Elective Deferrals shall not include any deferrals properly distributed as excess annual additions.

10.2 LIMITATIONS ON 401(k) CONTRIBUTIONS

(a) Actual Deferred Percentage Test (“ADP Test”). Amounts contributed as elective deferrals under Section 4.1(a) and, if so elected by the Employer, “Qualified Matching Contributions” (as defined below) and any Fail-Safe Contributions made under this Section, are considered to be amounts deferred pursuant to Section 401(k) of the Code. For purposes of this Section, these amounts are referred to as the “deferred amounts.” For purposes of the “actual deferral percentage test” described below, (i) such deferred amounts must be made before the last day of the twelve (12)-month period immediately following the Plan Year to which the contributions relate, and (ii) the deferred amounts relate to Compensation that either (A) would have been received by the Participant in the Plan Year but for the Participant’s election to make deferrals, or (B) is attributable to services performed by the Participant in the Plan Year and, but for the Participant’s election to make deferrals, would have been received by the Participant within two and one-half (2 ¹⁄₂) months after the close of the Plan Year. The Employer shall maintain records sufficient to demonstrate satisfaction of the actual deferral percentage test and the deferred amounts used in such test.

For purposes of this Section, “Qualified Matching Contributions” shall mean matching contributions which are subject to the distribution and nonforfeitability requirements under Section 401(k) of the Code and satisfy Section 1.401(k)-2(a)(6) of the IRS Treasury regulations.

As of the last day of each Plan Year, the deferred amounts for the Participants who are Highly-Compensated Employees for the Plan Year shall satisfy either of the following tests:

(1) The actual deferral percentage for the eligible Participants who are Highly-Compensated Employees for the Plan Year shall not exceed the actual deferral percentage for eligible Participants who are Nonhighly-Compensated Employees for the Plan Year multiplied by 1.25; or

(2) The actual deferral percentage for eligible Participants who are Highly-Compensated Employees for the Plan Year shall not exceed the actual deferral percentage of eligible Participants who are Nonhighly-Compensated Employees for the Plan Year multiplied by two (2), provided that the actual deferral percentage for eligible Participants who are Highly-Compensated Employees for the Plan Year does not exceed the actual deferral percentage for eligible Participants who are Nonhighly-Compensated Employees by more than two (2) percentage points.

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Notwithstanding the foregoing, if elected by the Employer by Plan amendment, the foregoing percentage tests shall be applied based on the actual deferral percentage of the Nonhighly-Compensated Employees for the prior Plan Year; provided, however, the change in testing methods complies with the requirements set forth in the Final 401(k) and 401(m) Regulations and any other superseding guidance.

In the event the Plan changes from the current year testing method to the prior year testing method, then, for purposes of the first testing year for which the change is effective, the actual deferral percentage for Nonhighly-Compensated Employees for the prior year shall be determined by taking into account only elective deferrals (within the meaning of Section 4.1) for those Nonhighly-Compensated Employees that were taken into account for purposes of the actual deferral percentage test (and not the actual contribution percentage test) under the current year testing method for the prior year.

For purposes of the above tests, the “actual deferral percentage” shall mean for a specified group of Participants for a Plan Year, the average of the ratios (calculated separately for each Participant in such group) of (1) deferred amounts actually paid over to the Trust on behalf of such Participant for the Plan Year to (2) the Participant’s compensation (within the meaning of Section 1.6 of the Plan) or, if the Employer chooses, Participant’s compensation determined by using any other definition of compensation that satisfies the nondiscrimination requirements of Section 414(s) of the Code and the regulations thereunder. For purposes hereof, the Participant’s compensation shall be referred to as “414(s) Compensation.” An Employer may limit the period taken into account for determining 414(s) Compensation to that part of the Plan Year or calendar year in which an Employee was a Participant in the component of the Plan being tested. The period used to determine 414(s) Compensation must be applied uniformly to all Participants for the Plan Year. Deferred amounts on behalf of any Participant shall include (1) any Elective Deferrals made pursuant to the Participant’s deferral election (including Excess Elective Deferrals of Highly Compensated Employees), but excluding (a) Excess Elective Deferrals of Nonhighly-Compensated Employees that arise solely from Elective Deferrals made under the Plan or plans of this Employer and (b) Elective Deferrals that are taken into account in the actual contribution percentage test (provided the actual deferral percentage test is satisfied both with and without exclusion of these Elective Deferrals); and (2) Qualified Matching Contributions and Fail-Safe Contributions. For purposes of computing Actual Deferral Percentages, an Employee who would be a Participant but for failure to make Elective Deferrals shall be treated as a Participant on whose behalf no Elective Deferrals are made.

For purposes of this Section 10.2, the actual deferral percentage for any eligible Participant who is a Highly-Compensated Employee for the Plan Year and who is eligible to have Elective Deferrals allocated to his account under two (2) or more plans or arrangements described in Code Section 401 (k) that are maintained by the Employer or any employer who is a related group member (within the meaning of Section 2.5(b)) shall be determined as if all such deferrals were made under a single arrangement. In the event that this Plan satisfies the requirements of Code Section 401(k), 401(a)(4) or 410(b) only if aggregated with one (1) or more other plans, or if one (1) or more other plans satisfy the

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requirements of such Sections of the Code only if aggregated with this Plan, then the provisions of this Section 10.2 shall be applied by determining the actual deferral percentage of eligible Participants as if all such plans were a single plan. If the Employer elects by Plan amendment to use the prior year testing method, any adjustments to the Nonhighly-Compensated Employee actual deferral percentage for the prior year shall be made in accordance with the Final 401(k) and 401(m) Regulations. Plans may be aggregated in order to satisfy Section 401 (k) of the Code only if they have the same Plan Year and use the same average actual deferral percentage testing method.

The determination and treatment of deferred amounts and the actual deferral percentage of any Participant shall be subject to the prescribed requirements of the Secretary of the Treasury.

In the event the actual deferral percentage test is not satisfied for a Plan Year, the Employer, in its discretion, may make a Fail-Safe Contribution for eligible Participants who are Nonhighly-Compensated Employees, to be allocated among their Accounts in proportion to their compensation for the Plan Year. For purposes of this paragraph, “compensation” shall mean compensation used for the actual deferral percentage test.

(b) Distributions of Excess Contributions.

(1) In General. If the actual deferral percentage test of Section 10 .2( a) is not satisfied for a Plan Year, then the “excess contributions”, and income allocable thereto, shall be distributed, to the extent required under Treasury regulations, no later than the last day of the Plan Year following the Plan Year for which the excess contributions were made. However, if such excess contributions are distributed later than two and one-half (2 ¹⁄₂) months following the last day of the Plan Year in which such excess contributions were made, a ten percent (10%) excise tax shall be imposed upon the Employer with respect to such excess contributions.

(2) Excess Contributions. For purposes of this Section, “excess contributions” shall mean, with respect to any Plan Year, the excess of:

(A) The aggregate amount of Employer contributions actually taken into account in computing the numerator of the actual deferral percentage of Highly-Compensated Employees for such Plan Year, over

(B) The maximum amount of such contributions permitted by the ADP Test under Section 10.2( a) (determined by hypothetically reducing contributions made on behalf of Highly-Compensated Employees in order of the actual deferral percentages, beginning with the highest of such percentages).

Excess contributions shall be allocated to the Highly-Compensated Employees with the highest dollar amounts of contributions taken into account in calculating the actual deferral percentage test for the year in which the excess arose, beginning with the Highly-Compensated Employee with the highest dollar

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amount of such contributions and continuing in descending order until all the excess contributions have been allocated. For purposes of the preceding sentence, the “highest dollar amount” is determined after distribution of any excess contributions. To the extent a Highly-Compensated Employee has not reached his catch-up contribution limit (set forth in Section 4.1(e) of the Plan), excess contributions allocated to such Highly-Compensated Employee are catch-up contributions and will not be treated as excess contributions.

(3) Determination of Income. Excess contributions shall be adjusted for any income or loss up to the date of distribution. The income or loss allocable to excess contributions allocated to each Participant is the sum of: (i) income or loss allocable to the Participant’s deferred amounts for the Plan Year multiplied by a fraction, the numerator of which is the excess contributions made on behalf of the Participant for the Plan Year, and the denominator of which is the sum of the Participant’s Account balances attributable to the Participant’s deferred amounts on the last day of the Plan Year; and (ii) ten percent (10%) of the amount determined under (i) multiplied by the number of whole calendar months between the end of the Plan Year and the date of distribution, counting the month of distribution if distribution occurs after the fifteenth (15^th) of such month.

(4) Accounting for Excess Contributions. Excess contributions shall be distributed from that portion of the Participant’s Account attributable to such deferred amounts to the extent allowable under Treasury regulations.

10.3 NONDISCRIMINATION TEST FOR EMPLOYER MATCHING CONTRIBUTIONS AND AFTER-TAX CONTRIBUTIONS

(a) Average Contribution Percentage Test (“ACP Test”). To the extent required by applicable law, the provisions of this Section shall apply if Employer matching contributions are made in any Plan Year under Section 4.2 and such matching contributions are not used to satisfy the actual deferral percentage test of Section 10.2 or in the event Employee after-tax contributions are made to the Plan under Section 4.5.

Any Employee after-tax contributions that are used to satisfy the average contribution percentage test shall satisfy the requirements of Section 1.401(m)-2(a)(6) of the IRS Treasury Regulations.

As of the last day of each Plan Year, the average contribution percentage for Highly-Compensated Employees for the Plan Year shall satisfy either of the following tests:

(1) The average contribution percentage for eligible Participants who are Highly-Compensated Employees for the Plan Year shall not exceed the average contribution percentage for eligible Participants who are Nonhighly-Compensated Employees for the Plan Year multiplied by 1.25; or

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(2) The average contribution percentage for eligible Participants who are Highly-Compensated Employees for the Plan Year shall not exceed the average contribution percentage for eligible Participants who are Nonhighly-Compensated Employees for the Plan Year multiplied by two (2), provided that the average contribution percentage for eligible Participants who are Highly-Compensated Employees for the Plan Year does not exceed the average contribution percentage for eligible Participants who are Nonhighly-Compensated Employees by more than two (2) percentage points.

Notwithstanding the foregoing, if elected by the Employer by Plan amendment, the foregoing percentage tests shall be applied based on the average contribution percentage of the Nonhighly-Compensated Employees for the prior Plan Year; provided, however, the change in testing methods complies with the requirements set forth in the Final 401(k) and 401(m) Regulations and any other superseding guidance.

In the event the Plan changes from the current year testing method to the prior year testing method, then, for purposes of the first testing year for which the change is effective, the average contribution percentage for Nonhighly-Compensated Employees for the prior year shall be determined by taking into account only (a) after-tax contributions for those Nonhighly-Compensated Employees for the prior year, and (b) matching contributions for those Nonhighly-Compensated Employees that were taken into account for purposes of the average contribution percentage test (and not the average actual deferral percentage test) under the current year testing method for the prior year.

For purposes of the above tests, the “average contribution percentage” shall mean the average (expressed as a percentage) of the contribution percentages of the “eligible Participants” in each group. The “contribution percentage” shall mean the ratio (expressed as a percentage) that the sum of Employer matching contributions, and, if applicable, Employee after-tax contributions, and elective deferrals under Section 4.1 (to the extent such elective deferrals are not used to satisfy the actual deferral percentage test of Section 10 .2) under the Plan on behalf of the eligible Participant for the Plan Year bears to the eligible Participant’s compensation (within the meaning of Section 1.6 of the Plan) or, if the Employer chooses, Participant’s compensation determined by using any other definition of compensation that satisfies the nondiscrimination requirements of Section 414(s) of the Code and the regulations thereunder. For purposes hereof, the Participant’s compensation shall be referred to as “414(s) Compensation.” An Employer may limit the period taken into account for determining 414(s) Compensation to that part of the Plan Year or calendar year in which an Employee was a Participant in the component of the Plan being tested. The period used to determine 414( s) Compensation must be applied uniformly to all Participants for the Plan Year. Such average contribution percentage shall be determined without regard to matching contributions that are used either to correct excess contributions hereunder or because contributions to which they relate are excess deferrals under Section 10.1 or excess contributions under Section 10.2. “Eligible Participant” shall mean each Employee who is eligible to receive Employer matching contributions or make after-tax contributions.

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For purposes of this Section 10.3, the contribution percentage for any eligible Participant who is a Highly-Compensated Employee for the Plan Year and who is eligible to have Employer matching contributions, elective deferrals and/or after-tax contributions allocated to his account under two (2) or more plans described in Section 401(a) of the Code or under arrangements described in Section 401 (k) of the Code that are maintained by the Employer or any member of the Employer’s related group (within the meaning of Section 2.5(b)), shall be determined as if all such contributions were made under a single plan.

In the event that this Plan satisfies the requirements of Section 401(m), 401(a)(4) or 410(b) of the Code only if aggregated with one (1) or more other plans, or if one (1) or more other plans satisfy the requirements of such Sections of the Code only if aggregated with this Plan, then the provisions of this Section 10.3 shall be applied by determining the contribution percentages of eligible Participants as if all such plans were a single plan. If the Employer elects by Plan amendment to use the prior year testing method, any adjustments to the Nonhighly-Compensated Employee actual contribution percentage for the prior year shall be made in accordance with the Final 401(k) and 401(m) Regulations. Plans may be aggregated in order to satisfy Section 401 (m) of the Code only if they have the same Plan Year and use the same average contribution percentage testing method.

The determination and treatment of the contribution percentage of any Participant shall satisfy such other requirements as may be prescribed by the Secretary of the Treasury.

(b) Distribution of Excess Employer Matching Contributions.

(1) In General. If the nondiscrimination tests of Section 10.3(a) are not satisfied for a Plan Year, then the “excess aggregate contributions”, and any income allocable thereto, shall be forfeited, if otherwise forfeitable, no later than the last day of the Plan Year following the Plan Year for which the nondiscrimination tests are not satisfied, and shall be used to reduce Employer matching contributions under Section 4.2. To the extent that such “excess aggregate contributions” are nonforfeitable, such excess contributions shall be distributed to the Participant on whose behalf the excess contributions were made no later than the last day of the Plan Year following the Plan Year for which such “excess aggregate contributions” were made. However, if such excess aggregate contributions are distributed later than two and one-half (2¹/₂) months following the last day of the Plan Year in which such excess aggregate contributions were made, a ten percent (10%) excise tax shall be imposed upon the Employer with respect to such excess aggregate contributions. For purposes of the limitations of Section 11.1 (b)(1) of the Plan, excess aggregate contributions shall be considered annual additions.

(2) Excess Aggregate Contributions. For purposes of this Section, “excess aggregate contributions” shall mean, with respect to any Plan Year, the excess of:

(A) The aggregate amount of Employer matching contributions and, if applicable, Employee after-tax contributions, and elective deferrals under Section 4.1 (to the extent not used to satisfy the actual deferral percentage test of Section 10.2) actually taken into account in computing the numerator of the actual contribution percentage of Highly-Compensated Employees for such Plan Year, over

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(B) The maximum amount of such contributions permitted by the ACP Test under Section 10.3(a) (determined by hypothetically reducing contributions made on behalf of Highly-Compensated Employees in order of the actual contribution percentages, beginning with the highest of such percentages).

Excess contributions shall be allocated to the Highly-Compensated Employee with the largest “contribution percentage amounts” (as defined below) taken into account in calculating the average contribution percentage test for the year in which the excess arose, beginning with the Highly-Compensated Employee with the largest amount of such contribution percentage amounts and continuing in descending order until all the excess aggregate contributions have been allocated. For purposes of the preceding sentence, the “largest amount” is determined after distribution of any excess aggregate contributions.

For purposes of the preceding paragraph, “contribution percentage amounts” shall mean the sum of Employer matching contributions and, if applicable, Employee after-tax contributions, and elective deferrals (to the extent not used to satisfy the actual deferral percentage test of Section 10.2) made under the Plan on behalf of the Participant for the Plan Year.

(3) Determination of Income. Excess aggregate contributions shall be adjusted for an income or loss up to the date of distribution. The income or loss allocable to excess contributions allocated to each Participant is the sum of: (i) income or loss allocable to the Employer matching contributions and, if applicable, Employee after-tax contributions, and such elective deferrals for the Plan Year multiplied by a fraction, the numerator of which is the excess aggregate contributions on behalf of the Participant for the Plan Year, and the denominator of which is the sum of the Participant’s Account balances attributable to Employer matching contributions and, if applicable, Employee after-tax contributions, and such elective deferrals (to the extent not used to satisfy the average actual percentage test of Section 10.2) on the last day of the Plan Year; and (ii) ten percent (10%) of the amount determined under (i) multiplied by the number of whole calendar months between the end of the Plan Year and the date of distribution, counting the month of distribution if distribution occurs after the fifteenth (15^th) of such month.

Notwithstanding the foregoing, to the extent otherwise required to comply with the requirements of Section 401(a)(4) of the Code and the regulations thereunder, vested matching contributions may be forfeited.

For this purpose, to the extent permitted by applicable law, the Plan may be disaggregated under Section 1.410(b)-7(c) of the Income Tax Regulations, in which case the testing provisions of subsections (a) and (b) above, may separately apply to the disaggregated plans.

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ARTICLE ELEVEN—LIMITATION ON ANNUAL ADDITIONS

11.1 RULES AND DEFINITIONS

(a) Rules. The following rules shall limit additions to Participants’ Accounts for limitation years and Plan Years beginning on or after July 1, 2007:

(1) If the Participant does not participate, and has never participated, in another qualified plan maintained by the Employer, the amount of annual additions which may be credited to the Participant’s Account for any limitation year shall not exceed the lesser of the “maximum permissible” amount (as hereafter defined) or any other limitation contained in this Plan. If the Employer contribution that would otherwise be allocated to the Participant’s Account would cause the annual additions for the limitation year to exceed the maximum permissible amount, the amount allocated shall be reduced so that the annual additions for the limitation year shall equal the maximum permissible amount.

(2) Prior to determining the Participant’s actual compensation for the limitation year, the Employer may determine the maximum permissible amount for a Participant on the basis of a reasonable estimation of the Participant’s compensation for the limitation year, uniformly determined for all Participants similarly situated.

(3) As soon as is administratively feasible after the end of the limitation year, the maximum permissible amount for the limitation year shall be determined on the basis of the Participant’s actual compensation for the limitation year.

(4) If the limitations of Section 415 of the Code are exceeded, such excess amount shall be corrected in accordance with the requirements of applicable law, including pursuant to the Employee Plans Compliance Resolution System.

(5) If, in addition to this Plan, the Participant is covered under another defined contribution plan maintained by the Employer, or a welfare benefit fund, as defined in Code Section 419(e), maintained by the Employer, or an individual medical account, as defined in Code Section 415( 1)(2), maintained by the Employer which provides an annual addition, the annual additions which may be credited to a Participant’s account under all such plans for any such limitation year shall not exceed the maximum permissible amount. Benefits shall be reduced under any discretionary defined contribution plan before they are reduced under any defined contribution pension plan. If both plans are discretionary contribution plans, they shall first be reduced under this Plan. Any excess amount attributable to this Plan shall be disposed of in the manner described in Section 11.l(a)(4).

(b) Definitions.

(1) Annual additions: The following amounts credited to a Participant’s Account for the limitation year shall be treated as annual additions:

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(A) Employer contributions;

(B) Elective deferrals (within the meaning of Section 4.1);

(C) Employee after-tax contributions, if any;

(D) Forfeitures, if any; and

(E) Amounts allocated after March 31, 1984 to an individual medical account, as defined in Section 415(1)(2) of the Code, which is part of a pension or annuity plan maintained by the Employer. Also, amounts derived from contributions paid or accrued after December 31, 1985 in taxable years ending after such date which are attributable to post-retirement medical benefits allocated to the separate account of a Key Employee, as defined in Section 419A(d)(3), and amounts under a welfare benefit fund, as defined in Section 419(e), maintained by the Employer, shall be treated as annual additions to a defined contribution plan.

Employer and employee contributions taken into account as annual additions shall include “excess contributions” as defined in Section 401(k)(8)(B) of the Code, “excess aggregate contributions” as defined in Section 401(m)(6)(B) of the Code, and “excess deferrals” as defined in Section 402(g) of the Code, regardless of whether such amounts are distributed, recharacterized or forfeited, unless such amounts constitute excess deferrals that were distributed to the Participant no later than April 15 of the taxable year following the taxable year of the Participant in which such deferrals were made.

For this purpose, any excess amount applied under Section 11.1(a)(4) in the limitation year to reduce Employer contributions shall be considered annual additions for such limitation year.

(2) Compensation: For purposes of determining maximum permitted benefits under this Section, compensation shall include all of a Participant’s earned income, wages, salaries, and fees for professional services, and other amounts received for personal services actually rendered in the course of employment with the Employer, including, but not limited to, commissions paid to salesmen, compensation for services on the basis of a percentage of profits, commissions on insurance premiums, tips and bonuses, elective deferrals (as defined in Section 402(g)(3) of the Code) made by an Employee to the Plan and any amount contributed or deferred by an Employee on an elective basis and not includable in the gross income of the Employee under Section 125, 132(f), or 457 of the Code. Notwithstanding the foregoing, Compensation for purposes of this Section shall exclude the following:

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(A) Except as provided in the preceding paragraph of this Section 11.1 (b)(2), Employer contributions to a plan of deferred compensation which are not included in the Employee’s gross income for the taxable year in which contributed, or Employer contributions under a simplified employee pension plan (funded with individual retirement accounts or annuities) to the extent such contributions are deductible by the Employee, or any distributions from a plan of deferred compensation;

(B) Amounts realized from the exercise of a nonqualified stock option, or when restricted stock (or property) held by the Employee either becomes freely transferable or is no longer subject to a substantial risk of forfeiture;

(C) Amounts realized from the sale, exchange, or other disposition of stock acquired under a qualified stock option;

(D) Other amounts which received special tax benefits, or contributions made by the Employer (whether or not under a salary reduction agreement) toward the purchase of an annuity described in Section 403(b) of the Code (whether or not the amounts are actually excludable from the gross income of the Employee); and

(E) Amounts in excess of the applicable Code Section 401(a)(17) limit.

Compensation shall be measured on the basis of compensation paid in the limitation year.

Any compensation described in this Section 11.1(b)(2) does not fail to be Compensation merely because it is paid after the Participant’s severance from employment with the Employer, provided the Compensation is paid by the later of 2Y2 months after severance from employment with the Employer or the end of the limitation year that includes the date of severance from employment. In addition, payment for unused bona fide sick, vacation or other leave shall be included as Compensation if (i) the Participant would have been able to use the leave if employment had continued, (ii) such amounts are paid by the later of 212 months after severance from employment with the Employer or the end of the Plan Year that includes the date of severance from employment and (iii) such amounts would have been included as Compensation if they were paid prior to the Participant’s severance from employment with the Employer.

(3) Defined contribution dollar limitation: This shall mean $40,000, as adjusted under Section 415(d) of the Code.

(4) Employer: This term refers to the Employer that adopts this Plan, and all members of a controlled group of corporations (as defined in Section 414(b) of the Code, as modified by Section 415(h)), commonly-controlled trades or businesses (as defined in Section 414(c), as modified by Section 41 5(h)), or affiliated service groups (as defined in Section 414(m)) of which the Employer is a part, or any other entity required to be aggregated with the Employer under Code Section 414(o).

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(5) Limitation year: This shall mean the Plan Year, unless the Employer elects a different twelve (12) consecutive month period. The election shall be made by the adoption of a Plan amendment by the Employer. If the limitation year is amended to a different twelve (12) consecutive month period, the new limitation year must begin on a date within the limitation year in which the amendment is made.

(6) Maximum permissible amount: Except to the extent permitted under Section 4.l(e) and Section 414(v) of the Code, if applicable, this shall mean an amount equal to the lesser of the defined contribution dollar limitation or one hundred percent (100%) of the Participant’s compensation for the limitation year. If a short limitation year is created because of an amendment changing the limitation year to a different twelve (12)-consecutive month period, the maximum permissible amount shall not exceed the defined contribution dollar limitation multiplied by the following fraction:

Number of months in the short limitation year

12

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ARTICLE TWELVE—AMENDMENT AND TERMINATION

12.1 AMENDMENT. The Employer reserves the right to amend, or modify the Plan at any time, or from time to time, in whole or in part. To the extent permitted by board resolutions of the Employer, any amendment may be adopted by action of a named fiduciary appointed pursuant to Section 9.1 to which the Employer as Administrator has delegated the authority to amend the Plan. Any such amendment shall become effective under its terms upon adoption by the Employer, or named fiduciary, as the case may be. However, no amendment affecting the duties, powers or responsibilities of the Trustee may be made without the written consent of the Trustee. No amendment shall be made to the Plan which shall:

(a) make it possible (other than as provided in Section 14.3) for any part of the corpus or income of the Trust Fund (other than such part as may be required to pay taxes and administrative expenses) to be used for or diverted to purposes other than the exclusive benefit of the Participants or their Beneficiaries;

(b) decrease a Participant’s account balance or eliminate an optional form of payment (unless permitted by applicable law) with respect to benefits accrued as of the later of (i) the date such amendment is adopted, or (ii) the date the amendment becomes effective; or

(c) alter the schedule for vesting in a Participant’s Account with respect to any Participant with three (3) or more Years of Service for vesting purposes without his consent or deprive any Participant of any nonforfeitable portion of his Account.

Notwithstanding the other provisions of this Section or any other provisions of the Plan, any amendment or modification of the Plan may be made retroactively if necessary or appropriate within the remedial amendment period to conform to or to satisfy the conditions of any law, governmental regulation, or ruling, and to meet the requirements of the Employee Retirement Income Security Act of 1974, as it may be amended.

If any corrective amendment (within the meaning of Section l.40l(a)(4)-11(g) of the IRS Treasury Regulations) is made after the end of a Plan Year, such amendment shall satisfy the requirements of Section 1.401(a)(4)-11(g)(3) and (4) of the IRS Treasury Regulations.

12.2 TERMINATION OF THE PLAN. The Employer, by resolution of its board of directors, reserves the right at any time and in its sole discretion to discontinue payments under the Plan and to terminate the Plan. In the event the Plan is terminated, or upon complete discontinuance of contributions under the Plan by the Employer, the rights of each Participant to his Account on the date of such termination or discontinuance of contributions, to the extent of the fair market value under the Trust Fund, shall become fully vested and nonforfeitable. The Employer shall direct the Trustee to distribute the Trust Fund in accordance with the Plan’s distribution provisions to the Participants and their Beneficiaries, each Participant or Beneficiary receiving a portion of the Trust Fund equal to the value of his Account as of the date of distribution. These distributions may be implemented by the continuance of the Trust and the distribution of the Participants’ Account shall be made at such time and in such manner as though the Plan had not

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terminated, or by any other appropriate method, including rollover into Individual Retirement Accounts. Upon distribution of the Trust Fund, the Trustee shall be discharged from all obligations under the Trust and no Participant or Beneficiary shall have any further right or claim therein. In the event of the partial termination of the Plan, the Accounts of all affected Participants shall become fully vested and nonforfeitable.

In the event of the termination of the Plan, any amounts to be distributed to Participants or Beneficiaries who cannot be located shall be handled in accordance with the provisions of applicable law (which may include the establishment of an account for such Participant or Beneficiary).

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ARTICLE THIRTEEN—TOP-HEAVY PROVISIONS

13.1 APPLICABILITY. The provisions of this Article shall become applicable only for any Plan Year in which the Plan is a Top-Heavy Plan (as defined in Section 13.2(b)) and only if, and to the extent, required under Section 416 of the Code and the regulations issued thereunder. Notwithstanding the foregoing, this Article shall not apply in any Plan Year in which the Plan consists solely of a cash or deferred arrangement which meets the requirements of Section 40l(k)(12) of the Code and matching contributions with respect to which the requirements of Section 40l(m)(11) of the Code are met.

13.2 DEFINITIONS. For purposes of this Article, the following definitions shall apply:

(a) “Key Employee”: “Key Employee” shall mean any Employee or former Employee (including any deceased Employee) who, at any time during the Plan Year that includes the determination date, was an officer of the Employer having annual compensation greater than $130,000 (as adjusted under Section 416(i)(l) of the Code for Plan Years beginning after December 31, 2002), a five percent (5%) owner of the Employer, or a one percent (1%) owner of the Employer having annual compensation of more than $150,000. For this purpose, annual compensation shall mean compensation as defined in Section 11.1(b)(2) of the Plan. The determination of who is a Key Employee (including the terms “5% owner” and “1% owner”) shall be made in accordance with Section 4 16(i)(l) of the Code and the applicable regulations and other guidance of general applicability issued thereunder.

(b) “Top-Heavy Plan”:

(1) The Plan shall constitute a “Top-Heavy Plan” if any of the following conditions exist:

(A) The top-heavy ratio for the Plan exceeds sixty percent (60%) and the Plan is not part of any required aggregation group or permissive aggregation group of plans; or

(B) The Plan is part of a required aggregation group of plans (but is not part of a permissive aggregation group) and the top-heavy ratio for the group of plans exceeds sixty percent (60%); or

(C) The Plan is a part of a required aggregation group of plans and part of a permissive aggregation group and the top-heavy ratio for the permissive aggregation group exceeds sixty percent (60%).

(2) If the Employer maintains one (1) or more defined contribution plans (including any simplified employee pension plan funded with individual retirement accounts or annuities) and the Employer maintains or has maintained one (1) or more defined benefit plans which have covered or could cover a Participant in this Plan,

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the top-heavy ratio is a fraction, the numerator of which is the sum of account balances under the defined contribution plans for all Key Employees and the actuarial equivalents of accrued benefits under the defined benefit plans for all Key Employees, and the denominator of which is the sum of the account balances under the defined contribution plans for all Participants and the actuarial equivalents of accrued benefits under the defined benefit plans for all Participants. Both the numerator and denominator of the top-heavy ratio shall include any distribution of an account balance or an accrued benefit made in the one (1)-year period ending on the determination date and any contribution due to a defined contribution pension plan but unpaid as of the determination date. However, in the case of any distribution made for a reason other than severance from employment, death, or disability, this provision shall be applied by substituting a five (5)-year period for a one (1)-year period. In determining the accrued benefit of a non-Key Employee who is participating in a plan that is part of a required aggregation group, the method of determining such benefit shall be either (i) in accordance with the method, if any, that uniformly applies for accrual purposes under all plans maintained by the Employer or any member of the Employer’s related group (within the meaning of Section 2.5(b)), or (ii) if there is no such method, as if such benefit accrued not more rapidly than the slowest accrual rate permitted under the fractional accrual rate of Code Section 411 (b)( 1)(C).

(3) For purposes of (1) and (2) above, the value of account balances and the actuarial equivalents of accrued benefits shall be determined as of the most recent Valuation Date that falls within or ends with the twelve (12)-month period ending on the determination date. The account balances and accrued benefits of a Participant who is not a Key Employee but who was a Key Employee in a prior year shall be disregarded. The accrued benefits and account balances of Participants who have performed no service with any Employer maintaining the plan for the one (1)-year period ending on the determination date shall be disregarded. The calculations of the top-heavy ratio, and the extent to which distributions, rollovers, and transfers are taken into account shall be made under Section 416 of the Code and regulations issued thereunder. Deductible Employee contributions shall not be taken into account for purposes of computing the top-heavy ratio. When aggregating plans, the value of account balances and accrued benefits shall be calculated with reference to the determination dates that fall within the same calendar year.

(4) Definition of terms for Top-Heavy status:

(A) “Top-heavy ratio” shall mean the following:

(1) If the Employer maintains one or more defined contribution plans (including any simplified employee pension plan funded with individual retirement accounts or annuities) and the Employer has never maintained any defined benefit plans which have covered or could cover a Participant in this Plan, the top-heavy ratio is a fraction, the numerator of which is the sum of the account balances

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of all Key Employees as of the determination date, and the denominator of which is the sum of the account balances of all Participants as of the determination date. Both the numerator and the denominator shall be increased by any contributions due but unpaid to a defined contribution pension plan as of the determination date.

(B) “Permissive aggregation group” shall mean the required aggregation group of plans plus any other plan or plans of the Employer which, when considered as a group with the required aggregation group, would continue to satisfy the requirements of Sections 401(a)(4) and 410 of the Code.

(C) “Required aggregation group” shall mean (i) each qualified plan of the Employer (including any terminated plan) in which at least one Key Employee participates, and (ii) any other qualified plan of the Employer which enables a plan described in (i) to meet the requirements of Section 401(a)(4) or 410 of the Code.

(D) “Determination date” shall mean, for any Plan Year subsequent to the first Plan Year, the last day of the preceding Plan Year. For the first Plan Year of the Plan, “determination date” shall mean the last day of that Plan Year.

(E) “Valuation Date” shall mean the last day of the Plan Year.

(F) “Actuarial equivalence” shall be based on the interest and mortality rates utilized to determine actuarial equivalence when benefits are paid from any defined benefit plan. If no rates are specified in said plan, the following shall be utilized: pre- and post-retirement interest — five percent (5%); post-retirement mortality based on the Unisex Pension (1984) Table as used by the Pension Benefit Guaranty Corporation on the date of execution hereof.

13.3 ALLOCATION OF EMPLOYER CONTRIBUTIONS AND FORFEITURES FOR A TOP-HEAVY PLAN YEAR.

(a) Except as otherwise provided below, in any Plan Year in which the Plan is a Top-Heavy Plan, the Employer contributions and forfeitures allocated on behalf of any Participant who is a non-Key Employee shall not be less than the lesser of three percent (3%) of such Participant’s compensation (as defined in Section 11.1(b)(2) and as limited by Section 401(a)(17) of the Code) or the largest percentage of Employer contributions, elective deferrals (within the meaning of Section 4.1), and forfeitures as a percentage of the Key Employee’s compensation (as defined in Section 11.1(b)(2) and as limited by Section 401(a)(17) of the Code), allocated on behalf of any Key Employee for that Plan Year. This minimum allocation shall be made even though, under other Plan provisions, the Participant would not otherwise be entitled to receive an allocation or would have received a lesser allocation for the Plan Year because of insufficient Employer contributions under Section 4.2, the Participant’s failure to make elective deferrals under Section 4.1 or compensation is less than a stated amount.

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(b) The minimum allocation under this Section shall not apply to any Participant who was not employed by the Employer on the last day of the Plan Year.

(c) Elective deferrals may not be taken into account for the purpose of satisfying the minimum allocation. However, Employer matching contributions may be taken into account for the purpose of satisfying the minimum allocation.

(d) For purposes of the Plan, a non-Key Employee shall be any Employee or Beneficiary of such Employee, any former Employee, or Beneficiary of such former Employee, who is not or was not a Key Employee during the Plan Year ending on the determination date.

(e) If no defined benefit plan has ever been part of a permissive or required aggregation group of plans of the Employer, the contributions and forfeitures under this step shall be offset by any allocation of contributions and forfeitures under any other defined contribution plan of the Employer with a Plan Year ending in the same calendar year as this Plan’s Valuation Date.

(f) There shall be no duplication of the minimum benefits required under Code Section 416. Benefits shall be provided under defined contribution plans before under defined benefit plans. If a defined benefit plan (active or terminated) is part of the permissive or required aggregation group of plans, the allocation method of subparagraph (a) above shall apply, except that “3%” shall be increased to “5%.”

13.4 VESTING. The provisions contained in Section 6.1 relating to vesting shall continue to apply in any Plan Year in which the Plan is a Top-Heavy Plan, and apply to all benefits within the meaning of Section 411(a)(7) of the Code except those attributable to Employee contributions and elective deferrals under Section 4.1, including benefits accrued before the effective date of Section 416 and benefits accrued before the Plan became a Top-Heavy Plan.

Payment of a Participant’s vested Account balance under this Section shall be made in accordance with the provisions of Article Seven.

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ARTICLE FOURTEEN—MISCELLANEOUS PROVISIONS

14.1 PLAN DOES NOT AFFECT EMPLOYMENT. Neither the creation of this Plan, any amendment thereto, the creation of any fund nor the payment of benefits hereunder shall be construed as giving any legal or equitable right to any Employee or Participant against the Employer, its officers or Employees, or against the Trustee. All liabilities under this Plan shall be satisfied, if at all, only out of the Trust Fund held by the Trustee. Participation in the Plan shall not give any Participant any right to be retained in the employ of the Employer, and the Employer hereby expressly retains the right to hire and discharge any Employee at any time with or without cause, as if the Plan had not been adopted, and any such discharged Participant shall have only such rights or interests in the Trust Fund as may be specified herein.

14.2 SUCCESSOR TO THE EMPLOYER. In the event of the merger, consolidation, reorganization or sale of assets of the Employer, under circumstances in which a successor person, firm, or corporation shall carry on all or a substantial part of the business of the Employer, and such successor shall employ a substantial number of Employees of the Employer and shall elect to carry on the provisions of the Plan, such successor shall be substituted for the Employer under the terms and provisions of the Plan upon the filing in writing with the Trustee of its election to do so.

14.3 REPAYMENTS TO THE EMPLOYER. Notwithstanding any provisions of this Plan to the contrary:

(a) Any monies or other Plan assets attributable to any contribution made to this Plan by the Employer because of a mistake of fact shall be returned to the Employer within one (1) year after the date of contribution.

(b) Any monies or other Plan assets attributable to any contribution made to this Plan by the Employer shall be refunded to the Employer, to the extent such contribution is predicated on the deductibility thereof under the Code and the income tax deduction for such contribution is disallowed. Such amount shall be refunded within one (1) taxable year after the date of such disallowance or within one (1) year of the resolution of any judicial or administrative process with respect to the disallowance. All Employer contributions hereunder are expressly contributed based upon such contributions’ deductibility under the Code.

14.4 BENEFITS NOT ASSIGNABLE. Except as provided in Section 414(p) of the Code with respect to “qualified domestic relations orders,” or except as provided in Section 401(a)(13)(C) of the Code with respect to certain judgments and settlements, the rights of any Participant or his Beneficiary to any benefit or payment hereunder shall not be subject to voluntary or involuntary alienation or assignment.

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With respect to any “qualified domestic relations order” relating to the Plan, the Plan shall permit distribution to an alternate payee under such order at any time, irrespective of whether the Participant has attained his “earliest retirement age” (within the meaning of Section 414(p)(4)(B) of the Code) under the Plan. A distribution to an alternate payee prior to the Participant’s attainment of his earliest retirement age shall, however, be available only if the order specifies distribution at that time or permits an agreement between the Plan and the alternate payee to authorize an earlier distribution. Nothing in this paragraph shall, however, give a Participant a right to receive distribution at a time otherwise not permitted under the Plan nor does it permit the alternate payee to receive a form of payment not otherwise permitted under the Plan or under said Section 414(p) of the Code.

14.5 MERGER OF PLANS. In the case of any merger or consolidation of this Plan with, or transfer of the assets or liabilities of the Plan to, any other plan, the terms of such merger, consolidation or transfer shall be such that each Participant would receive (in the event of termination of this Plan or its successor immediately thereafter) a benefit which is no less than what the Participant would have received in the event of termination of this Plan immediately before such merger, consolidation or transfer.

14.6 INVESTMENT EXPERIENCE NOT A FORFEITURE. The decrease in value of any Account due to adverse investment experience shall not be considered an impermissible “forfeiture” of any vested balance.

14.7 CONSTRUCTION. Wherever appropriate, the use of the masculine gender shall be extended to include the feminine and/or neuter or vice versa; and the singular form of words shall be extended to include the plural; and the plural shall be restricted to mean the singular.

14.8 GOVERNING DOCUMENTS. A Participant’s rights shall be determined under the terms of the Plan as in effect at the Participant’s date of termination from employment, or, if later, and to the extent permitted by applicable law, as determined under the terms of the Plan.

14.9 GOVERNING LAW. The provisions of this Plan shall be construed under the laws of the state of the situs of the Trust, except to the extent such laws are preempted by Federal law.

14.10 HEADINGS. The Article headings and Section numbers are included solely for ease of reference. If there is any conflict between such headings or numbers and the text of the Plan, the text shall control.

14.11 COUNTERPARTS. This Plan may be executed in any number of counterparts, each of which shall be deemed an original; said counterparts shall constitute but one and the same instrument, which may be sufficiently evidenced by any one counterpart.

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14.12 LOCATION OF PARTICIPANT OR BENEFICIARY UNKNOWN. In the event that all or any portion of the distribution payable to a Participant or to a Participant’s Beneficiary hereunder shall, at the expiration of five (5) years after it shall become payable, remain unpaid solely by reason of the inability of the Administrator to ascertain the whereabouts of such Participant or Beneficiary, after sending a registered letter, return receipt requested, to the last known address, and after further diligent effort, the amount so distributable shall be forfeited and used to pay Plan administrative expenses and/or used to reduce future Employer contributions. In the event a Participant or Beneficiary is located subsequent to the forfeiture of his Account balance, such Account balance shall be restored.

14.13 DISTRIBUTION TO MINOR OR LEGALLY INCAPACITATED. In the event any benefit is payable to a minor or to a person deemed to be incompetent or to a person otherwise under legal disability, or who is by sole reason of advanced age, illness, or other physical or mental incapacity incapable of handling the disposition of his property, the Administrator may direct the Trustee to make payment of such benefit to the minor’s or legally incapacitated person’s court appointed guardian, person designated in a valid power of attorney, or any other person authorized under state law. The receipt of any such payment or distribution shall be a complete discharge of liability for Plan obligations.

IN WITNESS WHEREOF, each of the Employers and Participating Affiliates, by their duly authorized officers, has caused this Plan to be executed on the 18^th day of June, 2009.

UNITIL CORPORATION
By	/s/ Robert G. Schoenberger
	Authorized Officer
UNITIL SERVICE CORP.
By	Mark H. Collin
	Authorized Officer

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UNITIL ENERGY SYSTEMS, INC.
By	/s/ Robert G. Schoenberger
	Authorized Officer
FITCHBURG GAS AND ELECTRIC LIGHT COMPANY
By	/s/ Robert G. Schoenberger
	Authorized Officer
NORTHERN UTILITIES, INC.
By	/s/ Robert G. Schoenberger
	Authorized Officer
GRANITE STATE GAS TRANSMISSION, INC.
By	/s/ Robert G. Schoenberger
	Authorized Officer

59

AMENDMENT FOR THE PENSION PROTECTION ACT OF 2006 (“PPA”),

HEROES EARNINGS ASSISTANCE AND RELIEF TAX ACT OF 2008 (“HEART

ACT”) AND

THE WORKER, RETIREE AND EMPLOYER RECOVERY ACT OF 2008 (“PPA

TECHNICAL CORRECTIONS ACT”)

UNITIL CORPORATION TAX DEFERRED SAVINGS AND INVESTMENT PLAN

WHEREAS, Unitil Corporation (the “Employer”) heretofore adopted the Unitil Corporation Tax Deferred Savings and Investment Plan (the “Plan”); and

WHEREAS, the Employer reserved the right to amend the Plan; and

WHEREAS, the Employer desires to amend the Plan to comply with the Pension Protection Act of 2006 (“PPA”), the Heroes Earnings Assistance and Relief Tax Act of 2008 (“HEART Act”), the Worker, Retiree and Employer Recovery Act of 2008 (“PPA Technical Corrections Act”);

NOW, THEREFORE, the Plan is hereby amended, effective as of the date or dates set forth below, as follows, with such amendment intended to constitute good faith compliance with the above-referenced law changes and to supersede the provisions of the Plan to the extent those provisions are inconsistent with the provisions of this amendment:

1. Section 5.1 (b) of the Plan shall be amended, effective for Plan Years beginning after December 31, 2006, by adding the following paragraph(s) to the conclusion of such subsection:

“Divestment of Employer Securities: lf any portion of a Participant’s Account is invested in publicly-traded employer securities (within the meaning of Section 407(d)(l) of the Employee Retirement Income Security Act of 1974), the Participant may direct the Trustee to divest such securities and to reinvest the proceeds in other investment options available under the Plan, subject to the provisions of Code Section 401(a)(35), in accordance with rules and procedures established by the Administrator from time to time.

For purposes hereof, except as otherwise provided in Code Section 401(a)(35) or regulations promulgated thereunder, a plan holding employer securities which are not publicly-traded securities shall be treated as holding publicly-traded employer securities if any Employer corporation, or any member of a controlled group of corporations which includes such Employer corporation (as defined in Code Section 40l(a)(35)(F)(iii)) has issued a class of stock which is a publicly traded employer security.”

2. Section 7.2 of the Plan shall be amended by adding the following paragraph to the end of such Section:

“Minimum distributions under Section 401(a)(9) of the Code for 2009 may be suspended subject to the requirements of applicable law and Plan administrative practices.”

3. Section 7.8 of the Plan shall be amended by adding the following paragraphs to the conclusion of such Section:

“For any distribution notice issued in Plan Years beginning after December 31, 2006, the description of a Participant’s right, if any, to defer distribution shall also describe the consequences of failing to defer receipt of the distribution in accordance with the requirements of applicable law. In addition, any reference to the ninety (90) day maximum notice period prior to distribution in applying the notice requirements of Code Sections 402(f), 411(a)(11) and 417 will become one hundred and eighty (180) days.

For taxable years beginning after December 31, 2006, a Participant may elect to transfer any after-tax contributions by means of a direct rollover to a qualified plan or to a 403(b) plan that agrees to separately account for amounts so transferred, including accounting separately for the portion(s) of such distribution which are includable, and not includable, in gross income.

For distributions made after December 3 1, 2007, a Participant may elect to roll over directly an eligible rollover distribution to a Roth IRA described in Code Section 408A(b), subject to the requirements of applicable law.

For distributions after December 31, 2009, a non-spouse Beneficiary who is a “designated beneficiary” under Code Section 401(a)(9)(E) and the regulations promulgated thereunder may roll over his distribution, in accordance with the requirements of applicable law and in accordance with procedures established by the Administrator, to an individual retirement account (or other permissible eligible retirement plan) established by or for the Beneficiary for purposes of receiving the distribution. In order to be able to rollover the distribution, the distribution must otherwise satisfy the definition of an “eligible rollover distribution” (within the meaning of Code Section 402(f)(2)(A)).”

4. Article Eight of the Plan shall be amended by adding the following Section to such Article:

“8.6 HEART ACT PROVISIONS.

(a) Death benefits. In the case of a Participant’s death occurring on or after January 1, 2007, if a Participant dies while performing qualified military service (as defined in Code Section 414(u)), the Beneficiary(ies) (or surviving spouse, if the qualified joint and survivor annuity or qualified pre-retirement survivor annuity rules apply) of the Participant shall be entitled to any additional benefits (other than benefit accruals relating to the period of qualified military service) provided under the Plan as if the Participant had resumed employment and then terminated employment on account of death.

(b) Differential wage payments. For years beginning after December 31, 2008, (i) a Participant receiving a differential wage payment, as defined by Code Section 3401(h)(2), shall be treated as an Employee of the Employer making the payment, (ii) the differential wage payment shall be treated as Compensation, and (iii) the Plan shall not be treated as failing to meet the requirements of any provision described in Code Section 414(u)(l)(C) by reason of any contribution or benefit which is based on the differential wage payment.

(c) Severance from employment. For years beginning after December 31, 2008 and for purposes of Code Section 401(k)(2)(B)(i)(l), an individual shall be treated as having severed from employment during any period the individual is performing service in the uniformed services described in Code Section 340l(h)(2)(A).

If a Participant elects to receive a distribution by reason of such severance from employment, the Participant may not make an elective deferral or employee contribution during the six (6)-month period beginning on the date of such distribution.”

5. Section 10.1 of the Plan shall be amended by adding the following sentence to the conclusion of such subsection:

“Notwithstanding the foregoing, for Plan Years beginning after December 31, 2007, the Administrator shall not calculate and distribute income for the period after the close of the Plan Year in which the Excess Elective Deferral occurred and prior to the distribution of such Excess Elective Deferral.”

6. Section 10.2(b)(3) of the Plan shall be amended by adding the following sentence to the conclusion of such subsection:

“Notwithstanding the foregoing, for Plan Years beginning after December 31, 2007, the Administrator shall not calculate and distribute income for the period after the close of the Plan Year in which the excess contribution occurred and prior to the distribution of such excess contribution.”

7. Section 10.3(b)(3) of the Plan shall be amended by adding the following sentence to the conclusion of such subsection:

“Notwithstanding the foregoing, for Plan Years beginning after December 31, 2007, the Administrator shall not calculate and distribute income for the period after the close of the Plan Year in which the excess aggregate contribution occurred and prior to the distribution of such excess aggregate contribution.”

8. Except as hereinabove amended, the provisions of the Plan shall continue in full force and effect.

IN WITNESS WHEREOF, the Employer, by its duly authorized officer, has caused this Amendment to be executed on the 18^th day of June, 2009.

UNITIL CORPORATION
By:	/s/ Mark H. Collin

AMENDMENT TO

UNITIL CORPORATION TAX DEFERRED SAVINGS AND INVESTMENT PLAN

WHEREAS, Unitil Corporation (the “Employer”) heretofore adopted the Unitil Corporation Tax Deferred Savings and Investment Plan (the “Plan”); and

WHEREAS, the Employer reserved the right to amend the Plan; and

WHEREAS, the Employer desires to amend the Plan to comply with the final regulations under Section 415 of the Internal Revenue Code of 1986, as amended;

NOW, THEREFORE, the Plan is hereby amended, effective for limitation years and Plan Years beginning on or after July 1, 2007, as follows:

1. Section 1.6 of the Plan shall be amended by adding the following to the conclusion of such Section:

Any compensation described in this Section 1.6 does not fail to be Compensation merely because it is paid after the Participant’s severance from employment with the Employer, provided the Compensation is paid by the later of 2 ¹⁄₂ months after severance from employment with the Employer or the end of the Plan Year that includes the date of severance from employment. However, any overtime, bonuses, commissions or incentive payments shall not be taken into account.

In addition, payment for unused accrued bona fide sick, vacation or other leave shall be included as Compensation if (i) the Participant would have been able to use the leave if employment had continued, (ii) such amounts are paid by the later of 2 ¹⁄₂ months after severance from employment with the Employer or the end of the Plan Year that includes the date of severance from employment, and (iii) such amounts would have been included as Compensation if they were paid prior to the Participant’s severance from employment with the Employer.

2. Section 11.1(a)(4) of the Plan shall be amended to read in its entirety as follows:

(4) If the limitations of Section 415 of the Code are exceeded, such excess amount shall be corrected in accordance with the requirements of applicable law, including pursuant to the Employee Plans Compliance Resolution System.

3. Section 11.1(b)(2) of the Plan shall be amended by adding the following subsection (E):

(E) Amounts in excess of the applicable Code Section 401(a)(17) limit.

4. Section 11.1(b)(2) of the Plan shall be further amended by adding the following paragraph to the conclusion of such Section:

Any compensation described in this Section 11.1(b)(2) does not fail to be Compensation merely because it is paid after the Participant’s severance from employment with the Employer, provided the Compensation is paid by the later of 21/2 months after severance from employment with the Employer or the end of the limitation year that includes the date of severance from employment.

5. Except as hereinabove amended, the provisions of the Plan shall continue in full force and effect.

IN WITNESS WHEREOF, the Employer, by its duly authorized officer, has caused this Amendment to be executed on the 18 day of June, 2009.

UNITIL CORPORATION
By:	/s/ Mark H. Collin

AMENDMENT TO

UNITIL CORPORATION TAX DEFERRED SAVINGS AND INVESTMENT PLAN

WHEREAS, Unitil Corporation (the “Employer’’) heretofore adopted the Unitil Corporation Tax Deferred Savings and Investment Plan (the “Plan”); and

WHEREAS, the Employer reserved the right to amend the Plan; and

WHEREAS, the Employer desires to amend the Plan to add (1) an automatic enrollment feature to the Plan, (2) a managed savings feature to the Plan, (3) a new Company Contribution feature, and (4) a new matching contribution arrangement;

NOW, THEREFORE, the Plan is hereby amended, effective as of January 1, 2010, as follows:

1. Section 1.6 of the Plan shall be amended by deleting from clause (b) of the last sentence of such section the words “nevertheless be exclusive of’’ and by inserting, in lieu of said words so deleted, the new words “include bonuses and incentive payments, but exclude”.

2. Section 4.l(a) of the Plan shall be amended by adding the following paragraphs at the conclusion of such subsection:

“Notwithstanding the foregoing, any Employee not included in a unit of Employees covered by a collective bargaining agreement between the Employer and Employee representatives (‘Non-union Participant’), who elected to opt-out of the Employer’s defined benefit plan as of January 1, 20 10, and/or upon first becoming eligible to participate in the Plan pursuant to Section 3.1 or upon becoming eligible upon being rehired on or after January 1, 2010, who fails to affirmatively make any deferral election (including an election to contribute zero percent (0%) of his Compensation to the Plan) within the time prescribed by the Administrator, shall be deemed to have elected to defer three percent (3%) of his Compensation as a pre-tax contribution (‘deemed elective deferral’ ). The Administrator shall provide to each such Employee a notice of his right to receive the amount of the deemed elective deferral in cash and his right to increase or decrease his rate of elective deferrals.

Non-union Participants who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010 and/or who are first eligible to participate in the Plan, and eligible Non-union Participants who are rehired, on or after January 1, 2010, shall be enrolled in the Plan’s “Managed Savings” feature unless they elect to opt out of such feature. Such Non-union Participants, as of January 151 of each Plan year, shall have their rate of elective deferral contributions automatically increased by one percent (1 %). Such rate of elective deferral contributions shall be further increased by an additional one percent (1%) per year as of each subsequent January 1^st Notwithstanding the above, a Participant shall not have his rate of elective deferral contributions automatically increased beyond ten percent (10%). All other Participants in the Plan may elect to participate in the ‘Managed Savings’ feature of the Plan described in this paragraph by making an election pursuant to procedures established by the Administrator. A Participant’s election to participate in the ‘Managed Savings’ feature shall remain in place until the Participant revokes such election.”

3. Section 4.2 of the Plan shall be amended by adding the following paragraph as the new third paragraph of such section:

1

“Notwithstanding the provisions of this Section 4.2 to the contrary, and solely with respect to Non-union Participants who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010 and/or are first eligible to participate in the Plan and eligible Non-union Participants who are rehired on or after January 1, 2010, as well as any Participants who were eligible for the Plan prior to January 1, 2010 who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010, in lieu of receiving Employer matching contributions pursuant to the previous provisions of this section, the Employer will contribute to the Plan on behalf of each such Participant for each payroll period a matching contribution in an amount equal to 100% of the elective deferrals (within in the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by such Participant; provided, however, that the amount of such Employer Matching Contribution for any such Participant in a Plan Year shall not exceed six percent (6%) of the Participant’s Compensation for that payroll period. Those Participants who elect to continue participating in the Employer’s defined benefit plan will not be eligible for this increased matching contribution and shall continue to receive discretionary matching contributions in accordance with the previous provisions of this section.”

4. Section 4.2A shall be added to the Plan as follows:

“4.2A COMPANY CONTRIBUTION. Effective on and after January 1, 2010, each payroll period the Employer shall make a ‘Company Contribution’ on behalf of Non-union Participants who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010 and/or are first eligible to participate in the Plan on and after January 1, 2010 and eligible Non-union Participants who are rehired on and after January 1, 2010, as well as any Participants who were eligible for the Plan prior to January 1, 2010 who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010. Such ‘Company Contributions’ shall be in the amount equal to four percent (4%) of each such Participant’s Compensation for each payroll period.”

5. Section 6.1 of the Plan shall be amended by adding the following paragraph at the conclusion of such section:

“Notwithstanding the provisions of this Section 6.1 to the contrary, and solely with respect to Non-union Participants who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010 and/or who are first eligible to participate in the Plan on and after January 1, 2010 and eligible Non-union Participants who are rehired on or after January 1, 2010, as well as any Participants who were eligible for the Plan prior to January 1, 2010 who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010, any such Participant shall at all times have a nonforfeitable (vested) right to his Account derived from Employer matching contributions made on or after January 1, 2010 under Section 4.2. In addition, any such Participant shall at all times have a nonforfeitable (vested) right to his Account derived from Company Contributions under Section 4.2A.”

6. Except as hereinabove amended, the provisions of the Plan shall continue in full force and effect.

IN WITNESS THEREOF, the Employer, by its duly authorized officer, has caused this Amendment to be executed on the 23^rd day of September, 2009.

UNITIL CORPORATION
By:	/s/ Mark H. Collin

2

AMENDMENT TO

UNITIL CORPORATION TAX DEFERRED SAVINGS AND INVESTMENT PLAN

WHEREAS, Unitil Corporation (the “Employer”) heretofore adopted the Unitil Corporation Tax Deferred Savings and Investment Plan (the “Plan”); and

WHEREAS, the Employer reserved the right to amend the Plan; and

WHEREAS, the Employer desires to amend the Plan to provide for the following with respect to Local 12012-6 Northern-Portsmouth Employees: (1) an automatic enrollment feature to the Plan, (2) a managed savings feature to the Plan, (3) a new Company Contribution feature, and (4) a new matching contribution arrangement;

NOW, THEREFORE, the Plan is hereby amended, effective as of January 1, 2011, as follows:

1. Section 4.1 (a) of the Plan shall be amended by adding the following paragraphs at the conclusion of such subsection:

“Notwithstanding the foregoing, any Local 12012-6 Northern-Portsmouth Employee, who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011, and/or upon first becoming eligible to participate in the Plan pursuant to Section 3.1 or upon becoming eligible upon being rehired on or after January 1, 2011, who fails to affirmatively make any deferral election (including an election to contribute zero percent (0%) of his Compensation to the Plan) within the time prescribed by the Administrator, shall be deemed to have elected to defer three percent (3%) of his Compensation as a pre-tax contribution (‘deemed elective deferral’). The Administrator shall provide to each such Employee a notice of his right to receive the amount of the deemed elective deferral in cash and his right to increase or decrease his rate of elective deferrals.

Participants who are Local 12012-6 Northern-Portsmouth Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011, and/or who are first eligible to participate in the Plan, or are rehired, on or after January 1, 20 11, shall be enrolled in the Plan’s ‘Managed Savings’ feature unless they elect to opt out of such feature. Such Participants, as of January 1^st of each Plan year, shall have their rate of elective deferral contributions automatically increased by one percent (1 %). Such rate of elective deferral contributions shall be further increased by an additional one percent (1%) per year as of each subsequent January 1^st. Notwithstanding the above, a Participant shall not have his rate of elective deferral contributions automatically increased beyond ten percent (10%). A Participant’s election to participate in the ‘Managed Savings’ feature shall remain in place until the Participant revokes such election.”

2. Section 4.2 of the Plan shall be amended by adding the following paragraph as the new fourth paragraph of such section:

“Notwithstanding the provisions of this Section 4.2 to the contrary, and solely with respect to Local 12012-6 Northern-Portsmouth Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011, and/or are first eligible to participate in the Plan and eligible Local 12012-6 Northern-Portsmouth Employees who are rehired on or after January 1, 2011, as well as any Participants who are Local 12012-6 Northern-Portsmouth Employees who were eligible for the Plan prior to January 1, 2011 and who elected to opt-out of the Employer’s defined

1

benefit plan as of January 1, 201 1, in lieu of receiving Employer matching contributions pursuant to the previous provisions of this section, the Employer will contribute to the Plan on behalf of each such Participant for each payroll period a matching contribution in an amount equal to 100% of the elective deferrals (within in the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by such Participant; provided, however, that the amount of such Employer Matching Contribution for any such Participant in a Plan Year shall not exceed six percent (6%) of the Participant’s Compensation for that payroll period. Those Participants who elect to continue participating in the Employer’s defined benefit plan will not be eligible for this increased matching contribution and shall continue to receive discretionary matching contributions in accordance with the previous provisions of this section.”

3. Section 4.2A shall be amended by adding the following paragraph to the end thereof:

“Effective on and after January 1, 2011, each payroll period the Employer shall make a ‘Company Contribution’ on behalf of Participants who are Local 12012-6 Northern-Portsmouth Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011, and/or are first eligible to participate in the Plan on and after January 1, 2011 and eligible Participants who are Local 12012-6 Northern-Portsmouth Employees rehired on and after January 1, 2011 as well as any Participants who are Local 12012-6 Northern-Portsmouth Employees who were eligible for the Plan prior to January 1, 2011 who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011. Such ‘Company Contributions’ shall be in the amount equal to four percent (4%) of each such Participant’s Compensation for each payroll period.”

4. Section 6.1 of the Plan shall be amended by adding the following paragraph at the conclusion of such section:

“Notwithstanding the provisions of this Section 6.1 to the contrary, and solely with respect to Local 12012-6 Northern-Portsmouth Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011, and/or are first eligible to participate in the Plan on and after January 1, 2011 and eligible Local 12012-6 Northern-Portsmouth Employees who are rehired on or after January 1, 2011, as well as any Participants who are Local 12012-6 Northern-Portsmouth Employees who were eligible for the Plan prior to January 1, 2011 and who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011, any such Participant shall at all times have a nonforfeitable (vested) right to his Account derived from Employer matching contributions made on or after January 1, 2011 under Section 4.2. In addition, any such Participant shall at all times have a nonforfeitable (vested) right to his Account derived from Company Contributions under Section 4.2A.”

5. Except as hereinabove amended, the provisions of the Plan shall continue in full force and effect.

IN WITNESS THEREOF, the Employer, by its duly authorized officer, has caused this Amendment to be executed on the 22^nd day of September, 2010.

UNITIL CORPORATION
By:	/s/ Mark H. Collin

2

AMENDMENT FOR

HEROES EARNINGS ASSISTANCE AND RELIEF TAX ACT OF 2008 (“HEART ACT”) AND

2009 SUSPENSION OF REQUIRED MINIMUM DISTRIBUTIONS

UNITIL CORPORATION TAX DEFERRED SAVINGS AND INVESTMENT PLAN

WHEREAS, Unitil Corporation (the “Employer”) heretofore adopted the Unitil Corporation Tax Deferred Savings and Investment Plan (the “Plan”); and

WHEREAS, the Employer reserved the right to amend the Plan; and

WHEREAS, the Employer desires to amend the Plan to comply with the Heroes Earnings Assistance and Relief Tax Act of 2008 (“HEART Act”), to reflect administration of 2009 required minimum distributions, and for other administrative changes; and

WHEREAS, this amendment shall replace and supersede any prior amendment to the Plan for the HEART Act;

NOW, THEREFORE, the Plan is hereby amended, effective as of the dates set forth below, as follows, with such amendment intended to constitute good faith compliance with the above-referenced law changes:

1. Effective as of the first day of the Plan Year beginning in 2010, Section 7.2 of the Plan shall be amended by replacing the second paragraph thereof with the following:

“Notwithstanding the foregoing, a Participant’s Account may be frozen to prevent the Participant from taking any withdrawals, loans and/or distributions from his Account in accordance with the Plan’s qualified domestic relations order procedures.”

2. Effective January 1, 2009, Section 7.4 of the Plan shall be amended by adding the following new subsection (f) at the end thereof:

“(f) Special Rules for Required Minimum Distributions During 2009

For purposes of this subsection, a ‘2009 RMD’ is the required minimum distribution a Participant or Beneficiary, as applicable, is required to receive for 2009 without regard to Code Section 40l(a)(9)(H).

A Participant or Beneficiary whose initial required minimum distribution is a 2009 RMD will not receive distribution of his 2009 RMD unless he elects otherwise in accordance with procedures established by the Administrator.

A Participant or Beneficiary whose 2009 RMD is not his initial required minimum distribution will receive his 2009 RMD unless he elects to suspend his 2009 RMD in accordance with procedures established by the Administrator.

A direct rollover will be offered only for distributions that would be eligible rollover distributions without regard to Code Section 40l(a)(9)(H).

1

The provisions of this subsection (f) shall be interpreted in accordance with Code Section 40l(a)(9)(H) and regulatory guidance issued thereunder.”

3. Section 8.6 of the Plan shall be amended by replacing it with the following:

“8.6 HEART ACT PROVISIONS.

(a) Death benefits. In the case of a Participant’s death occurring on or after January 1, 2007, if a Participant dies while performing qualified military service (as defined in Code Section 414(u)), the Beneficiary(ies) (or surviving spouse, if the qualified joint and survivor annuity or qualified pre-retirement survivor annuity rules apply) of the Participant shall be entitled to any additional benefits (other than benefit accruals relating to the period of qualified military service) provided under the Plan as if the Participant had resumed employment and then terminated employment on account of death. In addition, vesting service credit for the deceased Participant’s period of qualified military service shall be credited to the extent required by Code Section 401(a)(37) .

(b) Differential wage payments. For years beginning after December 3 1, 2008, (i) a Participant receiving a differential wage payment, as defined by Code Section 3401(h)(2), shall be treated as an Employee of the Employer making the payment, (ii) the differential wage payment shall be treated as Compensation, and (iii) the Plan shall not be treated as failing to meet the requirements of any provision described in Code Section 414(u)(1)(C) by reason of any contribution or benefit which is based on the differential wage payment.

(c) Severance from employment. For years beginning after December 31, 2008 and for purposes of Code Section 40l(k)(2)(B)(i)(I), an individual shall be treated as having severed from employment during any period the individual is performing service in the uniformed services described in Code Section 3401 (h)(2)(A).

If a Participant elects to receive a distribution by reason of such severance from employment, the Participant may not make an elective deferral or employee contribution during the six (6)-month period beginning on the date of such distribution.

Effective as of the dates specified above, the provisions of this Section 8.6 shall be interpreted consistent with, and governed by, the Heroes Earnings Assistance and Relief Tax Act of 2008 (‘HEART Act’) and regulatory guidance issued thereunder.”

4. Section 11.1 (b)(2) is hereby amended by adding the following to the end thereof:

“For years beginning after December 31, 2008, Compensation shall also include differential wage payments as defined by Code Section 340l(h)(2).”

5. Except as hereinabove amended, the provisions of the Plan shall continue in full force and effect.

IN WITNESS WHEREOF, the Employer, by its duly authorized officer, has caused this Amendment to be executed on the 22 day of September, 2010.

UNITIL CORPORATION
By:	/s/ Mark H. Collin

2

AMENDMENT TO

UNITIL CORPORATION TAX DEFERRED SAVINGS AND INVESTMENT PLAN

WHEREAS, Unitil Corporation (the “Employer”) heretofore adopted the Unitil Corporation Tax Deferred Savings and Investment Plan (the “Plan”); and

WHEREAS, the Employer reserved the right to amend the Plan; and

WHEREAS, the Employer desires to amend the Plan to change the eligibility requirements for Local 12012-6 Northern-Portsmouth employees;

NOW, THEREFORE, the Plan is hereby amended, effective as of January 1, 2011, as follows:

1. Section 3.1 of the Plan shall be amended by deleting the third paragraph thereof in its entirety and replacing it with the following:

“Notwithstanding the provisions of this Section 3.1 to the contrary, (a) a Local 341 Granite State Employee, a Local 341 Northern-Portland Employee, and a Local 12012-6 Northern-Portsmouth Employee hired on or after January 1, 2011 shall become a Participant under the Plan effective as of the first day of the month, or as soon as administratively possible thereafter, following such Employee’s completion of one (1) Year of Service, and (b) a Local 12012-6 Northern-Portsmouth Employee hired before January 1, 2011 shall become a Participant under the Plan effective as of the first day of the month, or as soon as administratively possible thereafter, following such Employee’s completion of sixty (60) consecutive days of employment as an Employee.”

2. Except as hereinabove amended, the provisions of the Plan shall continue in full force and effect.

IN WITNESS WHEREOF, the Employer, by its duly authorized officer, has caused this Amendment to be executed on the 23^rd day of December, 2010.

UNITIL CORPORATION
By:	/s/ Mark H. Collin

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shall be eligible to participate in the Employer’s defined benefit plan in accordance with the provisions thereof.”

3. Section 4.2A shall be amended by adding the following paragraphs to the end thereof:

‘‘Notwithstanding anything in the foregoing to the contrary, effective on and after January 1, 2011, each payroll period, the Employer shall make a ‘Company Contribution’ on behalf of Participants who had not previously been provided with the opportunity to make an election to opt-out of the Employer’s defined benefit plan, but who, within sixty days of their change in employment status from non-union to union or transfer of employment to a location of the Employer which has previously been provided the opportunity to make such an opt-out election, make such an election to opt-out of the Employer’s defined benefit plan. Such “Company Contribution” shall be in an amount equal to four percent (4%) of each such Participant’s Compensation for each payroll period.

Furthermore, notwithstanding anything in the foregoing provisions of this Section 4.2A to the contrary, effective January 1, 2011, any Employee who changes his employment status from non-union to union or transfers from a location of the Employer where he elected to opt-out of the Employer’s defined benefit plan (“DB Opt-Out”) to a status/location of the Employer that has not permitted the DB Opt-Out: (a) shall no longer be eligible to receive “Company Contributions”, and (b) shall be eligible to participate in the Employer’s defined benefit plan in accordance with the provisions thereof.”

4. Section 6.1 of the Plan shall be amended by adding the following paragraph to the end thereof:

‘‘Notwithstanding the provisions of this Section 6.1 to the contrary, and solely with respect to an Employee who changes his employment status from non-union to union or transfers from a location of the Employer where he elected to opt-out of the Employer’ s defined benefit plan to receive the increased Employer matching contribution provisions set forth in Section 4.2 and Company Contributions set forth in Section 4.2A (“DB Opt-Out”) to a status/location of the Employer that has not permitted the DB Opt-Out, any such Participant shall at all times have a nonforfeitable (vested) right to his Account derived from Employer matching contributions made on or after his date of status/location change under Section 4.2. In addition, any such Participant shall at all times have a nonforfeitable (vested) right to his Account derived from Company Contributions under Section 4.2A.”

5. Except as hereinabove amended, the provisions of the Plan shall continue in full force and effect.

IN WITNESS THEREOF, the Employer, by its duly authorized officer, has caused this Amendment to be executed on the 15^th day of December, 2011.

UNITIL CORPORATION
By:	/s/ Mark H. Collin

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AMENDMENT TO

UNITIL CORPORATION TAX DEFERRED SAVINGS AND INVESTMENT PLAN

WHEREAS, Unitil Corporation (the “Employer”) heretofore adopted the Unitil Corporation Tax Deferred Savings and Investment Plan (the “Plan”); and

WHEREAS, the Employer reserved the right to amend the Plan; and

WHEREAS, the Employer desires to amend the Plan pursuant to new collective bargaining agreements;

NOW, THEREFORE, the Plan is hereby amended, effective as of April 1, 2012 except as otherwise provided below, as follows:

1. Section 4.1 (a) of the Plan is hereby amended by replacing it in its entirety with the following:

“(a) Elections. A Participant may elect to defer a portion of his Compensation for a Plan Year on a pre-tax basis. The amount of a Participant’s Compensation contributed in accordance with the Participant’s election shall be withheld by the Employer from the Participant’s Compensation on a ratable basis throughout the Plan Year. The amount deferred on behalf of each Participant shall be contributed by the Employer to the Plan and allocated to the portion of the Participant’s Account consisting of pre-tax contributions.

Each Participant may elect to contribute in the aggregate from one percent (1%) to eighty-five percent (85%) of such Participant’s Compensation as a pre-tax contribution.

Notwithstanding the provisions of this Section 4.1 (a) to the contrary and solely with respect to Participants covered by a collective bargaining agreement, such Participants may elect to defer a portion of their Compensation for a Plan Year in accordance with Appendix A, attached hereto.

Notwithstanding the foregoing, any Employee not included in a unit of Employees covered by a collective bargaining agreement between the Employer and Employee representatives (‘Non-union Participant’), who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010, and/or upon first becoming eligible to participate in the Plan pursuant to Section 3.1 or upon becoming eligible upon being rehired on or after January 1, 2010, who fails to affirmatively make any deferral election (including an election to contribute zero percent (0%) of his Compensation to the Plan) within the time prescribed by the Administrator, shall be deemed to have elected to defer three percent (3%) of his Compensation as a pre-tax contribution (‘deemed elective deferral’). The Administrator shall provide to each such Employee a notice of his right to receive the amount of the deemed elective deferral in cash and his right to increase or decrease his rate of elective deferrals.

Non-union Participants who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010 and/or who are first eligible to participate in the Plan, and eligible Non-union Participants who are rehired, on or after January 1, 2010, shall be enrolled in

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the Plan’s “Managed Savings” feature unless they elect to opt out of such feature. Such Non-union Participants, as of January 1st of each Plan year, shall have their rate of elective deferral contributions automatically increased by one percent (1 %). Such rate of elective deferral contributions shall be further increased by an additional one percent (1%) per year as of each subsequent January 1st. Notwithstanding the above, a Participant shall not have his rate of elective deferral contributions automatically increased beyond ten percent (10%). All other Participants in the Plan may elect to participate in the ‘Managed Savings’ feature of the Plan described in this paragraph by making an election pursuant to procedures established by the Administrator. A Participant’s election to participate in the ‘Managed Savings’ feature shall remain in place until the Participant revokes such election.” ‘

2. Section 4.2 of the Plan is hereby amended by replacing it in its entirety with the following:

“4.2 EMPLOYER CONTRIBUTIONS

Employer Matching Contributions. For each payroll period, the Employer may contribute to the Plan, on behalf of each Participant, a discretionary matching contribution equal to a percentage (as determined by the Employer’s board of directors) of the elective deferrals (within the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by each such Participant; provided, however, that the amount of such Employer matching contribution for any Participant in a Plan Year shall not exceed three percent (3%) of the Participant’s Compensation for the period during which elective deferrals and/or after-tax contributions are made by the Participant.

Notwithstanding the provisions of this Section 4.2 to the contrary and solely with respect to Participants covered by a collective bargaining agreement, such Employer matching contributions shall be made in accordance with Appendix B, attached hereto.

Notwithstanding the provisions of this Section 4.2 to the contrary, and solely with respect to Non-union Participants who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010 and/or are first eligible to participate in the Plan and eligible Non-union Participants who are rehired on or after January 1, 2010, in lieu of receiving Employer matching contributions pursuant to the previous provisions of this section, the Employer will contribute to the Plan on behalf of each such Participant for each payroll period a matching contribution in an amount equal to 100% of the elective deferrals (within in the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by such Participant; provided, however, that the amount of such Employer Matching Contribution for any such Participant in a Plan Year shall not exceed six percent (6%) of the Participant’s Compensation for that payroll period. Those Participants who elect to continue participating in the Employer’s defined benefit plan will not be eligible for this increased matching contribution and shall continue to receive discretionary matching contributions in accordance with the previous provisions of this section.

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The Employer’s board of directors may also determine to suspend or reduce its contributions under this Section for any Plan Year or any portion thereof. Allocations under this Section shall be subject to the special rules of Section 13.3 in any Plan Year in which the Plan is a Top-Heavy Plan (as defined in Section 13.2(b)).

Notwithstanding anything in the foregoing provisions of this Section 4.2 to the contrary, effective December 1, 2011, an Employee who transfers from a location and/or division of the Employer that has not permitted Employees to opt-out of the Employer’s defined benefit plan (“DB Opt-Out”) to a location and/or division of the Employer which has permitted the DB Opt-Out, within forty-five days of the effective date of his transfer to such location, shall be provided with the opportunity to elect to either: (i) continue to participate in the Employer’s defined benefit plan, or (ii) elect to cease participating in the Employer’s defined benefit plan by opting out of such plan and, in lieu of receiving Employer matching contributions pursuant to the previous provisions of this section, the Employer will contribute to the Plan on behalf of each such Participant, for each payroll period, a matching contribution in an amount equal to one hundred percent (100%) of the elective deferrals (within in the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by such Participant; provided, however, that the amount of such Employer Matching Contribution for any such Participant in a Plan Year shall not exceed six percent (6%) of the Participant’s Compensation for that payroll period. Those Participants who elect to continue participating in the Employer’s defined benefit plan will not be eligible to receive the increased matching contribution and shall continue to receive discretionary matching contributions in accordance with the previous provisions of this Section.

Furthermore, notwithstanding anything in the foregoing provisions of this Section 4.2 to the contrary, effective December 1, 2011, any Employee who transfers from a location and/or division of the Employer where he elected to opt-out of the Employer’s defined benefit plan to receive the increased Employer matching contribution previously set forth (“DB Opt-Out”) to a location and/or division of the Employer that has not permitted the DB Opt-Out: (a) shall no longer be eligible to receive the increased matching contribution set forth above, (b) shall be eligible to receive an Employer matching contribution in accordance with the first and second paragraphs of this Section, and (c) shall be eligible to participate in the Employer’s defined benefit plan in accordance with the provisions thereof.”

3. Section 4.2A of the Plan is hereby amended by replacing it in its entirety with the following:

“4.2A COMPANY CONTRIBUTION. Effective on and after January 1, 2010, each payroll period the Employer shall make a ‘Company Contribution’ on behalf of Non-union Participants who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010 and/or are first eligible to participate in the Plan on and after January 1, 2010 and eligible Non-union Participants who are rehired on and after January 1, 2010 as well as any Participants who were eligible for the Plan prior to January 1, 2010 who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2010. Such ‘Company Contributions’ shall be in the amount equal to four percent (4%) of each such Participant’s Compensation for each payroll period.

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Notwithstanding anything in the foregoing to the contrary, effective on and after December 1, 2011, each payroll period, the Employer shall make a “Company Contribution” on behalf of Participants who had not previously been provided with the opportunity to make an election to opt-out of the Employer’s defined benefit plan, but who, within forty-five (45) days of their transfer of employment to a location/division of the Employer which has previously been provided the opportunity to make such an opt-out election, make such an election to opt-out of the Employer’s defined benefit plan. Such “Company Contribution” shall be in an amount equal to four percent (4%) of each such Participant’s Compensation for each payroll period.

Furthermore, notwithstanding anything in the foregoing provisions of this Section 4.2A to the contrary, effective December 1, 2011, any Employee who transfers from a location and/or division of the Employer where he elected to opt-out of the Employer’s defined benefit plan (“DB Opt-Out”) to a location and/or division of the Employer that has not permitted the DB Opt-Out: (a) shall no longer be eligible to receive “Company Contributions”, and (b) shall be eligible to participate in the Employer’s defined benefit plan in accordance with the provisions thereof.

Notwithstanding the provisions of this Section 4.2A to the contrary and solely with respect to Participants covered by a collective bargaining agreement, such “Company Contributions” shall be made in accordance with Appendix C, attached hereto.”

4. Effective as of January 1, 2011, Section 6.1 of the Plan shall be amended by adding the words “Company Contributions under Section 4.2A,” immediately after the words “Employer matching contributions under Section 4.2,” in the second paragraph of such section and by adding the following paragraph at the conclusion such section:

“Notwithstanding the provisions of this Section 6.1 to the contrary, and solely with respect to Local 1837 Employees (as defined in Appendices A, B and C, attached hereto) who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, and/or are first eligible to participate in the Plan on and after June 1, 2012 and eligible Local 183 7 Employees who are rehired on or after June 1, 2012, as well as any Participants who are Local 1837 Employees who were eligible for the Plan prior to June 1, 2012 and who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, any such Participant shall at all times have a nonforfeitable (vested) right to his Account derived from Employer matching contributions made on or after January 1, 2013 under Section 4.2. In addition, any such Participant shall at all times have a nonforfeitable (vested) right to his Account derived from Company Contributions under Section 4.2A.”

5. The Plan is hereby amended to add to the end thereof Appendices A, B, and C to the Plan, as follows:

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“APPENDIX A

Notwithstanding the provisions of Section 4.1(a) to the contrary and solely with respect to the unions named below, such Participants may elect to defer a portion of their Compensation for a Plan Year in accordance with the following:

I. Utility Workers Union of America, AFL-CIO, Local Union No. B340, The Brotherhood of Utility Workers Council (“Local B340”), June 1, 2005 through May 31, 2010. (This Agreement has been extended by a Memorandum of Understanding through May 31, 2013.)

Each Local B340 Participant may elect to contribute in the aggregate from one percent (1 %) to eighty-five percent (85%) of such Participant’s Compensation as a pre-tax contribution.

II. Local Union No. 1837, International Brotherhood of Electrical Workers (“Local 1837”), June 1, 2012 through May 31, 2018. These provisions are effective June 1, 2012.

Each Local 1837 Participant may elect to contribute in the aggregate from one percent (1 %) to eighty-five percent (85%) of such Participant’s Compensation as a pre-tax contribution.

Any Local 1837 Employee, who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, and/or upon first becoming eligible to participate in the Plan pursuant to Section 3.1 or upon becoming eligible upon being rehired on or after June 1, 2012, who fails to affirmatively make any deferral election (including an election to contribute zero percent (0%) of his Compensation to the Plan) within the time prescribed by the Administrator, shall be deemed to have elected to defer three percent (3%) of his Compensation as a pre-tax contribution (‘deemed elective deferral’). The Administrator shall provide to each such Employee a notice of his right to receive the amount of the deemed elective deferral in cash and his right to increase or decrease his rate of elective deferrals.

Participants who are Local 1837 Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, and/or who are first eligible to participate in the Plan, or are rehired, on or after June 1, 2012, shall be enrolled in the Plan’s ‘Managed Savings’ feature unless they elect to opt out of such feature. Such Participants, as of 1^st January of each Plan year, shall have their rate of elective deferral contributions automatically increased by one percent (1 %). Such rate of elective deferral contributions shall be further increased by an additional one percent (1 %) per year as of each subsequent January 1st. Notwithstanding the above, a Participant shall not have his rate of elective deferral contributions automatically increased beyond ten percent (10%). A Participant’s election to participate in the ‘Managed Savings’ feature shall remain in place until the Participant revokes such election.

III. United Steel Workers of America, AFL-CIO, Local No. 12012-6 (“Local 12012-6”), June 6, 2010 through June 5, 2014. (These are Northern-Portsmouth employees.)

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Each Local 12012-6 Participant may elect to contribute in the aggregate from one percent (1%) to eighty-five percent (85%) of such Participant’s Compensation as a pre-tax contribution.

Notwithstanding the foregoing, any Local 12012-6 Participant who did not elect to opt out of the Employer’s defined benefit plan as of January 1, 2011, may elect to contribute from one percent (1%) to seventy-five percent (75%) of his Compensation.

Any Local 12012-6 Employee, who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011, and/or upon first becoming eligible to participate in the Plan pursuant to Section 3.1 or upon becoming eligible upon being rehired on or after January 1, 2011, who fails to affirmatively make any deferral election (including an election to contribute zero percent (0%) of his Compensation to the Plan) within the time prescribed by the Administrator, shall be deemed to have elected to defer three percent (3%) of his Compensation as a pre-tax contribution (‘deemed elective deferral’). The Administrator shall provide to each such Employee a notice of his right to receive the amount of the deemed elective deferral in cash and his right to increase or decrease his rate of elective deferrals.

Participants who are Local 12012-6 Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011, and/or who are first eligible to participate in the Plan, or are rehired, on or after January 1, 2011, shall be enrolled in the Plan’s ‘Managed Savings’ feature unless they elect to opt out of such feature. Such Participants, as of January 1^st of each Plan year, shall have their rate of elective deferral contributions automatically increased by one percent (1%). Such rate of elective deferral contributions shall be further increased by an additional one percent (1%) per year as of each subsequent January 151 Notwithstanding the above, a Participant shall not have his rate of elective deferral contributions automatically increased beyond ten percent (10%). A Participant’s election to participate in the ‘Managed Savings’ feature shall remain in place until the Participant revokes such election.

IV. Utility Workers Union of America, Local No. 341 (“Local 341”), April 1, 2012 through March 31, 2017. (This contract covers both Northern Utilities, Inc. and Granite State Gas Transmission, Inc.)

Each Local 341 Participant may elect to contribute in the aggregate from one percent

(1%) to eighty-five percent (85%) of such Participant’s Compensation as a pre-tax contribution.

Notwithstanding the foregoing, any Local 341 Participant who did not elect to opt out of the Employer’s defined benefit plan as of January 1, 2013, may elect to contribute from one percent (1%) to seventy-five percent (7 5%) of his Compensation.

6

Any Local 341 Employee, who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, and/or upon first becoming eligible to participate in the Plan pursuant to Section 3.1 or upon becoming eligible upon being rehired on or after April 1, 2012, who fails to affirmatively make any deferral election (including an election to contribute zero percent (0%) of his Compensation to the Plan) within the time prescribed by the Administrator, shall be deemed to have elected to defer three percent (3%) of his Compensation as a pre-tax contribution (‘deemed elective deferral’). The Administrator shall provide to each such Employee a notice of his right to receive the amount of the deemed elective deferral in cash and his right to increase or decrease his rate of elective deferrals.

Participants who are Local 341 Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, and/or who are first eligible to participate in the Plan, or are rehired, on or after April 1, 2012, shall be enrolled in the Plan’s ‘Managed Savings’ feature unless they elect to opt out of such feature. Such Participants, as of January 1^st of each Plan year, shall have their rate of elective deferral contributions automatically increased by one percent (1%). Such rate of elective deferral contributions shall be further increased by an additional one percent (1%) per year as of each subsequent January 1^st. Notwithstanding the above, Participant shall not have his rate of elective deferral contributions automatically increased beyond ten percent (10%). A Participant’s election to participate in the ‘Managed Savings’ feature shall remain in place until the Participant revokes such election.

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APPENDIXB

Notwithstanding the provisions of Section 4.2 to the contrary and solely with respect to the unions named below, Employer matching contributions shall be calculated as follows:

I. Utility Workers Union of America, AFL-CIO, Local Union No. B340, The Brotherhood of Utility Workers Council (“Local B340”), June 1, 2005 through May 31, 2010. (This Agreement has been extended by a Memorandum of Understanding through May 31, 2013.)

Employer Matching Contribution for all Local B340 Participants - For each payroll period, the Employer shall contribute to the Plan, on behalf of each Participant, a discretionary matching contribution equal to a percentage (as determined by the Employer’s board of directors) of the elective deferrals (within the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by each such Participant; provided, however, that the amount of such Employer matching contribution for any Participant in a Plan Year shall not exceed three percent (3%) of the Participant’s Compensation for the period during which elective deferrals and/or after-tax contributions are made by the Participant.

II. Local Union No. 1837, International Brotherhood of Electrical Workers (“Local 1837’’), June 1, 2012 through May 31, 2018. These provisions are effective June 1, 2012.

Employer Matching Contribution for Local 1837 Participants - For each payroll period the Employer shall contribute to the Plan, on behalf of each such Participant who has completed a Year of Service, a matching contribution in an amount equal to 100% of the pre-tax elective deferrals made by such Participant during the payroll period which do not exceed 3% of Compensation of such Participant. Employer matching contributions shall commence with the payroll after the first day of the month following such Participant’s completion of one Year of Service.

Notwithstanding the foregoing, and solely with respect to Local 1837 Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, and/or are first eligible to participate in the Plan and eligible Local 1837 Employees who are rehired on or after June 1, 2012, as well as any Participants who are Local 1837 Employees who were eligible for the Plan prior to January 1, 2013 and who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, in lieu of receiving Employer matching contributions pursuant to the previous provisions of this section, the Employer will contribute to the Plan on behalf of each such Participant for each payroll period a matching contribution in an amount equal to 100% of the elective deferrals (within in the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by such Participant; provided, however, that the amount of such Employer Matching Contribution for any such Participant in a Plan Year shall not exceed six percent (6%) of the Participant’s Compensation for that payroll period. Those Participants who elect to continue participating in the Employer’s defined benefit plan will not be eligible for this increased matching contribution and shall continue to receive discretionary matching contributions in accordance with the previous provisions of this section.

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III. United Steel Workers of America, AFL-CIO, Local No. 12012-6 (“Local 12012-6”), June 6, 2010 through June 5, 2014. (These are Northern-Portsmouth employees.)

Employer Matching Contribution for Local 12012-6 Participants - For each payroll period the Employer shall contribute to the Plan, on behalf of each such Participant who has completed a Year of Service, a matching contribution in an amount equal to 50% of the pre-tax elective deferrals made by such Participant during the payroll period which do not exceed 5% of Compensation of such Participant. Employer matching contributions shall commence with the payroll after the first day of the month following such Participant’s completion of one Year of Service.

Notwithstanding the foregoing, and solely with respect to Local 12012-6 Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011, and/or are first eligible to participate in the Plan and eligible Local 12012-6 Employees who are rehired on or after January 1, 2011, as well as any Participants who are Local 12012-6 Employees who were eligible for the Plan prior to January 1, 2011 and who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011, in lieu of receiving Employer matching contributions pursuant to the previous provisions of this section, the Employer will contribute to the Plan on behalf of each such Participant for each payroll period a matching contribution in an amount equal to 100% of the elective deferrals (within in the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by such Participant; provided, however, that the amount of such Employer Matching Contribution for any such Participant in a Plan Year shall not exceed six percent (6%) of the Participant’s Compensation for that payroll period. Those Participants who elect to continue participating in the Employer’s defined benefit plan will not be eligible for this increased matching contribution and shall continue to receive discretionary matching contributions in accordance with the previous provisions of this section.

IV. Utility Workers Union of America, Local No. 341 (“Local 341”), April 1, 2012 through March 31, 2017. (This contract covers both Northern Utilities, Inc. and Granite State Gas Transmission, Inc.)

Employer Matching Contribution for Local 341 Participants - For each payroll period the Employer shall contribute to the Plan, on behalf of each such Participant who has completed a Year of Service, a matching contribution in an amount equal to 100% of the pre-tax elective deferrals made by such Participant during the payroll period which do not exceed 3% of Compensation of such Participant. Employer matching contributions shall commence with the payroll after the first day of the month following such Participant’s completion of one Year of Service.

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Notwithstanding the foregoing, and solely with respect to Local 341 Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, and/or are first eligible to participate in the Plan and eligible Local 341 Employees who are rehired on or after April 1, 2012, as well as any Participants who are Local 341 Employees who were eligible for the Plan prior to January 1, 2013 and who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, in lieu of receiving Employer matching contributions pursuant to the previous provisions of this section, the Employer will contribute to the Plan on behalf of each such Participant for each payroll period a matching contribution in an amount equal to 100% of the elective deferrals (within in the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by such Participant; provided, however, that the amount of such Employer Matching Contribution for any such Participant in a Plan Year shall not exceed six percent (6%) of the Participant’s Compensation for that payroll period. Those Participants who elect to continue participating in the Employer’s defined benefit plan will not be eligible for this increased matching contribution and shall continue to receive discretionary matching contributions in accordance with the previous provisions of this section.

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APPENDIX C

Notwithstanding the provisions of Section 4.2A to the contrary and solely with respect to the unions named below, Company contributions shall be calculated as follows:

I. Utility Workers Union of America, AFL-CIO, Local Union No. B340, The Brotherhood of Utility Workers Council (“Local B340”), June 1, 2005 through May 31, 201 0. (This Agreement has been extended by a Memorandum of Understanding through May 31, 2013.)

Not eligible for “Company Contributions” under Section 4.2A.

II. Local Union No. 1837, International Brotherhood of Electrical Workers (“Local 1837”), June I, 2012 through May 31, 2018. These provisions are effective June 1, 2012.

Effective on and after June 1, 2012, each payroll period the Employer shall make a ‘Company Contribution’ on behalf of Participants who are Local 1837 Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, and/or are first eligible to participate in the Plan on and after June 1, 2012 and eligible Participants who are Local 1837 Employees rehired on and after June 1, 2012 as well as any Participants who are Local 1837 Employees who were eligible for the Plan prior to January 1, 2013 who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013. Such ‘Company Contributions’ shall be in the amount equal to four percent (4%) of each such Participant’s Compensation for each payroll period.

III. United Steel Workers of America, AFL-CIO, Local No. 12012-6 (“Local 12012-6”), June 6, 2010 through June 5, 2014. (These are Northern-Portsmouth employees.)

Effective on and after January 1, 2011 , each payroll period the Employer shall make a ‘Company Contribution’ on behalf of Participants who are Local 12012-6 Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 201 1, and/or are first eligible to participate in the Plan on and after January 1, 2011 and eligible Participants who are Local 12012-6 Employees rehired on and after January 1, 201 1 as well as any Participants who are Local 12012-6 Employees who were eligible for the Plan prior to January 1, 2011 who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2011. Such ‘Company Contributions’ shall be in the amount equal to four percent (4%) of each such Participant’s Compensation for each payroll period.

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IV. Utility Workers Union of America, Local No. 341 (“Local 341”), April I, 2012 through March 31, 2017. (This contract covers both Northern Utilities, Inc. and Granite State Gas Transmission, Inc.) Effective on and after April 1, 2012, each payroll period the Employer shall make a ‘Company Contribution’ on behalf of Participants who are Local 341 Employees who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013, and/or are first eligible to participate in the Plan on and after April 1, 2012 and eligible Participants who are Local 341 Employees rehired on and after April l , 2012 as well as any Participants who are Local 341 Employees who were eligible for the Plan prior to January 1, 2013 who elected to opt-out of the Employer’s defined benefit plan as of January 1, 2013. Such ‘Company Contributions’ shall be in the amount equal to four percent (4%) of each such Participant’s Compensation for each payroll period.”

5. Except as hereinabove amended, the provisions of the Plan shall continue in full force and effect.

IN WITNESS THEREOF, the Employer, by its duly authorized officer, has caused this Amendment to be executed on the 21^st day of September, 2012.

UNITIL CORPORATION
By:	/s/ Mark H. Collin

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AMENDMENT TO

UNITIL CORPORATION TAX DEFERRED SAVINGS AND INVESTMENT PLAN

WHEREAS, Unitil Corporation (the Employer”) heretofore adopted the Unitil Corporation Tax Deferred Savings and Investment Plan (the “Plan”); and

WHEREAS, the Employer reserved the right to amend the Plan; and

WHEREAS, the Employer desires to amend the Plan to exclude certain rehired Employees from participating under the Plan;

NOW, THEREFORE, the Plan is hereby amended, effective as of January 1, 2012, as follows:

1. Section 3.1 of the Plan is hereby amended by deleting the last paragraph thereof in its entirety and replacing it with the following:

“In no event, however, shall any Employee (or other individual) participate under the Plan while he is: (i) included in a unit of Employees covered by a collective bargaining agreement between the Employer and the Employee representatives under which retirement benefits were the subject of good faith bargaining, unless the terms of such bargaining agreement expressly provides for the inclusion in the Plan; (ii) employed as an independent contractor on the payroll records of the Employer (regardless of any subsequent reclassification by the Employer, any governmental agency or court); (iii) employed as a Leased Employee; (iv) employed as a nonresident alien who receives no earned income (within the meaning of Section 911(d)(2) of the Code) from the Employer which constitutes income from sources within the United States (within the meaning of Section 861 (a)(3) of the Code); or (v) a rehired Employee who works on temporary assignments during storm restoration and who is eligible to commence benefits or has commenced benefits under the Unitil Corporation Retirement Plan (or would be eligible under the terms of that plan if that plan was available to him).

2. Section 3.2 of the Plan is hereby amended to read as follows:

“RE-EMPLOYMENT OF FORMER PARTICIPANT. A vested Participant (or a nonvested Participant whose prior Service cannot be disregarded) whose participation ceased because of termination of employment with the Employer shall resume participating upon his reemployment as an eligible Employee; provided, however, that such an individual (if not otherwise a member of an excluded class pursuant to Section 3.1 of the Plan) shall be entitled to commence elective deferrals (within the meaning of Section 4.1) as soon as administratively possible following his return to participation in the Plan.”

3. Except as hereinabove amended, the provisions of the Plan shall continue in full force and effect.

1

IN WITNESS THEREOF, the Employer, by its duly authorized officer, has caused this Amendment to be executed on the 21^st day of September, 2012.

UNITIL CORPORATION
By:	/s/ Mark H. Collin

2

AMENDMENT TO

UNITIL CORPORATION TAX DEFERRED SAVINGS AND INVESTMENT PLAN

WHEREAS, Unitil Corporation (the “Employer”) heretofore adopted the Unitil Corporation Tax Deferred Savings and Investment Plan (the “Plan”); and

WHEREAS, the Employer reserved the right to amend the Plan; and

WHEREAS, the Employer desires to amend the Plan pursuant to a new collective bargaining agreement for Local B340 as well as to permit participants to make loan repayments to the Plan following termination of employment;

NOW, THEREFORE, the Plan is hereby amended, effective as of June 1, 2013 except as otherwise provided below, as follows:

1. Effective October I, 2013, Section 8.1 of the Plan is hereby amended by deleting the penultimate paragraph of said Section and replacing it with the following:

“If a Participant terminates employment with an outstanding loan balance, the Participant may, subject to the terms and conditions of the underlying promissory note, continue to make loan repayments. However, in the event the loan goes into default, or to the extent distribution of the Participant’s Account is to be made or commenced, the outstanding loan balance shall be charged against the amounts that are otherwise payable to the Participant or the Participant’s Beneficiary under the provisions of the Plan. For any Participant with a loan(s) in good standing on October 1, 2013, loan repayments may be made after termination of employment notwithstanding anything to the contrary set forth in the underlying promissory note.”

2. Appendix A to the Plan is hereby amended to replace Item I thereof with the following:

“I. Utility Workers Union of America, AFL-CIO, Local Union No. B340, The Brotherhood of Utility Workers Council (‘Local B340’), June 1, 2013 through May 31, 2019.

Each Local B340 Participant may elect to contribute in the aggregate from one percent (1%) to eighty-five percent (85%) of such Participant’s Compensation as a pre-tax contribution.

Any Local B340 Employee, who either (i) elected to opt-out of the Employer’s defined benefit plan as of January 1, 2014 or (ii) who is first hired or rehired on or after June 1, 2013, and who, upon first becoming eligible to participate in the Plan in accordance with Section 3.1 , fails to affirmatively make any deferral election (including an election to contribute zero percent (0%) of his Compensation to the Plan) within the time prescribed by the Administrator, shall be deemed to have elected to defer three percent (3%) of his Compensation as a pre-tax contribution (‘deemed elective deferral ‘). The Administrator shall provide to each such Employee a notice of his right to receive the amount of the deemed elective deferral in cash and his right to increase or decrease his rate of elective deferrals.

Participants who are Local B340 Employees who either (i) elected to opt-out of the Employer’s defined benefit plan as of January 1, 2014 or (ii) who are hired or rehired, on or after June 1, 2013, shall, upon first becoming eligible to participate in the Plan in accordance with Section 3.1, also be enrolled in the Plan’s ‘Managed Savings’ feature unless they elect to opt out of such feature. Such Participants, as of January 1st of each Plan year, shall have their rate of elective deferral contributions automatically increased by one percent (1 %). Such rate of elective deferral contributions shall be further increased by an additional one percent (1 %) per year as of each subsequent January 1st. Notwithstanding the above, a Participant shall not have his rate of elective deferral contributions automatically increased beyond ten percent (1 0%). A Participant’s election to participate in the ‘Managed Savings’ feature shall remain in place until the Participant revokes such election.

Notwithstanding the foregoing, in no event shall any Local B340 Employee who opted out of the Employer’s defined benefit plan prior to meeting the eligibility requirements set forth under Section 3.1 of this Plan become a participant in the Plan, be enrolled in the Plan’s ‘Managed Savings’ feature and/or be eligible for any Employer Contributions as described below, until such Local B340 Employee has satisfied the age and service requirements set forth in Section 3.1.”

3. Appendix B to the Plan is hereby amended to replace Item I thereof with the following:

“I. Utility Workers Union of America, AFL-CIO, Local Union No. B340, The Brotherhood of Utility Workers Council (‘Local B340’), June 1, 2013 through May 31, 2019.

Employer Matching Contribution for Local B340 Participants - For each payroll period, the Employer shall contribute to the Plan, on behalf of each Participant, a discretionary matching contribution equal to a percentage (as determined by the Employer’s board of directors) of the elective deferrals (within the meaning of Section 4.1) and/or after-tax contributions (under Section 4.5) made by each such Participant; provided, however, that the amount of such Employer matching contribution for any Participant in a Plan Year shall not exceed three percent (3%) of the Participant’s Compensation for the period during which elective deferrals and/or after-tax contributions are made by the Participant

Notwithstanding the foregoing, and solely with respect to Local B340 Employees who either elected to opt-out of the Employer’s defined benefit plan as of January I, 2014 or who are hired or rehired on or after June 1, 2013, shall, in lieu of receiving Employer matching contributions pursuant to the previous provisions of this section, instead receive an Employer matching contribution for each payroll period in an amount equal to 100% of the elective deferrals (within the meaning of Section 4.1) and/or after-tax contributions (within the meaning of Section 4.5) made by such Participant; provided, however, that the amount of such Employer Matching Contribution for any such Participant in a Plan Year shall not exceed six percent ( 6%) of the Participant’s Compensation for that payroll

period. Those Participants who elect to either continue participating in the Employer’s defined benefit plan or participate in the Employer’s defined benefit plan upon satisfaction of such defined benefit plan’s eligibility provisions shall not be eligible for this increased matching contribution and shall instead receive Employer discretionary matching contributions in accordance with the previous provisions of this section.

Notwithstanding the foregoing, in no event shall any Local B340 Employee be eligible to participate in the Plan and receive Employer contributions prior to satisfying the eligibility provisions of Section 3.1 of the Plan.”

4. Appendix C to the Plan is hereby amended to replace Item I thereof with the following:

“I. Utility Workers Union of America, AFL-CIO, Local Union No. B340, The Brotherhood of Utility Workers Council (‘Local B340’), June 1, 2013 through May 31, 2019.

Effective on and after June 1, 2013, each payroll period the Employer shall make a ‘Company Contribution’ on behalf of Participants who are Local B340 Employees who either elected to opt-out of the Employer’s defined benefit plan as of January 1, 2014 or who are hired or rehired on and after June 1, 2013. Such ‘Company Contributions’ shall be in the amount equal to four percent (4%) of each such Participant’s Compensation for each payroll period. Notwithstanding the foregoing, in no event shall any Local B340 Employee be eligible to participate in the Plan and receive Employer contributions prior to satisfying the eligibility provisions of Section 3.1 of the Plan.”

5. Except as hereinabove amended, the provisions of the Plan shall continue in full force and effect.

IN WITNESS THEREOF, the Employer, by its duly authorized officer, has caused this Amendment to be executed on the 24^th day of September, 2013.

UNITIL CORPORATION
By:	/s/ Robert G. Schoenberger
	Chairman, Chief Executive Officer & President

EX-11.1

Exhibit 11.1

UNITIL CORPORATION

COMPUTATION IN SUPPORT OF EARNINGS PER SHARE

	Year Ended December 31,
	2013		2012		2011
EARNINGS PER SHARE (000’s, except per share data)
Net Income	$	21,629	$	18,196	$	16,439
Less: Dividend Requirements on Preferred Stock		14		102		131
Net Income Applicable to Common Stock	$	21,615	$	18,094	$	16,308
Average Number of Common Shares Outstanding—Basic		13,773		12,669		10,880
Dilutive Effect of Stock Options and Restricted Stock		2		3		3
Average Number of Common Shares Outstanding—Diluted		13,775		12,672		10,883
Earnings Per Share—Basic	$	1.57	$	1.43	$	1.50
Earnings Per Share—Diluted	$	1.57	$	1.43	$	1.50

EX-12.1

Exhibit 12.1

UNITIL CORPORATION

COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
	2013		2012		2011		2010		2009
(000’s, except ratios)
Earnings:
Net Income, per Consolidated Statement of Earnings	$	21,629	$	18,196	$	16,439	$	9,616	$	10,049
Federal and State Income Taxes included in Operations		12,652		10,976		10,025		4,464		5,220
Interest on Long-Term Debt		19,907		19,948		19,987		19,664		17,961
Amortization of Debt Discount Expense		302		324		340		307		233
Other Interest		1,737		2,003		1,760		2,015		2,474
Total	$	56,227	$	51,447	$	48,551	$	36,066	$	35,937
Fixed Charges:
Interest of Long-Term Debt	$	19,907	$	19,948	$	19,987	$	19,664	$	17,961
Amortization of Debt Discount Expense		302		324		340		307		233
Other Interest		1,737		2,003		1,760		2,015		2,474
Pre-tax Preferred Stock Dividend Requirements		22		165		211		194		208
Total	$	21,968	$	22,440	$	22,298	$	22,180	$	20,876
Ratio of Earnings to Fixed Charges		2.56		2.29		2.18		1.63		1.72

EX-21.1

Exhibit 21.1

Subsidiaries of Registrant

The Company or the registrant has eight wholly-owned subsidiaries, seven of which are corporations organized under the laws of the State of New Hampshire: Unitil Energy Systems, Inc., Northern Utilities, Inc., Granite State Gas Transmission, Inc., Unitil Power Corp., Unitil Realty Corp., Unitil Resources, Inc. and Unitil Service Corp. The eighth, Fitchburg Gas and Electric Light Company, is organized under the laws of the State of Massachusetts. Usource, Inc., which is a corporation organized under the laws of the State of Delaware, is a wholly-owned subsidiary of Unitil Resources, Inc. Usource, Inc. is the sole member of Usource L.L.C., which is a corporation organized under the laws of the State of Delaware.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements on Form S-3 (File Nos. 333-180316 and 333-168394) and Form S-8 (File Nos. 333-184849, 333-114978 and 333-42266) of Unitil Corporation and subsidiaries of our report dated January 29, 2014, relating to our audits of the consolidated financial statements as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 and internal control over financial reporting as of December 31, 2013, included in this Annual Report on Form 10-K of Unitil Corporation and subsidiaries for the year ended December 31, 2013.

/s/ McGladrey LLP

Boston, Massachusetts

January 29, 2014

EX-31.1

Exhibit 31.1

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Robert G. Schoenberger, certify that:

1) I have reviewed this annual report on Form 10-K of Unitil Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 29, 2014

/s/ Robert G. Schoenberger

Robert G. Schoenberger

Chief Executive Officer and President

EX-31.2

Exhibit 31.2

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark H. Collin, certify that:

1) I have reviewed this annual report on Form 10-K of Unitil Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 29, 2014

/s/ Mark H. Collin

Mark H. Collin

Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Laurence M. Brock, certify that:

1) I have reviewed this annual report on Form 10-K of Unitil Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 29, 2014

/s/ Laurence M. Brock

Laurence M. Brock

Chief Accounting Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Unitil Corporation (the “Company”) on Form 10-K for the year ending December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned Robert G. Schoenberger, Chief Executive Officer and President, Mark H. Collin, Chief Financial Officer and Laurence M. Brock, Chief Accounting Officer, certifies, to the best knowledge and belief of the signatory, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Signature	Capacity	Date
/s/ Robert G. Schoenberger Robert G. Schoenberger	Chief Executive Officer and President	January 29, 2014
/s/ Mark H. Collin Mark H. Collin	Chief Financial Officer	January 29, 2014
/s/ Laurence M. Brock Laurence M. Brock	Chief Accounting Officer	January 29, 2014

EX-99.1

Exhibit 99.1

PAGE 1 OF 3

For Release

UNITIL REPORTS YEAR-END EARNINGS

HAMPTON, N.H., JANUARY 29, 2014 – Unitil Corporation (NYSE: UTL) (www.unitil.com) today reported Earnings Applicable to Common Shareholders (Earnings) of $21.6 million and $1.57 per share for the year ended December 31, 2013, an improvement of $3.5 million and $0.14 per share compared to 2012. Earnings for the three months ended December 31, 2013 were $10.3 million and $0.75 per share, an increase of $1.3 million and $0.09 per share compared to the same period in 2012. Results for 2013 were driven by increases in natural gas and electric sales margins, partially offset by higher utility operating costs.

“The continued strong demand for natural gas helped produce excellent financial results in 2013,” said Bob Schoenberger, Unitil’s Chairman and Chief Executive Officer. “The robust growth in our utility businesses is due to several factors, including favorable weather, continued investment in distribution infrastructure and recently approved electric and gas base rates. This provides a strong foundation for future growth.”

Natural gas sales margins were $28.9 million and $85.2 million in the three and twelve month periods ended December 31, 2013, increases of $3.8 million and $9.0 million, respectively, compared to 2012. Natural gas sales margins in 2013 were positively affected by higher therm unit sales, a growing customer base and higher base distribution rates. Therm sales of natural gas increased 11.2% and 10.7% in the three and twelve month periods ended December 31, 2013 compared to 2012, driven by the colder winter weather in 2013 compared to 2012 coupled with strong growth in the number of new residential and commercial & industrial (C&I) customers. Based on weather data collected in the Company’s service areas, there were 16% more Heating Degree Days in 2013 compared to 2012. Weather-normalized gas therm sales, excluding decoupled sales, in 2013 are estimated to be up 4.2% compared to 2012. Approximately 11% of Unitil’s natural gas therm sales are decoupled and changes in these sales due to the weather do not affect sales margins.

Electric sales margins were $19.1 million and $76.2 million in the three and twelve month periods ended December 31, 2013, a decrease of $0.1 million and an increase of $4.3 million, respectively, compared to 2012, reflecting slightly lower sales to electric C&I customers in the fourth quarter of 2013. Overall, Electric kilowatt-hour (kWh) sales increased 0.1% and 0.9% in the three and twelve month periods ended December 31, 2013 compared to the same periods in 2012. Electric sales margins reflect higher electric base distribution rates in 2013 which include recovery of $1.3 million of vegetation management and electric reliability enhancement expenditures as well as an increase of $0.7 million in the recovery of major storm restoration costs, which are offset by a corresponding increase in operating expenses, discussed below. Approximately 27% of electric kWh sales are decoupled and changes in these sales due to the weather do not affect sales margins.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $5.8 million in 2013, an increase of $0.3 million compared to 2012. 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.

Operation & Maintenance (O&M) expenses increased $0.3 million and $4.0 million in the three and twelve month periods ended December 31, 2013 compared to the same periods in 2012. Overall, the change in 2013 O&M expenses reflects higher utility operating costs of $1.9 million, higher compensation and benefit costs of $1.0 million, higher professional fees of $0.9 million and higher all other O&M expenses, net of $0.2 million. The increase in utility operating costs in 2013 includes $1.3 million in new spending on vegetation management programs which is recovered through cost tracker rate mechanisms that result in a corresponding and offsetting increase in revenue and margin in the period.

(Continued on Next Page)

6 Liberty Lane West

Hampton, New Hampshire 03842

www.unitil.com

Ph: 603-772-0775 Fax: 603-773-6605

PAGE 2 OF 3

Depreciation, Amortization, Taxes and other expenses increased $1.5 million and $5.4 million in the three and twelve month periods ended December 31, 2013 compared to the same periods in 2012. In the twelve month period ended December 31, 2013, Depreciation and Amortization expense increased $2.6 million compared to 2012 reflecting higher depreciation of $1.6 million on normal utility plant additions, higher amortization of major storm restoration costs of $0.7 million and an increase in all other amortization of $0.3 million. The increase in major storm restoration cost amortization is also recovered in current electric rates. Property taxes increased $1.0 million in 2013 compared to 2012, reflecting higher levels of utility plant in service. Federal and State Income Taxes increased $1.7 million in 2013 due to higher pre-tax earnings in 2013 compared to 2012. All other expenses, net increased $0.1 million in 2013 compared to 2012.

Interest Expense, net increased $0.6 million and $0.7 million in the three and twelve month periods ended December 31, 2013 compared to the same periods in 2012, reflecting lower net interest income on regulatory assets, partially offset by lower average rates on lower short-term borrowings.

Selected financial data for 2013 and 2012 is presented in the following table:

Unitil Corporation – Condensed Consolidated Financial Data

(Millions, except Per Share data)(Unaudited)

	Three Months Ended December 31,							Twelve Months Ended December 31,
	2013		2012		Change			2013		2012		Change
Gas Therm Sales:
Residential		10.0		8.8		13.6	%		39.8		34.8		14.4	%
Commercial/Industrial		43.7		39.5		10.6	%		160.9		146.5		9.8	%
Total Gas Therm Sales		53.7		48.3		11.2	%		200.7		181.3		10.7	%
Electric kWh Sales:
Residential		155.9		154.9		0.6	%		690.9		677.7		1.9	%
Commercial/Industrial		231.2		232.0		(0.3	%)		977.4		976.1		0.1	%
Total Electric kWh Sales		387.1		386.9		0.1	%		1,668.3		1,653.8		0.9	%
Gas Revenues	$	58.6	$	53.4	$	5.2		$	170.4	$	160.6	$	9.8
Cost of Gas Sales		29.7		28.3		1.4			85.2		84.4		0.8
Gas Sales Margin		28.9		25.1		3.8			85.2		76.2		9.0
Electric Revenues		49.8		44.0		5.8			190.7		187.0		3.7
Cost of Electric Sales		30.7		24.8		5.9			114.5		115.1		(0.6	)
Electric Sales Margin		19.1		19.2		(0.1	)		76.2		71.9		4.3
Usource Sales Margin		1.4		1.4		—			5.8		5.5		0.3
Total Sales Margin:		49.4		45.7		3.7			167.2		153.6		13.6
Operation & Maintenance Expenses		14.6		14.3		0.3			61.0		57.0		4.0
Depreciation, Amortization, Taxes & Other		19.7		18.2		1.5			65.8		60.4		5.4
Interest Expense, net		4.8		4.2		0.6			18.8		18.1		0.7
Earnings Applicable to Common Shareholders:	$	10.3	$	9.0	$	1.3		$	21.6	$	18.1	$	3.5
Earnings Per Share	$	0.75	$	0.66	$	0.09		$	1.57	$	1.43	$	0.14
Weighted Average Common Shares Outstanding (000’s)		13,800		13,723		77			13,775		12,672		1,103

At its January 2014 meeting, the Unitil Corporation Board of Directors declared the regular quarterly dividend on the Company’s common stock of $0.345 per share. Unitil paid common dividends of $1.38 per share in 2013.

Earnings per share in 2013 and 2012 reflect the sale of 2,760,000 common shares on May 16, 2012.

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The Company’s results are expected to reflect the seasonal nature of its natural gas businesses. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher and negatively affected during the second and third quarters, when gas operating expenses usually exceed sales margins in those periods.

The Company will hold a quarterly conference call to discuss fourth quarter and full year 2013 results on Wednesday, January 29, 2014, at 2:00 p.m. Eastern Time. This call is being webcast and can be accessed in the Investor Relations section of Unitil Corporation’s website, www.unitil.com.

About Unitil Corporation

Unitil Corporation provides energy for life by safely and reliably delivering natural gas and electricity in New England. We are committed to the communities we serve and to developing people, business practices, and technologies that lead to dependable, more efficient energy. Unitil Corporation is a public utility holding company with operations in Maine, New Hampshire and Massachusetts. Together, Unitil’s operating utilities serve approximately 102,400 electric customers and 75,900 natural gas customers. Other subsidiaries include Usource, Unitil’s non-regulated business segment. For more information about our people, technologies, and community involvement please visit www.unitil.com.

This press release contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. All statements, other than statements of historical fact, are forward-looking statements. Certain factors that could cause the actual results to differ materially from those projected in these forward-looking statements include, but are not limited to the following: variations in weather; changes in the regulatory environment; customers’ preferences on energy sources; general economic conditions; increased competition; fluctuations in supply, demand, transmission capacity and prices for energy commodities; and other uncertainties, all of which are difficult to predict, and many of which are beyond the control of Unitil Corporation.

For more information please contact:

David Chong – Investor Relations	Alec O’Meara – Media Relations
Phone: 603-773-6499	Phone: 603-773-6404
Email: chong@unitil.com	Email: omeara@unitil.com

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Allowance for Doubtful Accounts - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 4.6	$ 3.6	$ 4.3
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 1.4	$ 1.9	$ 1.8

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Company's Liability for Environmental Obligations (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Environmental Exit Cost [Line Items]
Total Environmental Obligations-Balance at Beginning of Period	$ 14.8		$ 14.7
Changes in Estimates			0.1
Liabilities Assumed
Less: Payments / Reductions
Total Environmental Obligations-Balance at End of Period	14.8		14.8
Less: Current Portion	1.0	[1]	1.0	[1]
Environmental Obligations-noncurrent-Balance at End of Period	$ 13.8		$ 13.8

[1] Reflects amounts included in Other Current Liabilities on the Company's Consolidated Balance Sheets.

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Equity - Additional Information (Detail) (USD $)	12 Months Ended					12 Months Ended					12 Months Ended				12 Months Ended	1 Months Ended	12 Months Ended				1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Apr. 21, 2011	Apr. 21, 2011 Before Amendment	Dec. 31, 2013 Non Vested Restricted Stock	Dec. 31, 2012 Non Vested Restricted Stock	Dec. 31, 2011 Non Vested Restricted Stock	Dec. 31, 2013 Restricted Stock Units	Dec. 31, 2012 Restricted Stock Units Maximum	Dec. 31, 2013 Restricted Stock Y	Dec. 31, 2012 Restricted Stock	Dec. 31, 2011 Restricted Stock	Dec. 31, 2013 Restricted Stock Maximum	Dec. 31, 2013 Restricted Stock Units	May 16, 2012 Common Stock Offering	Dec. 31, 2013 Dividend and Distribution Reinvestment and Share Purchase Plan	Dec. 31, 2012 Dividend and Distribution Reinvestment and Share Purchase Plan	Dec. 31, 2011 Dividend and Distribution Reinvestment and Share Purchase Plan	Dec. 31, 2013 Unitil Energy Systems Inc Series 6 Nonredeemable Preferred Stock Noncumulative Preferred Stock	Dec. 31, 2012 Fitchburg Gas and Electric Light Company Series 8	Dec. 31, 2012 Fitchburg Gas and Electric Light Company Series 5
Class of Stock [Line Items]
Common stock, authorized shares				25,000,000	16,000,000
Common stock, shares outstanding	13,841,400	13,780,601
Common stock, share issued																2,760,000	39,559	41,752	39,473
Common stock price per share																$ 25.25	$ 29.01
Proceed from issuance of common stock	$ 1,100,000	$ 66,800,000	$ 1,000,000													$ 65,700,000	$ 1,100,000	$ 1,100,000	$ 1,000,000
Common stock shares repurchase	2,969	6,368	8,765
Repurchase expense	100,000	200,000	200,000
Restricted stock available for awards														677,500
Restricted stock that may be awarded in any one calendar year to any one participant														20,000
Restricted stock vesting period											4 years
Restricted stock vesting percentage annually											25.00%
Restricted stock non-vested											53,480	53,932
Restricted stock weighted average grant date fair value											$ 25.99	$ 24.67
Share based compensation expense											700,000	1,300,000	700,000
Unrecognized share based compensation											700,000
Share compensation recognition period											2.4
Forfeitures or cancellations under the stock plan											0
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled															70.00%
Percentage of fully-vested restricted stock units that directors will receive in cash when settled															30.00%
Fair value of liabilities associated with fully vested RSUs that will be settled in cash									200,000	100,000
Preferred Stock	200,000	200,000																		200,000
Dividend rate																				6.00%	8.00%	5.125%
Redeemable, Cumulative Preferred Stock	$ 0	$ 8,000	$ 8,600																		$ 1,000,000	$ 800,000
Preferred Stock premium percentage																						1.28%
Antidilutive securities excluded from computation of earnings per share						4,481	24,325	1,642

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Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) (Other Postretirement Benefit Plans, Defined Benefit, USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	$ 10,829	$ 8,301
Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	1,673	1,274
Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	4,689	3,670
Index Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	4,467	3,357
Fair Value, Inputs, Level 1
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	10,829	8,301
Fair Value, Inputs, Level 1 | Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	1,673	1,274
Fair Value, Inputs, Level 1 | Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	4,689	3,670
Fair Value, Inputs, Level 1 | Index Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	$ 4,467	$ 3,357

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Provisions for Federal and State Income Taxes (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current Federal Tax Provision (Benefit)
Current Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)	10,052,000	9,085,000	7,976,000
Total Federal Tax Provision	10,052,000	9,085,000	7,976,000
State
Current	386,000	132,000	1,358,000
Deferred	2,214,000	1,759,000	691,000
Total State Tax Provision	2,600,000	1,891,000	2,049,000
Total Provision for Federal and State Income Taxes	12,652,000	10,976,000	10,025,000
Current Benefit of Operating Loss Carrybacks
Current Federal Tax Provision (Benefit)
Current Federal Tax Provision (Benefit)
Utility Plant Differences
Deferred Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)	28,907,000	6,019,000	13,002,000
Net Operating Loss Carryforwards
Deferred Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)	(8,053,000)	2,835,000	(4,844,000)
Regulatory Assets and Liabilities
Deferred Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)	(11,483,000)	472,000	513,000
Other, net
Deferred Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)	$ 681,000	$ (241,000)	$ (695,000)

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Borrowing Limits Amounts Outstanding and Amounts Available Under Revolving Credit Facility (Detail) (Revolving Credit Facility, USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Oct. 04, 2013	Dec. 31, 2012
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility	$ 120.0	$ 120.0	$ 60.0
Outstanding revolving credit facility	60.2		49.4
Available revolving credit facility	$ 59.8		$ 10.6

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Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets (Detail) (Not Designated as Hedging Instrument, USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative Assets
Derivative Assets	$ 0.2
Derivative Liabilities
Derivative Liabilities		0.7
Natural Gas Contracts | Prepayments and Other
Derivative Assets
Derivative Assets	0.1
Natural Gas Contracts | Other Noncurrent Assets
Derivative Assets
Derivative Assets	0.1
Natural Gas Contracts | Other Current Liabilities
Derivative Liabilities
Derivative Liabilities		$ 0.7

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Deferred Tax Assets and Liabilities, Current (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Current Deferred Income Taxes
Accrued Revenue, Current Portion	$ 6,583,000	$ 13,568,000
Other, net	108,000	(168,000)
Total Current Deferred Income Tax Liabilities	$ 6,700,000	$ 13,400,000

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Provisions for Federal and State Income Taxes

Provisions for Federal and State Income Taxes in the accompanying consolidated statements of earnings for the years ended December 31, 2013, 2012 and 2011 are shown in the table below:

	($000’s)
	2013			2012			2011
Current Federal Tax Provision (Benefit)
Current Benefit of Operating Loss Carrybacks	$	—		$	—		$	—
Total Current Federal Tax Provision (Benefit)		—			—			—
Deferred Federal Tax Provision (Benefit)
Utility Plant Differences		28,907			6,019			13,002
Net Operating Loss Carryforwards		(8,053	)		2,835			(4,844	)
Regulatory Assets and Liabilities		(11,483	)		472			513
Other, net		681			(241	)		(695	)
Total Deferred Federal Tax Provision (Benefit)		10,052			9,085			7,976
Total Federal Tax Provision		10,052			9,085			7,976
State
Current		386			132			1,358
Deferred		2,214			1,759			691
Total State Tax Provision		2,600			1,891			2,049
Total Provision for Federal and State Income Taxes	$	12,652		$	10,976		$	10,025

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate

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:

	2013			2012			2011
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, Net		5			5			5
Utility Plant Differences		(2	)		(2	)		(1	)
Other, Net		—			1			—
Effective Income Tax Rate		37	%		38	%		38	%

Deferred Income Taxes Assets Liabilities Current

Deferred Tax Assets and Liabilities

Temporary differences which gave rise to current deferred tax assets and liabilities in 2013 and 2012, are shown below:

Current Deferred Income Taxes (000’s)	2013		2012
Accrued Revenue, Current Portion	$	6,583	$	13,568
Other, net		108		(168	)
Total Current Deferred Income Tax Liabilities	$	6,691	$	13,400

Deferred Income Taxes Assets liabilities Noncurrent

Deferred Tax Assets and Liabilities

Temporary differences which gave rise to noncurrent deferred tax assets and liabilities in 2013 and 2012, are shown below:

Noncurrent Deferred Income Taxes (000’s)	2013			2012
Utility Plant Differences	$	102,479		$	66,907
Net Operating Loss Carryforwards		(17,403	)		(8,521	)
AMT Tax Credit Carryforwards		(1,538	)		(1,538	)
Regulatory Assets & Liabilities		17,174			17,872
Retirement Benefit Obligations		(28,287	)		(38,644	)
Other, net		754			2,606
Total Noncurrent Deferred Income Tax Liabilities	$	73,179		$	38,682

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Restricted Stock Units Issued (Detail) (Restricted Stock, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock
Restricted Stock Units
Beginning Restricted Stock Units	3,883
Restricted Stock Units Granted	10,710	3,829
Dividend Equivalents Earned	310	54
Restricted Stock Units Settled
Ending Restricted Stock Units	14,903	3,883
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 27.39
Restricted Stock Units Granted	$ 29.43	$ 27.43
Dividend Equivalents Earned	$ 29.47	$ 24.62
Restricted Stock Units Settled
Ending Restricted Stock Units	$ 28.90	$ 27.39

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Estimated Fair Value of Long-Term Debt (Detail) (Fair Value, Inputs, Level 2, USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long- Term Debt	$ 327.3	$ 349.7

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Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013 mi Entity Segment
Segment Reporting Information [Line Items]
No of segments	4
No of subsidiaries	3
Length Of Pipeline	86
Granite State Gas Transmission Inc
Segment Reporting Information [Line Items]
Length Of Pipeline	86
No of major pipeline	3

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Energy Supply - Additional Information (Detail)	1 Months Ended	12 Months Ended
	Jul. 31, 2012	Dec. 31, 2013
Fitchburg Gas and Electric Light Company
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities		14,057
Percentage of power supply requirement		50.00%
Power supply contract duration		12 months
Fitchburg Gas and Electric Light Company | Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration		1 year
Northern Utilities Inc
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities		100,000
Natural gas, underground storage		3.4
Northern Utilities Inc | Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration		1 year
Unitil Energy Systems Inc
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement	100.00%	100.00%
Power supply contract duration	6 months	12 months

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Assets Measured at Fair Value on Recurring Basis for Pension Plan (Detail) (Pension Plans, USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	$ 82,551	$ 72,411
Equity Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	44,201	34,742
Fixed Income Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	26,276	34,251
Equity And Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	4,574	3,418
Real Estate Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	1,125
Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	6,375
Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	81,426	72,411
Fair Value, Inputs, Level 1 | Equity Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	44,201	34,742
Fair Value, Inputs, Level 1 | Fixed Income Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	26,276	34,251
Fair Value, Inputs, Level 1 | Equity And Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	4,574	3,418
Fair Value, Inputs, Level 1 | Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	6,375
Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	1,125
Fair Value, Inputs, Level 3 | Real Estate Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	$ 1,125

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Retirement Benefit Plans - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended			1 Months Ended				1 Months Ended		1 Months Ended			12 Months Ended
	Jun. 25, 2010	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Aug. 17, 2006 Pension Protection Act	Jul. 06, 2012 Well-Funded Pension Plan	Jul. 06, 2012 Well-Funded Pension Plan Minimum	Aug. 17, 2006 Well-Funded Pension Plan Minimum	Jul. 06, 2012 Well-Funded Pension Plan Maximum	Aug. 17, 2006 Well-Funded Pension Plan Maximum	Jan. 31, 2010 Employee Retirement Income Security Act Class Action	Dec. 31, 2013 Defined Benefit Obligations	Dec. 31, 2012 Defined Benefit Obligations	Dec. 31, 2013 Fair Value Of Plan Assets	Dec. 31, 2012 Fair Value Of Plan Assets	Dec. 31, 2011 Fair Value Of Plan Assets	Dec. 31, 2013 Pension Plans	Dec. 31, 2012 Pension Plans	Dec. 31, 2011 Pension Plans	Dec. 31, 2013 Pension Plans Equity Funds	Dec. 31, 2013 Pension Plans Fixed Income Securities	Dec. 31, 2013 Pension Plans Real Estate Funds	Dec. 31, 2013 Pension Plans Equity And Debt Securities	Dec. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit	Dec. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit	Dec. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit Equity Funds	Dec. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit Fixed Income Securities	Dec. 31, 2013 Pension Plans	Dec. 31, 2012 Pension Plans	Dec. 31, 2011 Pension Plans	Dec. 31, 2013 Supplemental Employee Retirement Plans, Defined Benefit	Dec. 31, 2012 Supplemental Employee Retirement Plans, Defined Benefit	Dec. 31, 2011 Supplemental Employee Retirement Plans, Defined Benefit	Dec. 31, 2013 Four Zero One K Plan	Dec. 31, 2012 Four Zero One K Plan	Dec. 31, 2011 Four Zero One K Plan	Dec. 31, 2013 Scenario, Forecast Other Postretirement Benefit Plans, Defined Benefit	Dec. 31, 2013 Scenario, Forecast Pension Plans	Dec. 31, 2013 Scenario, Forecast Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Change in Discount Rate		0.25%	0.25%	0.25%
Increase or decrease of Net Periodic Benefit Cost (NPBC) due to change in the discount rate		$ 431,000	$ 367,000	$ 325,000
Increase in Rate of Compensation		3.00%	3.00%	3.50%
Amortizations related to Actuarial Loss and Prior Service Cost																																					1,700,000	3,100,000	100,000
Pension expense		6,600,000	6,300,000	6,200,000										6,600,000	6,700,000	5,700,000
Regulatory Assets		143,700,000	186,500,000									42,600,000	62,500,000
Accumulated Benefit Obligation																												96,900,000	103,400,000		5,100,000	4,800,000
Defined Benefit Plan, Funded Percentage					100.00%	100.00%		92.00%		100.00%	80.00%
Amortization Period For Defined Benefit Plan					7 years						7 years
Defined Benefit Plan, shortfall											10,200,000													(786,000)	(129,000)			(4,229,000)	(3,617,000)	(3,132,000)	(184,000)	(64,000)	(78,000)
Defined Benefit Plan, Annual Employer Contributions											1,700,000
Defined Benefit Plan, Description of Settlements and Curtailments	The Company evaluated the two alternative shortfall amortization periods under the Relief Act and made the decision to continue with the seven year amortization period.
Company's contributions						3,100,000											3,700,000	9,387,000	8,813,000					3,280,000	2,190,000						53,000	53,000	53,000	1,678,000	1,387,000	1,190,000
Minimum required contribution							$ 1,000,000		$ 6,100,000
Defined Benefit Plan, Target Plan Asset Allocations																				48.00%	37.00%	10.00%	5.00%			55.00%	45.00%
Defined Benefit Plan, Expected Long-term Return on Assets		8.50%
Defined Benefit Plan, Expected Long-term Rate-of-Return on Assets Assumption		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.

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Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Operating leases
2014	$ 1,244
2015	1,114
2016	926
2017	647
2018	294
2019 - 2023	15
Total Payments	4,240
Capital lease
2014	390
2015	174
2016	40
2017
2018
2019 - 2023
Total Payments	$ 604

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Segment Information

12 Months Ended

Dec. 31, 2013

Segment Information

Note 3: Segment Information

Unitil reports four segments: utility gas operations, utility electric operations, non-regulated, and other. Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capitol 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.

The following table provides significant segment financial data for the years ended December 31, 2013, 2012 and 2011 (millions):

Year Ended December 31, 2013	Gas		Electric		Non- Regulated		Other			Total
Revenues	$	170.4	$	190.7	$	5.8	$	—		$	366.9
Interest Income		0.5		2.2		0.1		0.4			3.2
Interest Expense		11.0		9.5		—		1.5			22.0
Depreciation & Amortization Expense		17.2		19.5		—		1.0			37.7
Income Tax Expense (Benefit)		7.5		5.1		0.8		(0.7	)		12.7
Segment Profit (Loss)		12.5		7.6		1.2		0.3			21.6
Segment Assets		502.3		402.8		6.2		9.3			920.6
Capital Expenditures		61.1		23.6		—		4.8			89.5
Year Ended December 31, 2012
Revenues	$	160.6	$	187.0	$	5.5	$	—		$	353.1
Interest Income		0.8		2.9		0.1		0.4			4.2
Interest Expense		11.1		9.5		—		1.7			22.3
Depreciation & Amortization Expense		15.7		18.0		—		1.4			35.1
Income Tax Expense (Benefit)		5.8		4.8		0.9		(0.5	)		11.0
Segment Profit (Loss)		8.9		7.6		1.3		0.3			18.1
Segment Assets		471.7		409.3		5.7		5.6			892.3
Capital Expenditures		43.9		21.2		—		3.4			68.5
Year Ended December 31, 2011
Revenues	$	159.2	$	188.1	$	5.5	$	—		$	352.8
Interest Income		0.5		0.9		0.1		0.1			1.6
Interest Expense		10.7		9.6		—		1.7			22.0
Depreciation & Amortization Expense		13.6		14.2		—		1.5			29.3
Income Tax Expense		4.3		5.2		1.1		(0.6	)		10.0
Segment Profit		6.7		7.8		1.7		0.1			16.3
Segment Assets		442.2		401.9		5.5		6.5			856.1
Capital Expenditures		33.6		20.3		—		3.2			57.1

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Components of Retirement Plan Costs (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	$ 3,573	$ 3,227	$ 2,941
Interest Cost	4,567	4,633	4,684
Expected Return on Plan Assets	(5,955)	(5,390)	(4,840)
Prior Service Cost Amortization	208	188	249
Actuarial Loss Amortization	4,229	3,617	3,132
Sub-total	6,622	6,275	6,166
Amounts Capitalized and Deferred	(2,929)	(2,726)	(2,590)
NPBC Recognized	3,693	3,549	3,576
Other Postretirement Benefit Plans, Defined Benefit
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	2,523	2,066	1,918
Interest Cost	2,448	2,303	2,279
Expected Return on Plan Assets	(722)	(695)	(818)
Prior Service Cost Amortization	1,701	1,729	1,729
Transition Obligation Amortization		21	21
Actuarial Loss Amortization	786	129
Sub-total	6,736	5,553	5,129
Amounts Capitalized and Deferred	(3,010)	(2,127)	(1,622)
NPBC Recognized	3,726	3,426	3,507
Supplemental Employee Retirement Plans, Defined Benefit
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	73	289	285
Interest Cost	241	211	227
Prior Service Cost Amortization	11	11	11
Actuarial Loss Amortization	184	64	78
Sub-total	509	575	601
NPBC Recognized	$ 509	$ 575	$ 601

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Details on Long Term Debt (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Long-Term Debt	$ 287.3	$ 287.8
Less: Current Portion	2.5	0.5
Total Long-Term Debt, Less Current Portion	284.8	287.3
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Senior Notes	20.0	20.0
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Series, Due March 2, 2020
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Series, Due October 14, 2024
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Series, Due September 1, 2028
Debt Instrument [Line Items]
Long-Term Debt	20.0	20.0
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Series, Due May 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Series, Due September 15, 2036
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Fitchburg Gas and Electric Light Company | 6.75% Notes, Due November 30, 2023
Debt Instrument [Line Items]
Long-Term Debt	19.0	19.0
Fitchburg Gas and Electric Light Company | 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Long-Term Debt	12.0	12.0
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	14.0	14.0
Fitchburg Gas and Electric Light Company | 6.79% Notes, Due October 15, 2025
Debt Instrument [Line Items]
Long-Term Debt	10.0	10.0
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Northern Utilities Inc | 6.95% Senior Notes, Series A, Due December 3, 2018
Debt Instrument [Line Items]
Senior Notes	30.0	30.0
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Senior Notes	25.0	25.0
Northern Utilities Inc | 7.72% Senior Notes, Series B, Due December 3, 2038
Debt Instrument [Line Items]
Senior Notes	50.0	50.0
Granite State Gas Transmission Inc | 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Senior Notes	10.0	10.0
Unitil Realty Corp | 8.00% Senior Secured Notes, Due August 1, 2017
Debt Instrument [Line Items]
Senior Secured Notes	$ 2.3	$ 2.8

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Exchange Gas Receivable (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Receivables [Line Items]
Total Exchange Gas Receivable	$ 10.8	$ 9.4
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	9.8	8.7
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 1.0	$ 0.7

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Components of Accrued Revenue (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 56.6	$ 63.4
Regulatory Asset
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	43.6	51.9
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 13.0	$ 11.5

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Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Examination [Line Items]
Statutory Federal Income Tax Rate	34.00%	34.00%	34.00%
State Income Taxes, Net	5.00%	5.00%	5.00%
Utility Plant Differences	(2.00%)	(2.00%)	(1.00%)
Other, Net		1.00%
Effective Income Tax Rate	37.00%	38.00%	38.00%

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Details on Long Term Debt (Parenthetical) (Detail)	Dec. 31, 2013	Dec. 31, 2012
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate	6.33%	6.33%
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Series, Due March 2, 2020
Debt Instrument [Line Items]
Stated interest rate	5.24%	5.24%
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Series, Due October 14, 2024
Debt Instrument [Line Items]
Stated interest rate	8.49%	8.49%
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Series, Due September 1, 2028
Debt Instrument [Line Items]
Stated interest rate	6.96%	6.96%
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Series, Due May 1, 2031
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Series, Due September 15, 2036
Debt Instrument [Line Items]
Stated interest rate	6.32%	6.32%
Fitchburg Gas and Electric Light Company | 6.75% Notes, Due November 30, 2023
Debt Instrument [Line Items]
Stated interest rate	6.75%	6.75%
Fitchburg Gas and Electric Light Company | 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Stated interest rate	7.37%	7.37%
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Stated interest rate	7.98%	7.98%
Fitchburg Gas and Electric Light Company | 6.79% Notes, Due October 15, 2025
Debt Instrument [Line Items]
Stated interest rate	6.79%	6.79%
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Stated interest rate	5.90%	5.90%
Northern Utilities Inc | 6.95% Senior Notes, Series A, Due December 3, 2018
Debt Instrument [Line Items]
Stated interest rate	6.95%	6.95%
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Stated interest rate	5.29%	5.29%
Northern Utilities Inc | 7.72% Senior Notes, Series B, Due December 3, 2038
Debt Instrument [Line Items]
Stated interest rate	7.72%	7.72%
Granite State Gas Transmission Inc | 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Stated interest rate	7.15%	7.15%
Unitil Realty Corp | 8.00% Senior Secured Notes, Due August 1, 2017
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%

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Components of Gas Inventory (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 1.2	$ 1.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.8	0.6
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.3	0.4
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.1	$ 0.1

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Regulatory Assets (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Regulatory Assets [Line Items]
Regulatory Assets	$ 143.7		$ 186.5
Less: Current Portion of Regulatory Assets	43.6	[1]	51.9	[1]
Regulatory Assets-noncurrent	100.1		134.6
Restructuring Charges | Energy Supply & Other Regulatory Tracker Mechanisms
Regulatory Assets [Line Items]
Regulatory Assets	32.5		41.0
Restructuring Charges | Deferred Restructuring Costs
Regulatory Assets [Line Items]
Regulatory Assets	9.3		20.1
Retirement Benefits
Regulatory Assets [Line Items]
Regulatory Assets	42.6		62.5
Income Taxes
Regulatory Assets [Line Items]
Regulatory Assets	11.9		10.2
Electric Utilities
Regulatory Assets [Line Items]
Regulatory Assets	25.6		27.8
Other Assets
Regulatory Assets [Line Items]
Regulatory Assets	5.7		8.1
Environmental Matters
Regulatory Assets [Line Items]
Regulatory Assets	$ 16.1		$ 16.8

[1] Reflects amounts included in Accrued Revenue on the Company's Consolidated Balance Sheets.

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Quarterly Financial Information

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information

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,
	2013		2012		2013			2012			2013		2012		2013		2012
Total Operating Revenues	$	118.2	$	114.2	$	66.4		$	68.8		$	72.5	$	71.3	$	109.8	$	98.8
Operating Income	$	21.9	$	19.3	$	4.5		$	4.3		$	5.6	$	5.0	$	21.5	$	18.9
Net Income (Loss) Applicable to Common	$	10.8	$	9.0	$	(0.1	)	$	(0.4	)	$	0.6	$	0.5	$	10.3	$	9.0
	Per Share Data:
Earnings Per Common Share	$	0.79	$	0.83	$	(0.01	)	$	(0.03	)	$	0.04	$	0.03	$	0.75	$	0.66
Dividends Paid Per Common Share	$	0.345	$	0.345	$	0.345		$	0.345		$	0.345	$	0.345	$	0.345	$	0.345

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Regulatory Liabilities (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 9.7	$ 6.8
Regulatory Tracker Mechanisms
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 9.7	$ 6.8

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Activity in Company's Allowance for Doubtful Accounts (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Electric	Dec. 31, 2012 Electric	Dec. 31, 2011 Electric	Dec. 31, 2013 Gas	Dec. 31, 2012 Gas	Dec. 31, 2011 Gas	Dec. 31, 2013 Other	Dec. 31, 2012 Other	Dec. 31, 2011 Other	Jan. 01, 2011 Other
Accounts and Other Receivables [Line Items]
Balance at Beginning of Period	$ 1.9	$ 2.3	$ 2.6	$ 1.1	$ 1.7	$ 1.8	$ 0.7	$ 0.5	$ 0.7	$ 0.1	$ 0.1	$ 0.1	$ 0.1
Provision	4.6	3.6	4.3	2.6	1.4	2.1	2.0	2.2	2.2
Recoveries	0.4	0.6	0.5	0.2	0.3	0.2	0.2	0.3	0.3
Accounts Written Off	5.3	4.6	5.1	2.6	2.3	2.4	2.7	2.3	2.7
Balance at End of Period	$ 1.6	$ 1.9	$ 2.3	$ 1.3	$ 1.1	$ 1.7	$ 0.2	$ 0.7	$ 0.5	$ 0.1	$ 0.1	$ 0.1	$ 0.1

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Commitments and Contingencies - Additional Information (Detail) (USD $)						12 Months Ended	1 Months Ended				1 Months Ended								1 Months Ended	12 Months Ended	1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Other Restructuring	Dec. 31, 2013 New Hampshire Environmental Restoration Costs	Dec. 31, 2013 Maine Environmental Restoration Costs	Dec. 31, 2013 Environmental Matters	Dec. 27, 2013 Northern Utilities Inc	Apr. 30, 2013 Northern Utilities Inc	Dec. 31, 2013 Northern Utilities Inc	Dec. 31, 2013 Northern Utilities Inc Other Current Liabilities	Apr. 30, 2013 Northern Utilities Inc New Hampshire	Dec. 27, 2013 Northern Utilities Inc Maine	Jul. 31, 2013 Fitchburg Gas and Electric Light Company	Oct. 31, 2012 Fitchburg Gas and Electric Light Company	May 01, 2012 Fitchburg Gas and Electric Light Company	Jul. 31, 2013 Fitchburg Gas and Electric Light Company Storm Costs	Dec. 31, 2013 Fitchburg Gas and Electric Light Company Environmental Clean Up Costs	Dec. 31, 2013 Fitchburg Gas and Electric Light Company Environmental Restoration Costs	Oct. 31, 2012 Unitil Energy Systems Inc	Dec. 31, 2013 Unitil Energy Systems Inc	Apr. 26, 2011 Unitil Energy Systems Inc Year One Policy	Apr. 26, 2011 Unitil Energy Systems Inc Year Two Policy	Apr. 25, 2013 Unitil Energy Systems Inc Storm Costs	Jun. 30, 2013 Granite State Gas Transmission Inc Gas Transportation and Storage
Regulatory Assets [Line Items]
Regulatory Assets, Remaining Balance	$ 12,700,000
Accrued Revenue	56,600,000	63,400,000	10,200,000
Increase in annual revenue								2,500,000			5,200,000	3,800,000	6,700,000			2,100,000					5,200,000	5,000,000
Amendment effective date								July 1, 2013				January 1, 2014									July 1, 2010	May 1, 2011
TIRA initial term							Four years
Percentage of elligibilty for earnings							10.00%
Percentage of earnings shared equally							11.00%
Service quality plan penalties impossed							500,000
Percent of increase in annual revenue											9.40%		11.50%
Settlement agreement date																				May 01, 2016
Adjustment to recover the increased spending for vegetation management program and reliability enhancement program and a proposed storm resiliency program																				2,800,000
Annual revenue increase in rate adjustments																								400,000
Storm recovery adjustment factor amount													2,800,000
Recovery of damage of electrical system														1,100,000					2,700,000
Construction expenditures														300,000					400,000
Storm expenditures															4,300,000
Recovery of damage of electrical system																							2,300,000
Cost recovery period, years																							5 years
Interest rate allowed by regulators on the unrecovered amount of storm costs which have been approved for recovery through rate adjustments																							4.52%
Income (loss) incurred in excess of recorded amount						0
Amortization period for environmental costs				7 years	5 years													7 years
Environmental obligations	$ 14,800,000	$ 14,800,000							$ 1,800,000	$ 1,000,000							$ 12,000,000

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Consolidated Statements of Earnings (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues:
Gas	$ 170,400,000	$ 160,600,000	$ 159,200,000
Electric	190,700,000	187,000,000	188,100,000
Other	5,800,000	5,500,000	5,500,000
Total Operating Revenues	366,900,000	353,100,000	352,800,000
Operating Expenses:
Cost of Gas Sales	85,200,000	84,400,000	91,300,000
Cost of Electric Sales	114,500,000	115,100,000	120,500,000
Operation and Maintenance	61,000,000	57,000,000	51,500,000
Depreciation and Amortization	37,700,000	35,100,000	29,300,000
Taxes Other Than Income Taxes	15,000,000	14,000,000	13,000,000
Total Operating Expenses	313,400,000	305,600,000	305,600,000
Operating Income	53,500,000	47,500,000	47,200,000
Interest Expense, net	18,800,000	18,100,000	20,400,000
Other Expense (Income), net	400,000	200,000	400,000
Income Before Income Taxes	34,300,000	29,200,000	26,400,000
Income Taxes	12,652,000	10,976,000	10,025,000
Net Income	21,600,000	18,200,000	16,400,000
Less Dividends on Preferred Stock		100,000	100,000
Earnings Applicable to Common Shareholders	$ 21,600,000	$ 18,100,000	$ 16,300,000
Earnings per Common Share-Basic and Diluted	$ 1.57	$ 1.43	$ 1.50
Average Common Shares Outstanding-Basic	13,772,855	12,669,309	10,880,025
Average Common Shares Outstanding-Diluted	13,775,245	12,671,609	10,882,971

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Summary of Interest Expense and Interest Income (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Interest Expense
Long-term Debt	$ 20.2		$ 20.3		$ 20.3
Short-term Debt	1.2		1.5		1.7
Regulatory Liabilities	0.6		0.5
Interest Expense	22.0		22.3		22.0
Interest Income
Interest income	(3.2)		(4.2)		(1.6)
Total Interest Expense, net	18.8		18.1		20.4
Regulatory Asset
Interest Income
Interest income	(2.3)		(3.4)		(1.1)
AFUDC and Other
Interest Income
Interest income	$ (0.9)	[1]	$ (0.8)	[1]	$ (0.5)	[1]

[1] AFUDC-Allowance for Funds Used During Construction

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Consolidated Statements of Changes in Common Stock Equity (Parenthetical)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Common Stock, Shares issued	39,559	41,752	39,473
Common Stock, Shares issued		2,760,000

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Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended			3 Months Ended	12 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2013 Massachusetts	Dec. 31, 2013 Federal	Dec. 31, 2013 Federal and State	Dec. 31, 2013 State and Local Jurisdiction	Dec. 31, 2013 Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Net Operating Loss carryforward assets						$ 17,400,000		$ 6,600,000
NOL carryforward assets expiration date							2019	2029
Alternative Minimum tax credit carryforwards	$ 1,538,000	$ 1,538,000
Corporate effective tax rate	37.00%	38.00%	38.00%	8.00%
Tax examination description					The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2010; December 31, 2011; and December 31, 2012.

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Energy Supply Obligations (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Contractual Obligation [Line Items]
Energy Supply Obligations	$ 14.4	$ 13.8
Energy Supply Obligations	2.5	3.3
Total Energy Supply Obligations	16.9	17.1
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations	9.8	8.7
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations	3.7	4.2
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations	0.9	0.9
Energy Supply Obligations	$ 2.5	$ 3.3

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Estimated Future Benefit Payments (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Pension Plans
Schedule of Pension Expected Future Benefit Payments [Line Items]
2014	$ 4,495
2015	4,617
2016	4,742
2017	5,050
2018	5,188
2019 - 2023	31,826
Other Postretirement Benefit Plans, Defined Benefit
Schedule of Pension Expected Future Benefit Payments [Line Items]
2014	1,914
2015	2,056
2016	2,129
2017	2,277
2018	2,404
2019 - 2023	14,496
Supplemental Employee Retirement Plans, Defined Benefit
Schedule of Pension Expected Future Benefit Payments [Line Items]
2014	384
2015	380
2016	375
2017	369
2018	364
2019 - 2023	$ 1,925

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Debt and Financing Arrangements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value of Long Term Debt

Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2013		2012
Estimated Fair Value of Long- Term Debt	$	327.3	$	349.7

Details on Long Term Debt

Details on long-term debt at December 31, 2013 and 2012 are shown below:

Long-Term Debt (millions)	December 31,
	2013		2012
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0
Unitil Energy First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0
8.49% Series, Due October 14, 2024		15.0		15.0
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		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0
Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		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
Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0
Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		2.3		2.8
Total Long-Term Debt		287.3		287.8
Less: Current Portion		2.5		0.5
Total Long-Term Debt, Less Current Portion	$	284.8	$	287.3

Summary of Interest Expense and Interest Income

A summary of interest expense and interest income is provided in the following table:

Interest Expense, net (millions)
	2013			2012			2011
Interest Expense
Long-term Debt	$	20.2		$	20.3		$	20.3
Short-term Debt		1.2			1.5			1.7
Regulatory Liabilities		0.6			0.5			—
Subtotal Interest Expense		22.0			22.3			22.0
Interest Income
Regulatory Assets		(2.3	)		(3.4	)		(1.1	)
AFUDC(1) and Other		(0.9	)		(0.8	)		(0.5	)
Subtotal Interest Income		(3.2	)		(4.2	)		(1.6	)
Total Interest Expense, net	$	18.8		$	18.1		$	20.4

⁽¹⁾ AFUDC—Allowance for Funds Used During Construction

Borrowing Limits Amounts Outstanding and Amounts Available Under Revolving Credit Facility

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2013 and December 31, 2012:

Revolving Credit Facility (millions)
	December 31,
	2013		2012
Limit	$	120.0	$	60.0
Outstanding	$	60.2	$	49.4
Available	$	59.8	$	10.6

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases

The following is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2013:

Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2014	$	1,244	$	390
2015		1,114		174
2016		926		40
2017		647		—
2018		294		—
2019 – 2023		15		—
Total Payments	$	4,240	$	604

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Quarterly Financial Information (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information [Line Items]
Total Operating Revenues	$ 109.8	$ 72.5	$ 66.4	$ 118.2	$ 98.8	$ 71.3	$ 68.8	$ 114.2	$ 366.9	$ 353.1	$ 352.8
Operating Income	21.5	5.6	4.5	21.9	18.9	5.0	4.3	19.3	53.5	47.5	47.2
Net Income (Loss) Applicable to Common	$ 10.3	$ 0.6	$ (0.1)	$ 10.8	$ 9.0	$ 0.5	$ (0.4)	$ 9.0	$ 21.6	$ 18.1	$ 16.3
Per Share Data:
Earnings Per Common Share	$ 0.75	$ 0.04	$ (0.01)	$ 0.79	$ 0.66	$ 0.03	$ (0.03)	$ 0.83	$ 1.57	$ 1.43	$ 1.50
Dividends Paid Per Common Share	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 1.38	$ 1.38	$ 1.38

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Environmental Obligations

The following table shows the balances and activity in the Company’s liability for Environmental Obligations for 2013 and 2012.

ENVIRONMENTAL OBLIGATIONS

(Millions)	December 31,
	2013		2012
Total Environmental Obligations—Balance at Beginning of Period	$	14.8	$	14.7
Changes in Estimates		—		0.1
Liabilities Assumed		—		—
Less: Payments / Reductions		—		—
Total Environmental Obligations—Balance at End of Period		14.8		14.8
Less: Current Portion(1)		1.0		1.0
Environmental Obligations—noncurrent—Balance at End of Period	$	13.8	$	13.8

⁽¹⁾  Reflects amounts included in Other Current Liabilities on the Company’s Consolidated Balance Sheets.

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Fair Value of Pension Plan Investments Estimated using Net Asset Value (Detail) (SEI Core Property Collective Investment Trust Fund, USD $)	12 Months Ended
	Dec. 31, 2013
SEI Core Property Collective Investment Trust Fund
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	$ 1,125,000	[1]
Unfunded Commitment		[1]
Redemption on Frequency	Quarterly	[1]
Redemption on Notice Period	65 days	[1]

[1] The SEI Core Property Collective Investment Trust Fund, through the SEI Core Property Fund, seeks both current income and long-term capital appreciation through investing in underlying funds that acquire, manage, and dispose of commercial real estate properties.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies

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 results will reflect the seasonal nature of the natural gas distribution business. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher due to heating-related requirements, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.

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.

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.

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.

On August 1, 2011, the Massachusetts Department of Public Utilities (MDPU) issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of Fitchburg. 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. One of the primary purposes of decoupling is to eliminate the disincentive a utility otherwise has to encourage and promote energy conservation programs designed to reduce energy usage. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011 forward, distribution revenues for Fitchburg based on established revenue targets. The established revenue targets for the gas division may be subject to periodic adjustments to account for customer growth and special contracts, for which RDM does not apply. The difference between distribution revenue amounts billed to customers and the targeted amounts is recognized as increases or decreases in Accrued Revenue which form the basis for future reconciliation adjustments in periodically resetting rates for future cash recoveries from, or credits to, customers. The Company’s other electric and natural gas distribution utilities are not subject to RDM.

Revenue Recognition—Non-regulated Operations—Usource, Unitil’s competitive energy brokering subsidiary, records energy brokering revenues based upon the estimated 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 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: 2013 – 3.59%, 2012 – 3.60% and 2011 – 3.43%.

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 current and 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. Deferred income taxes are reflected as Current and Noncurrent Deferred Income Taxes on the Consolidated Balance Sheets based on the nature of the underlying timing item.

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 years ended December 31, 2013, 2012 and 2011, the Company paid quarterly dividends of $0.345 per share, resulting in an annual dividend rate of $1.38 per common 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. On December 31, 2013 and 2012, the Unitil subsidiaries had deposited $7.3 million and $5.4 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. On December 31, 2013 and 2012, there was $0 and $1.2 million, respectively, deposited for this purpose.

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. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company.

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below and unbilled revenues (see Utility Revenue Recognition below.) The following table shows the components of Accrued Revenue as of December 31, 2013 and 2012.

Accrued Revenue (millions)	December 31,
	2013		2012
Regulatory Assets—Current	$	43.6	$	51.9
Unbilled Revenues		13.0		11.5
Total Accrued Revenue	$	56.6	$	63.4

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. Prior to March 31, 2013, the exchange gas amounts had been recorded in Gas Inventory on the Company’s Consolidated Balance Sheets. Amounts previously reported have been reclassified to conform to current year presentation. 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, 2013 and 2012.

Exchange Gas Receivable (millions)	December 31,
	2013		2012
Northern Utilities	$	9.8	$	8.7
Fitchburg		1.0		0.7
Total Exchange Gas Receivable	$	10.8	$	9.4

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, 2013 and 2012.

Gas Inventory (millions)	December 31,
	2013		2012
Natural Gas	$	0.8	$	0.6
Propane		0.3		0.4
Liquefied Natural Gas & Other		0.1		0.1
Total Gas Inventory	$	1.2	$	1.1

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 1.92%, 2.04% and 2.28% in 2013, 2012 and 2011, 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, 2013 and 2012, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $57.3 million and $51.4 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 Massachusetts Department of Public Utilities (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 Financial Accounting Standards Board (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,
	2013		2012
Energy Supply & Other Regulatory Tracker Mechanisms	$	32.5	$	41.0
Deferred Restructuring Costs		9.3		20.1
Retirement Benefits		42.6		62.5
Income Taxes		11.9		10.2
Environmental		16.1		16.8
Deferred Storm Charges		25.6		27.8
Other		5.7		8.1
Total Regulatory Assets	$	143.7	$	186.5
Less: Current Portion of Regulatory Assets(1)		43.6		51.9
Regulatory Assets—noncurrent	$	100.1	$	134.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets.

Regulatory Liabilities consist of the following (millions)	December 31,
	2013		2012
Regulatory Tracker Mechanisms	$	9.7	$	6.8
Total Regulatory Liabilities	$	9.7	$	6.8

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.

Prior to June 30, 2013, certain regulatory tracker mechanisms which are currently recorded in Regulatory Liabilities had been recorded in Accrued Revenue and Other Current Liabilities on the Consolidated Balance Sheets. Amounts previously reported have been reclassified to conform to current year presentation.

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 a portion of its gas supply costs for the coming year of service. In order to fix these costs, the Company purchases natural gas futures and options contracts on the New York Mercantile Exchange (NYMEX) that correspond to the associated delivery month. Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through a regulatory commission approved recovery mechanism. 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 Purchased Gas when the gains and losses are passed through to customers in accordance with rate reconciling mechanisms.

As of December 31, 2013 and December 31, 2012, the Company had 1.8 billion and 1.9 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 Purchased Gas. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Other Current Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.

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

		Fair Value
Description	Balance Sheet Location	December 31, 2013		December 31, 2012
Derivative Assets
Natural Gas Futures Contracts	Prepayments and Other	$	0.1	$	—
Natural Gas Futures Contracts	Other Noncurrent Assets		0.1		—
Total Derivative Assets		$	0.2	$	—
Derivative Liabilities
Natural Gas Futures Contracts	Other Current Liabilities	$	—	$	0.7
Natural Gas Futures Contracts	Other Noncurrent Liabilities		—		—
Total Derivative Liabilities		$	—	$	0.7

	Twelve Months Ended December 31,
	2013		2012
Amount of Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	0.3	$	1.0
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings(1):
Purchased Gas	$	1.2	$	2.6

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

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, 2013, the unamortized balance of the bargain purchase adjustment is $12.2 million, to be amortized over the next five years.

Energy Supply Obligations—The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

	December 31,
Energy Supply Obligations consist of the following: (millions)	2013		2012
Current:
Exchange Gas Obligation	$	9.8	$	8.7
Renewable Energy Portfolio Standards		3.7		4.2
Power Supply Contract Divestitures		0.9		0.9
Total Energy Supply Obligations—Current	$	14.4	$	13.8
Long-Term:
Power Supply Contract Divestitures	$	2.5	$	3.3
Total Energy Supply Obligations	$	16.9	$	17.1

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 a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker rate mechanism.

Power Supply Contract Divestitures—As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity 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 on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion).

Massachusetts Green Communities Act—In compliance with the Massachusetts Green Communities Act, discussed below in Note 8, Commitments and Contingencies, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The facility associated with one of these contracts has been constructed and is operating. The other contracts are pending approval by the MDPU as well as subsequent facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

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 an unfunded 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, 2013, 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, 2013, 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, 2013, 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 December 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” The amendments in this ASU require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The Company adopted ASU 2011-11 and it did not have any impact on the Company’s Consolidated Financial Statements.

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 impacted its Consolidated Financial Statements.

Reclassifications—Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. Most significant has been the reclassification of certain regulatory tracker mechanisms from Accrued Revenue and Other Current Liabilities to Regulatory Liabilities, the reclassification of exchange gas amounts from Gas Inventory to Exchange Gas Receivable on the Company’s Consolidated Balance Sheets, as discussed above in Regulatory Accounting and Exchange Gas Receivable, respectively. Also, energy efficiency program expenses, which were previously presented as Conservation & Load Management on the Company’s Consolidated Statements of Earnings are now included in Cost of Gas Sales and Cost of Electric Sales.

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current Assets:
Cash and Cash Equivalents	$ 9.4	$ 9.8
Accounts Receivable, net	52.2	47.7
Accrued Revenue	56.6	63.4
Exchange Gas Receivable	10.8	9.4
Gas Inventory	1.2	1.1
Material and Supplies	5.0	4.1
Prepayments and Other	4.8	4.2
Total Current Assets	140.0	139.7
Utility Plant:
Gas	477.3	424.4
Electric	375.6	356.9
Common	31.6	30.9
Construction Work in Progress	24.6	21.0
Utility Plant	909.1	833.2
Less: Accumulated Depreciation	243.5	232.0
Net Utility Plant	665.6	601.2
Other Noncurrent Assets:
Regulatory Assets	100.1	134.6
Other Assets	14.9	16.8
Total Other Noncurrent Assets	115.0	151.4
TOTAL ASSETS	920.6	892.3
Current Liabilities:
Accounts Payable	38.1	32.7
Short-Term Debt	60.2	49.4
Long-Term Debt, Current Portion	2.5	0.5
Energy Supply Obligations	14.4	13.8
Deferred Income Taxes	6.7	13.4
Interest Payable	3.1	3.1
Regulatory liabilities	9.7	6.8
Other Current Liabilities	10.0	11.4
Total Current Liabilities	144.7	131.1
Noncurrent Liabilities:
Energy Supply Obligations	2.5	3.3
Deferred Income Taxes	73.2	38.7
Cost of Removal Obligations	57.3	51.4
Retirement Benefit Obligations	77.3	103.7
Environmental Obligations	13.8	13.8
Other Noncurrent Liabilities	1.8	2.4
Total Noncurrent Liabilities	225.9	213.3
Capitalization:
Long-Term Debt, Less Current Portion	284.8	287.3
Common Stock Equity:
Common Equity	232.1	230.0
Retained Earnings	32.9	30.4
Total Common Stock Equity	265.0	260.4
Preferred Stock	0.2	0.2
Total Capitalization	550.0	547.9
TOTAL LIABILITIES AND CAPITALIZATION	$ 920.6	$ 892.3

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Nature of Operations

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 results will reflect the seasonal nature of the natural gas distribution business. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher due to heating-related requirements, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.

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.

Principles of Consolidation

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.

Use of Estimates

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.

Fair Value

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 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.

On August 1, 2011, the Massachusetts Department of Public Utilities (MDPU) issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of Fitchburg. 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. One of the primary purposes of decoupling is to eliminate the disincentive a utility otherwise has to encourage and promote energy conservation programs designed to reduce energy usage. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011 forward, distribution revenues for Fitchburg based on established revenue targets. The established revenue targets for the gas division may be subject to periodic adjustments to account for customer growth and special contracts, for which RDM does not apply. The difference between distribution revenue amounts billed to customers and the targeted amounts is recognized as increases or decreases in Accrued Revenue which form the basis for future reconciliation adjustments in periodically resetting rates for future cash recoveries from, or credits to, customers. The Company’s other electric and natural gas distribution utilities are not subject to RDM.

Revenue Recognition-Non-regulated Operations

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

Depreciation and Amortization

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 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: 2013 – 3.59%, 2012 – 3.60% and 2011 – 3.43%.

Stock-based Employee Compensation

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

Sales and Consumption Taxes

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

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 current and 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. Deferred income taxes are reflected as Current and Noncurrent Deferred Income Taxes on the Consolidated Balance Sheets based on the nature of the underlying timing item.

Dividends

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 years ended December 31, 2013, 2012 and 2011, the Company paid quarterly dividends of $0.345 per share, resulting in an annual dividend rate of $1.38 per common share.

Cash and Cash Equivalents

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. On December 31, 2013 and 2012, the Unitil subsidiaries had deposited $7.3 million and $5.4 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. On December 31, 2013 and 2012, there was $0 and $1.2 million, respectively, deposited for this purpose.

Allowance for Doubtful Accounts

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. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company.

Accrued Revenue

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below and unbilled revenues (see Utility Revenue Recognition below.) The following table shows the components of Accrued Revenue as of December 31, 2013 and 2012.

Accrued Revenue (millions)	December 31,
	2013		2012
Regulatory Assets—Current	$	43.6	$	51.9
Unbilled Revenues		13.0		11.5
Total Accrued Revenue	$	56.6	$	63.4

Exchange Gas Receivable

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. Prior to March 31, 2013, the exchange gas amounts had been recorded in Gas Inventory on the Company’s Consolidated Balance Sheets. Amounts previously reported have been reclassified to conform to current year presentation. 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, 2013 and 2012.

Exchange Gas Receivable (millions)	December 31,
	2013		2012
Northern Utilities	$	9.8	$	8.7
Fitchburg		1.0		0.7
Total Exchange Gas Receivable	$	10.8	$	9.4

Gas Inventory

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, 2013 and 2012.

Gas Inventory (millions)	December 31,
	2013		2012
Natural Gas	$	0.8	$	0.6
Propane		0.3		0.4
Liquefied Natural Gas & Other		0.1		0.1
Total Gas Inventory	$	1.2	$	1.1

Utility Plant

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 1.92%, 2.04% and 2.28% in 2013, 2012 and 2011, 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, 2013 and 2012, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $57.3 million and $51.4 million, respectively.

Regulatory Accounting

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 Massachusetts Department of Public Utilities (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 Financial Accounting Standards Board (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,
	2013		2012
Energy Supply & Other Regulatory Tracker Mechanisms	$	32.5	$	41.0
Deferred Restructuring Costs		9.3		20.1
Retirement Benefits		42.6		62.5
Income Taxes		11.9		10.2
Environmental		16.1		16.8
Deferred Storm Charges		25.6		27.8
Other		5.7		8.1
Total Regulatory Assets	$	143.7	$	186.5
Less: Current Portion of Regulatory Assets(1)		43.6		51.9
Regulatory Assets—noncurrent	$	100.1	$	134.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets.

Regulatory Liabilities consist of the following (millions)	December 31,
	2013		2012
Regulatory Tracker Mechanisms	$	9.7	$	6.8
Total Regulatory Liabilities	$	9.7	$	6.8

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.

Prior to June 30, 2013, certain regulatory tracker mechanisms which are currently recorded in Regulatory Liabilities had been recorded in Accrued Revenue and Other Current Liabilities on the Consolidated Balance Sheets. Amounts previously reported have been reclassified to conform to current year presentation.

Derivatives

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 a portion of its gas supply costs for the coming year of service. In order to fix these costs, the Company purchases natural gas futures and options contracts on the New York Mercantile Exchange (NYMEX) that correspond to the associated delivery month. Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through a regulatory commission approved recovery mechanism. 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 Purchased Gas when the gains and losses are passed through to customers in accordance with rate reconciling mechanisms.

As of December 31, 2013 and December 31, 2012, the Company had 1.8 billion and 1.9 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 Purchased Gas. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Other Current Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.

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

		Fair Value
Description	Balance Sheet Location	December 31, 2013		December 31, 2012
Derivative Assets
Natural Gas Futures Contracts	Prepayments and Other	$	0.1	$	—
Natural Gas Futures Contracts	Other Noncurrent Assets		0.1		—
Total Derivative Assets		$	0.2	$	—
Derivative Liabilities
Natural Gas Futures Contracts	Other Current Liabilities	$	—	$	0.7
Natural Gas Futures Contracts	Other Noncurrent Liabilities		—		—
Total Derivative Liabilities		$	—	$	0.7

	Twelve Months Ended December 31,
	2013		2012
Amount of Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	0.3	$	1.0
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings(1):
Purchased Gas	$	1.2	$	2.6

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

Goodwill and Intangible Assets

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, 2013, the unamortized balance of the bargain purchase adjustment is $12.2 million, to be amortized over the next five years.

Energy Supply Obligations

Energy Supply Obligations—The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

	December 31,
Energy Supply Obligations consist of the following: (millions)	2013		2012
Current:
Exchange Gas Obligation	$	9.8	$	8.7
Renewable Energy Portfolio Standards		3.7		4.2
Power Supply Contract Divestitures		0.9		0.9
Total Energy Supply Obligations—Current	$	14.4	$	13.8
Long-Term:
Power Supply Contract Divestitures	$	2.5	$	3.3
Total Energy Supply Obligations	$	16.9	$	17.1

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 a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker rate mechanism.

Power Supply Contract Divestitures—As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity 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 on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion).

Massachusetts Green Communities Act—In compliance with the Massachusetts Green Communities Act, discussed below in Note 8, Commitments and Contingencies, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The facility associated with one of these contracts has been constructed and is operating. The other contracts are pending approval by the MDPU as well as subsequent facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Retirement Benefit Obligations

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 an unfunded 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

Off-Balance Sheet Arrangements—As of December 31, 2013, 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

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, 2013, 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

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, 2013, 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

Recently Issued Pronouncements—In December 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” The amendments in this ASU require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The Company adopted ASU 2011-11 and it did not have any impact on the Company’s Consolidated Financial Statements.

Subsequent Events

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 impacted its Consolidated Financial Statements.

Reclassifications

Reclassifications—Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. Most significant has been the reclassification of certain regulatory tracker mechanisms from Accrued Revenue and Other Current Liabilities to Regulatory Liabilities, the reclassification of exchange gas amounts from Gas Inventory to Exchange Gas Receivable on the Company’s Consolidated Balance Sheets, as discussed above in Regulatory Accounting and Exchange Gas Receivable, respectively. Also, energy efficiency program expenses, which were previously presented as Conservation & Load Management on the Company’s Consolidated Statements of Earnings are now included in Cost of Gas Sales and Cost of Electric Sales.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jan. 24, 2014	Jun. 30, 2013
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Trading Symbol	UTL
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	0000755001
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		13,842,877
Entity Public Float			$ 392,955,494

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of December 31, 2013 and 2012.

Accrued Revenue (millions)	December 31,
	2013		2012
Regulatory Assets—Current	$	43.6	$	51.9
Unbilled Revenues		13.0		11.5
Total Accrued Revenue	$	56.6	$	63.4

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of December 31, 2013 and 2012.

Exchange Gas Receivable (millions)	December 31,
	2013		2012
Northern Utilities	$	9.8	$	8.7
Fitchburg		1.0		0.7
Total Exchange Gas Receivable	$	10.8	$	9.4

Components of Gas Inventory

The following table shows the components of Gas Inventory as of December 31, 2013 and 2012.

Gas Inventory (millions)	December 31,
	2013		2012
Natural Gas	$	0.8	$	0.6
Propane		0.3		0.4
Liquefied Natural Gas & Other		0.1		0.1
Total Gas Inventory	$	1.2	$	1.1

Regulatory Assets

Regulatory Assets consist of the following (millions)	December 31,
	2013		2012
Energy Supply & Other Regulatory Tracker Mechanisms	$	32.5	$	41.0
Deferred Restructuring Costs		9.3		20.1
Retirement Benefits		42.6		62.5
Income Taxes		11.9		10.2
Environmental		16.1		16.8
Deferred Storm Charges		25.6		27.8
Other		5.7		8.1
Total Regulatory Assets	$	143.7	$	186.5
Less: Current Portion of Regulatory Assets(1)		43.6		51.9
Regulatory Assets—noncurrent	$	100.1	$	134.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets.

Regulatory Liabilities

Regulatory Liabilities consist of the following (millions)	December 31,
	2013		2012
Regulatory Tracker Mechanisms	$	9.7	$	6.8
Total Regulatory Liabilities	$	9.7	$	6.8

Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets

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

		Fair Value
Description	Balance Sheet Location	December 31, 2013		December 31, 2012
Derivative Assets
Natural Gas Futures Contracts	Prepayments and Other	$	0.1	$	—
Natural Gas Futures Contracts	Other Noncurrent Assets		0.1		—
Total Derivative Assets		$	0.2	$	—
Derivative Liabilities
Natural Gas Futures Contracts	Other Current Liabilities	$	—	$	0.7
Natural Gas Futures Contracts	Other Noncurrent Liabilities		—		—
Total Derivative Liabilities		$	—	$	0.7

Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Purchased Gas

	Twelve Months Ended December 31,
	2013		2012
Amount of Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	0.3	$	1.0
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings(1):
Purchased Gas	$	1.2	$	2.6

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

Components of Energy Supply Obligations

	December 31,
Energy Supply Obligations consist of the following: (millions)	2013		2012
Current:
Exchange Gas Obligation	$	9.8	$	8.7
Renewable Energy Portfolio Standards		3.7		4.2
Power Supply Contract Divestitures		0.9		0.9
Total Energy Supply Obligations—Current	$	14.4	$	13.8
Long-Term:
Power Supply Contract Divestitures	$	2.5	$	3.3
Total Energy Supply Obligations	$	16.9	$	17.1

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Activities:
Net Income	$ 21.6	$ 18.2	$ 16.4
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	37.7	35.1	29.3
Deferred Taxes Provision	12.3	10.8	8.7
Changes in Working Capital Items:
Accounts Receivable	(4.5)	(2.6)	(7.4)
Accrued Revenue	6.8	(0.7)	(7.7)
Regulatory Liabilities	2.9	(4.4)	5.0
Taxes Refundable / Payable	(0.5)	(0.3)	8.5
Exchange Gas Receivable	(1.4)	4.1	(4.3)
Accounts Payable	5.4	5.4
Other Changes in Working Capital Items	(2.9)	(0.4)	(1.3)
Deferred Regulatory and Other Charges	15.0	5.4	1.0
Other, net	3.9	(3.9)	(2.3)
Cash Provided by Operating Activities	96.3	66.7	45.9
Investing Activities:
Property, Plant and Equipment Additions	(89.5)	(68.5)	(57.1)
Cash (Used In) Investing Activities	(89.5)	(68.5)	(57.1)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net	10.8	(38.5)	21.1
Repayment of Long-Term Debt	(0.5)	(0.5)	(0.5)
Net Increase (Decrease) in Gas Inventory Financing	1.2	(3.8)	4.6
Dividends Paid	(19.1)	(17.2)	(15.2)
Retirement of Preferred Stock		(1.8)
Proceeds from Issuance of Common Stock	1.1	66.8	1.0
Other, net	(0.7)	(0.9)	(1.2)
Cash (Used In) Provided by Financing Activities	(7.2)	4.1	9.8
Net Increase (Decrease) in Cash	(0.4)	2.3	(1.4)
Cash at Beginning of Year	9.8	7.5	8.9
Cash at End of Year	9.4	9.8	7.5
Supplemental Information:
Interest Paid	20.8	21.2	21.2
Income Taxes Paid (Refunded)	0.8	0.7	(7.3)
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$ 0.7	$ 1.9	$ 2.6

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Equity

12 Months Ended

Dec. 31, 2013

Equity

Note 6: Equity

The Company has common stock outstanding and Unitil Energy 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”. On April 21, 2011, the Company’s shareholders approved an increase in the authorized shares of the Company’s common stock. Shareholders approved an amendment to the Company’s Articles of Incorporation to increase the authorized number of shares of the Company’s common stock, from 16,000,000 shares to 25,000,000 shares in the aggregate. The Company had 13,841,400 and 13,780,601 shares of common stock outstanding at December 31, 2013 and December 31, 2012, respectively.

Unitil Corporation Common Stock Offering—On May 16, 2012, the Company issued and sold 2,760,000 shares of its common stock at a price of $25.25 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering were approximately $65.7 million and were used to make equity capital contributions to the Company’s regulated utility subsidiaries, repay short-term debt and for general corporate purposes.

Dividend Reinvestment and Stock Purchase Plan—During 2013, the Company sold 39,559 shares of its common stock, at an average price of $29.01 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.1 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 2012 and 2011, the Company raised $1.1 million and $1.0 million, respectively, through the issuance of 41,752 and 39,473 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 March 28, 2013, 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 2013, 2012 and 2011, the Company repurchased 2,969, 6,368 and 8,765 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, $0.2 million and $0.2 million in 2013, 2012 and 2011, respectively.

During 2013, 2012 and 2011, 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. Awards may be grossed up to offset the participant’s tax obligations in connection with the 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 2011 – 2013 in conjunction with the Stock Plan are presented in the following table:

Issuance Date	Shares	Aggregate Market Value (millions)
2/9/11	24,330	$0.6
2/3/12	25,600	$0.7
2/4/13	21,240	$0.6

There were 53,480 and 53,932 non-vested shares under the Stock Plan as of December 31, 2013 and 2012, respectively. The weighted average grant date fair value of these shares was $25.99 per share and $24.67 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 $0.7 million, $1.3 million and $0.7 million in 2013, 2012 and 2011, respectively. At December 31, 2013, there was approximately $0.7 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.4 years. There were no restricted shares forfeited or cancelled under the Stock Plan during 2013.

Restricted Stock Units

Restricted Stock Units 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. There were no Restricted Stock Units issued in conjunction with the Stock Plan during 2011.

The equity portion of Restricted Stock Units activity during 2013 and 2012 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	2013				2012
	Units		Weighted Average Stock Price		Units		Weighted Average Stock Price
Beginning Restricted Stock Units		3,883	$	27.39		—
Restricted Stock Units Granted		10,710	$	29.43		3,829	$	27.43
Dividend Equivalents Earned		310	$	29.47		54	$	24.62
Restricted Stock Units Settled		—				—
Ending Restricted Stock Units		14,903	$	28.90		3,883	$	27.39

Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2013 and 2012 is $0.2 million and less than $0.1 million, respectively, representing the fair value of liabilities associated with the portion of fully vested Restricted Stock Units that will be settled in cash.

Preferred Stock

Unitil Energy, has an aggregate of $0.2 million of 6.00% Series Non-Redeemable, Non-Cumulative Preferred Stock outstanding at December 31, 2013.

On December 1, 2012, Fitchburg redeemed and retired the two outstanding issues of its Redeemable, Cumulative Preferred Stock. The 8.00% Series was redeemed at par (aggregate par value of $1.0 million). The 5.125% Series was redeemed at par plus a premium of 1.28% (aggregate value of $0.8 million). Fitchburg used operating cash to effect this transaction.

Fitchburg was required to offer to redeem annually a given number of shares of each series of its Redeemable, Cumulative Preferred Stock and to purchase such shares that were tendered by holders of the respective stock. In addition, Fitchburg had the option to redeem the Redeemable, Cumulative Preferred Stock at a given redemption price, plus accrued dividends.

The aggregate purchases of Redeemable, Cumulative Preferred Stock during 2013, 2012 and 2011 related to the annual redemption offer were $0, $8,000 and $8,600, respectively.

Earnings Per Share

The following table reconciles basic and diluted earnings per share.

(Millions except shares and per share data)	2013		2012		2011
Earnings Available to Common Shareholders	$	21.6	$	18.1	$	16.3
Weighted Average Common Shares Outstanding—Basic (000’s)		13,773		12,669		10,880
Plus: Diluted Effect of Incremental Shares (000’s)		2		3		3
Weighted Average Common Shares Outstanding—Diluted (000’s)		13,775		12,672		10,883
Earnings per Share—Basic and Diluted	$	1.57	$	1.43	$	1.50

For 2013, 2012 and 2011, respectively, 4,481, 24,325 and 1,642 weighted average non-vested restricted shares were not included in the above computation because the effect would have been antidilutive.

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Debt and Financing Arrangements

12 Months Ended

Dec. 31, 2013

Debt and Financing Arrangements

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 Unitil Energy and Fitchburg 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 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.

At December 31, 2013, there were no restrictions on Unitil’s Retained Earnings for the payment of common dividends. Unitil Energy, Fitchburg, Northern Utilities and Granite State pay dividends to their sole shareholder, Unitil Corporation, and these dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders.

Debt Repayment—The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $541,938, $500,405, and $462,055 in 2013, 2012, and 2011, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2013 is: 2014 – $2,486,919; 2015 – $4,035,633; 2016 – $17,421,724; 2017 – $17,160,985 and 2018 – $30,133,332, respectively.

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 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,
	2013		2012
Estimated Fair Value of Long- Term Debt	$	327.3	$	349.7

Details on long-term debt at December 31, 2013 and 2012 are shown below:

Long-Term Debt (millions)	December 31,
	2013		2012
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0
Unitil Energy First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0
8.49% Series, Due October 14, 2024		15.0		15.0
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		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0
Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		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
Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0
Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		2.3		2.8
Total Long-Term Debt		287.3		287.8
Less: Current Portion		2.5		0.5
Total Long-Term Debt, Less Current Portion	$	284.8	$	287.3

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.

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)
	2013			2012			2011
Interest Expense
Long-term Debt	$	20.2		$	20.3		$	20.3
Short-term Debt		1.2			1.5			1.7
Regulatory Liabilities		0.6			0.5			—
Subtotal Interest Expense		22.0			22.3			22.0
Interest Income
Regulatory Assets		(2.3	)		(3.4	)		(1.1	)
AFUDC(1) and Other		(0.9	)		(0.8	)		(0.5	)
Subtotal Interest Income		(3.2	)		(4.2	)		(1.6	)
Total Interest Expense, net	$	18.8		$	18.1		$	20.4

⁽¹⁾ AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 and provides for a new 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 plus 1.375%. 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 following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2013 and December 31, 2012:

Revolving Credit Facility (millions)
	December 31,
	2013		2012
Limit	$	120.0	$	60.0
Outstanding	$	60.2	$	49.4
Available	$	59.8	$	10.6

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, 2013, 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%, 2.0%, and 2.2% during 2013, 2012, and 2011, respectively.

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 $12.5 million and $10.7 million of natural gas storage inventory at December 31, 2013 and 2012, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2013, which was payable in January 2014, is $2.7 million and recorded in Accounts Payable at December 31, 2013. The amount of natural gas inventory released in December 2012, which was payable in January 2013, is $2.1 million and recorded in Accounts Payable at December 31, 2012.

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, 2013, 2012 and 2011 amounted to $1.2 million, $1.3 million and $1.4 million respectively.

The following is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2013:

Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2014	$	1,244	$	390
2015		1,114		174
2016		926		40
2017		647		—
2018		294		—
2019 – 2023		15		—
Total Payments	$	4,240	$	604

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, 2013, there were approximately $19.1 million of guarantees outstanding and the longest term guarantee extends through October 2014.

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, 2013, the principal amount outstanding for the 8% Unitil Realty note was $2.3 million, and the principal amount outstanding for the 7.15% Granite State note was $10.0 million.

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Equity (Tables)

12 Months Ended

Dec. 31, 2013

Restricted Shares Issued in Conjunction with Stock Plan

Restricted Shares issued for 2011 – 2013 in conjunction with the Stock Plan are presented in the following table:

Issuance Date	Shares	Aggregate Market Value (millions)
2/9/11	24,330	$0.6
2/3/12	25,600	$0.7
2/4/13	21,240	$0.6

Restricted Stock Units Issued

The equity portion of Restricted Stock Units activity during 2013 and 2012 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	2013				2012
	Units		Weighted Average Stock Price		Units		Weighted Average Stock Price
Beginning Restricted Stock Units		3,883	$	27.39		—
Restricted Stock Units Granted		10,710	$	29.43		3,829	$	27.43
Dividend Equivalents Earned		310	$	29.47		54	$	24.62
Restricted Stock Units Settled		—				—
Ending Restricted Stock Units		14,903	$	28.90		3,883	$	27.39

Reconciliation of Basic and Diluted Earnings Per Share

The following table reconciles basic and diluted earnings per share.

(Millions except shares and per share data)	2013		2012		2011
Earnings Available to Common Shareholders	$	21.6	$	18.1	$	16.3
Weighted Average Common Shares Outstanding—Basic (000’s)		13,773		12,669		10,880
Plus: Diluted Effect of Incremental Shares (000’s)		2		3		3
Weighted Average Common Shares Outstanding—Diluted (000’s)		13,775		12,672		10,883
Earnings per Share—Basic and Diluted	$	1.57	$	1.43	$	1.50

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Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information

	Three Months Ended
	March 31,				June 30,						September 30,				December 31,
	2013		2012		2013			2012			2013		2012		2013		2012
Total Operating Revenues	$	118.2	$	114.2	$	66.4		$	68.8		$	72.5	$	71.3	$	109.8	$	98.8
Operating Income	$	21.9	$	19.3	$	4.5		$	4.3		$	5.6	$	5.0	$	21.5	$	18.9
Net Income (Loss) Applicable to Common	$	10.8	$	9.0	$	(0.1	)	$	(0.4	)	$	0.6	$	0.5	$	10.3	$	9.0
	Per Share Data:
Earnings Per Common Share	$	0.79	$	0.83	$	(0.01	)	$	(0.03	)	$	0.04	$	0.03	$	0.75	$	0.66
Dividends Paid Per Common Share	$	0.345	$	0.345	$	0.345		$	0.345		$	0.345	$	0.345	$	0.345	$	0.345

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes

Note 9: Income Taxes

Provisions for Federal and State Income Taxes in the accompanying consolidated statements of earnings for the years ended December 31, 2013, 2012 and 2011 are shown in the table below:

	($000’s)
	2013			2012			2011
Current Federal Tax Provision (Benefit)
Current Benefit of Operating Loss Carrybacks	$	—		$	—		$	—
Total Current Federal Tax Provision (Benefit)		—			—			—
Deferred Federal Tax Provision (Benefit)
Utility Plant Differences		28,907			6,019			13,002
Net Operating Loss Carryforwards		(8,053	)		2,835			(4,844	)
Regulatory Assets and Liabilities		(11,483	)		472			513
Other, net		681			(241	)		(695	)
Total Deferred Federal Tax Provision (Benefit)		10,052			9,085			7,976
Total Federal Tax Provision		10,052			9,085			7,976
State
Current		386			132			1,358
Deferred		2,214			1,759			691
Total State Tax Provision		2,600			1,891			2,049
Total Provision for Federal and State Income Taxes	$	12,652		$	10,976		$	10,025

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:

	2013			2012			2011
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, Net		5			5			5
Utility Plant Differences		(2	)		(2	)		(1	)
Other, Net		—			1			—
Effective Income Tax Rate		37	%		38	%		38	%

Temporary differences which gave rise to current deferred tax assets and liabilities in 2013 and 2012, are shown below:

Current Deferred Income Taxes (000’s)	2013		2012
Accrued Revenue, Current Portion	$	6,583	$	13,568
Other, net		108		(168	)
Total Current Deferred Income Tax Liabilities	$	6,691	$	13,400

Temporary differences which gave rise to noncurrent deferred tax assets and liabilities in 2013 and 2012, are shown below:

Noncurrent Deferred Income Taxes (000’s)	2013			2012
Utility Plant Differences	$	102,479		$	66,907
Net Operating Loss Carryforwards		(17,403	)		(8,521	)
AMT Tax Credit Carryforwards		(1,538	)		(1,538	)
Regulatory Assets & Liabilities		17,174			17,872
Retirement Benefit Obligations		(28,287	)		(38,644	)
Other, net		754			2,606
Total Noncurrent Deferred Income Tax Liabilities	$	73,179		$	38,682

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 which gave rise to the revision become known.

The Company filed its tax returns for the year ended December 31, 2012 with the Internal Revenue Service (IRS) in September 2013 and generated federal net operating loss (NOL) carryforward assets of $6.6 million principally due to tax repair expensing and bonus depreciation. As of December 31, 2013, the Company had recorded cumulative federal and state NOL carryforward assets of $17.4 million to offset against taxes payable in future periods. If unused, the Company’s state NOL carryforward assets will begin to expire in 2019 and the federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2013, the Company had $1.5 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

In the third quarter of 2013, the State of Massachusetts eliminated the classification of Public Service Corporation for utilities and now all public service entities, including utilities, will be taxed at the Massachusetts 8% corporate rate effective tax years beginning after January 1, 2014. Additionally, corporations in Massachusetts will now be able to carryforward NOLs created after January 1, 2014.

The Company evaluated its tax positions at December 31, 2013 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, 2010; December 31, 2011; and December 31, 2012.

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Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Rate of Compensation Increase	3.00%	3.00%	3.50%
Expected Long-term rate of return on plan assets	8.50%
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.00%	4.60%	5.35%
Rate of Compensation Increase	3.00%	3.00%	3.50%
Expected Long-term rate of return on plan assets	8.50%	8.50%	8.50%
Health Care Cost Trend Rate Assumed for Next Year	8.00%	6.50%	7.00%
Ultimate Health Care Cost Trend Rate	4.00%	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	2017	2017	2017
Effect of 1% Increase in Health Care Cost Trend Rate	$ 1,169	$ 981	$ 909
Effect of 1% Decrease in Health Care Cost Trend Rate	(895)	(756)	(705)
Benefit Obligation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.80%	4.00%	4.60%
Rate of Compensation Increase	3.00%	3.00%	3.00%
Health Care Cost Trend Rate Assumed for Next Year	8.00%	8.00%	6.50%
Ultimate Health Care Cost Trend Rate	4.00%	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	2018	2017	2017
Effect of 1% Increase in Health Care Cost Trend Rate	9,957	11,808	9,109
Effect of 1% Decrease in Health Care Cost Trend Rate	$ (7,942)	$ (9,291)	$ (7,217)

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Energy Supply

12 Months Ended

Dec. 31, 2013

Energy Supply

Note 7: Energy Supply

Natural Gas Supply

Unitil 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’ commercial & industrial (C&I) customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors, and third-party supply is prevalent among Northern Utilities’ larger C&I customers. Most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. Fitchburg’s residential and C&I business customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors. Many large and some medium C&I customers purchase their supplies 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. The approved costs associated with the acquisition of such wholesale natural gas supplies for 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 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), to truck supplies to storage facilities within Northern Utilities’ service territory.

Northern Utilities has available under firm contract 100,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 3.4 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 of one year or less, as well as from producers and marketers on the spot market. Fitchburg arranges for gas delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, or in the case of LNG or liquefied propane gas (LPG), to truck supplies to storage facilities within Fitchburg’s service territory.

Fitchburg has available under firm contract 14,057 MMbtu per day of year-round and seasonal transportation and 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

The restructuring of the electric utility industry in New Hampshire required the divestiture of Unitil’s power supply arrangements and the procurement of replacement supplies, which provided the flexibility for migration of customers to and from utility energy service. Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the ISO-NE markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s customers.

As a result of restructuring of the electric utility industry in Massachusetts and New Hampshire, Unitil’s customers in both New Hampshire and Massachusetts have the opportunity to purchase their electric supply from competitive third-party energy suppliers. As of December 2013, 69% of Unitil’s largest New Hampshire customers, representing 23% of total New Hampshire electric energy sales, and 78% of Unitil’s largest Massachusetts customers, representing 31% of total Massachusetts electric energy sales, are purchasing their electric power supply in the competitive market. However, most residential and small commercial customers continue to purchase their electric supply through Unitil’s distribution utilities under regulated energy rates and tariffs. We believe that the concentration of the competitive retail market on higher use customers has been a common experience throughout the New England electricity market.

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 with various wholesale suppliers.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. On July 31, 2012, the NHPUC approved Unitil Energy’s request to modify its Default Service solicitation to a process where 100% of the Default Service requirements are acquired for six months. Unitil Energy completed the transition to this procurement strategy in late 2013. Currently, Unitil Energy Default Service power supply contracts for small, medium and large customers are acquired every six months, are 12 months in duration and provide 100% of the supply requirements.

Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service energy supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential, 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 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 in the Commonwealth, and the MDPU’s regulations implementing the legislation. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU approved cost recovery mechanism.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

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 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. As a result of the restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most of Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers have the opportunity 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.

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. The remaining balance of these assets, to be recovered principally over the next year, is $12.7 million as of December 31, 2013 including $10.2 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet. Unitil’s distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Northern Utilities—Base Rates—Maine—On December 27, 2013, the MPUC approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine operations, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed to implement a Targeted Infrastructure Replacement Adjustment (TIRA) to provide for annual adjustments to distribution base rates to recover costs associated with the Company’s investments in targeted operational and safety-related infrastructure replacement and upgrade projects. The TIRA will have an initial term of four years, and covers expenditures in each of the Calendar Years 2013, 2014, 2015, and 2016. The settlement agreement also provides for Earning Sharing where Northern would be allowed to retain all earnings up to a return of 10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement continues and revises the service quality plan (SQP) that Northern has been operating under since 2004 and established in Docket No. 2002-140. The revised SQP consists of seven metrics with an appurtenant administrative penalty for failure to meet any of the seven metrics. The settlement agreement further provides that Northern will be subject to a maximum annual penalty of $500,000 if it fails to meet any of the baseline performance targets under the revised SQP.

Northern Utilities—Base Rates—New Hampshire—In April 2013, Northern Utilities’ New Hampshire operations filed a rate case with the NHPUC requesting approval to increase its natural gas distribution base rates by $5.2 million in gas distribution base revenue or approximately 9.4 percent over test year operating revenue. The filing included a proposed multi-year rate plan that included cost tracking mechanisms to recover future capital costs associated with Northern Utilities’ infrastructure replacements and safety and reliability improvements to the natural gas distribution system. Northern Utilities has been authorized to implement temporary rates to collect a $2.5 million increase (annualized) in gas distribution revenue, effective July 1, 2013. The Company is currently in settlement discussions with the NHPUC and expects a final rate order from the NHPUC in the first half of 2014. Once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were established, July 1, 2013.

Unitil Energy—Base Rates—Unitil Energy’s second step increase of $2.8 million went into effect on May 1, 2013, which included rate increases to recover capital improvements, increased spending for its vegetation management and reliability enhancement programs and an increase in its storm reserve fund. On April 26, 2011, the NHPUC approved a rate settlement with a permanent increase of $5.2 million in annual revenue effective July 1, 2010, and an additional increase of $5.0 million in annual revenue effective May 1, 2011. The settlement extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with step increases in annual revenue on May 1, 2012, May 1, 2013 and May 1, 2014, to support Unitil Energy’s continued capital improvements to its distribution system. Unitil Energy’s first step increase was approved as filed, effective May 1, 2012.

Granite State—Base Rates—In June 2013, Granite State submitted to the FERC its latest incremental annual rate adjustment, in the amount of $0.4 million, with rates effective August 1, 2013. The FERC approved the increase on July 30, 2013. Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file a limited Section 4 rate case that includes incremental annual rate adjustments to recover the revenue requirements for certain specified future capital cost additions to gas transmission plant projects.

Fitchburg—Electric Base Rates Filed—In July 2013, Fitchburg filed a rate case with the MDPU requesting approval to increase its electric distribution rates. The Company requested an increase of $6.7 million in electric base revenue or approximately 11.5 percent over test year operating revenue. Included in the amount of this annual increase is approximately $2.1 million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to three severe storms, Tropical Storm Irene, the October 2011 snowstorm and Superstorm Sandy. The filing includes a proposed modified revenue decoupling mechanism by means of an annual revenue adjustment mechanism by either a capital cost tracker mechanism or a multi-year rate plan featuring a revenue cap index. The filing also includes a proposal to establish a major storm reserve fund to address the costs of future major storms by collecting $2.8 million per year through a reconciling storm recovery adjustment factor beginning January 1, 2015. The rate case filing is subject to regulatory review with hearings scheduled throughout January 2014 and approval with final rate orders expected in the second quarter of 2014.

Major Storms—Fitchburg and Unitil Energy

Superstorm Sandy – On October 29-30, 2012, a severe storm struck the eastern seaboard of the United States, causing extensive damage to electric facilities and loss of service to significant numbers of customers of several utilities. Fitchburg and Unitil Energy incurred approximately $1.1 million and $2.7 million, respectively, in costs for the repair and replacement of electric distribution systems damaged during the storm, including $0.3 million and $0.4 million related to capital construction for Fitchburg and Unitil Energy, respectively. The amount and timing of the cost recovery of these storm restoration expenditures for Fitchburg will be determined in its rate case. The cost recovery for Unitil Energy has been approved as discussed below. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations.

Fitchburg—Storm Cost Deferral—On May 1, 2012 the MDPU approved Fitchburg’s request to defer $4.3 million of storm costs associated with two severe storms which occurred in 2011, and Fitchburg is seeking recovery of these costs in the electric rate case it filed in July 2013.

Unitil Energy—2012 Storm Costs—On April 25, 2013, the NHPUC approved the recovery of $2.3 million of costs to repair damage to Unitil Energy’s electrical system resulting from Superstorm Sandy over a five-year period, with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, applied to the uncollected balance through the recovery period.

Fitchburg—Electric Operations—On November 15, 2013, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing also includes the reconciliation of costs and revenues for a number of other surcharges and cost factors which are subject to review and approval by the MDPU. Many of the surcharges and cost factors were redesigned based on cost-based rate design in compliance with a MDPU order in its Investigation into Cost-Based Rate Design for Reconciliation Factors, which resulted from the “Act Relative to Competitively Priced Electricity in the Commonwealth”, signed into law by the Governor of Massachusetts on August 3, 2012. All of the rates were approved effective January 1, 2014 for billing purposes, subject to reconciliation, pending investigation by the MDPU. This matter remains pending.

Fitchburg—Service Quality—On March 1, 2013, Fitchburg submitted its 2012 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. On March 29, 2013, the MDPU issued its order approving the 2011 Service Quality Report for Fitchburg’s gas division. The 2011-2012 Service Quality reports for Fitchburg’s electric division remain pending.

On December 11, 2012, the MDPU opened an investigation into the service quality provided by the gas and electric distribution companies in Massachusetts and the Service Quality guidelines currently in effect. The MDPU investigation will review existing and potential new reliability, safety, and customer satisfaction metrics; potential penalties for downed wire response; potential clean energy metrics; penalty provisions, including penalty offsets for superior performance in other metrics for poor performance on a different metric; and review of historic data for use in establishing service quality benchmarks. Fitchburg has been an active participant in this docket, which remains pending.

Fitchburg—Other—On February 5, 2013, there was a natural gas explosion in the city of Fitchburg, Massachusetts in an area served by Fitchburg’s gas division resulting in property damage to a number of commercial and residential properties. The MDPU, pursuant to its authority under state and federal law, has commenced an investigation of the incident, with which Fitchburg is cooperating. The Company does not believe this incident or investigation will have a material adverse impact on the Company’s financial condition or results of operations.

On February 11, 2009, the Massachusetts Supreme Judicial Court (SJC) issued its decision in the Attorney General’s (AG) appeal of the MDPU orders relating to Fitchburg’s recovery of bad debt expense. The SJC agreed with the AG that the MDPU was required to hold hearings regarding changes in Fitchburg’s tariff and rates, and on that basis vacated the MDPU orders. The SJC, however, declined to rule on an appropriate remedy, and remanded the cases back to the MDPU for consideration of that issue. In the Company’s August 1, 2011 rate decision, the MDPU held that the approval of dollar for dollar collection of supply-related bad debt in the Company’s rate cases in 2006 (gas) and 2007 (electric) satisfied the requirement for a hearing ordered by the SJC. The MDPU has opened a docket to address the amounts collected by Fitchburg between the time the MDPU first approved dollar for dollar collection of the Company’s bad debt, and the rate decisions in 2006 and 2007. Briefs were filed in June 2013. This matter remains pending before the MDPU.

On July 2, 2008, the Governor of Massachusetts signed into law “The Green Communities Act” (the GC Act), an energy policy statute designed to substantially increase energy efficiency and the development of renewable energy resources in Massachusetts. The GC Act provides for utilities to recover in rates the incremental costs associated with its various mandated programs. Several regulatory proceedings have been initiated to implement various provisions of the GC Act, including provisions for each distribution company to file enhanced three-year energy efficiency investment plans, plans to establish smart grid pilot programs, proposals to purchase long-term contracts for renewable energy, special tariffs to allow the net metering of customer-owned renewable generation, and terms and conditions for purchasing supplier receivables. Fitchburg’s first two three-year energy efficiency investment plans, plans to establish smart grid pilot programs, net metering tariffs and proposals to purchase long-term contracts for renewable energy have been approved by the MDPU. Terms and conditions for purchasing supplier receivables are under review in a separately designated docket.

On August 3, 2012, the Governor of Massachusetts signed into law “An Act Relative to Competitively Priced Electricity in the Commonwealth”, which both increases electric distribution companies’ obligations to purchase renewable energy resources and the availability of net metering. This act also includes changes to the MDPU’s ratemaking procedures and authority for reviewing mergers and acquisitions for electric and gas distribution companies. With these changes, electric distribution companies are required to file rate schedules every five years, and gas distribution companies every ten years. The MDPU also opened a proceeding, as mandated by the act, to establish a cost-based rate design for costs that are currently recovered from distribution customers through a reconciling factor. On December 17, 2013, the MDPU issued an order establishing the new rate design allocation methodologies. Fitchburg has participated with the other electric utilities and entered into long-term renewable contracts for its pro-rata share of renewable energy projects. The facility associated with one of these contracts has been constructed and is operating. The other contracts are pending approval by the MDPU as well as subsequent facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

On August 6, 2012, the Governor of Massachusetts also signed into law “An Act Relative to the Emergency Response of Public Utilities”, which establishes a new storm trust fund and requires that penalties levied by the MDPU for violations of its emergency preparedness rules be credited to customers.

On December 23, 2013 the MDPU issued two orders related to Grid Modernization. The MDPU opened an investigation on its own motion into Modernization of the Electric Grid and, in a separate but related order, opened an investigation into Electric Vehicles and Electric Vehicle Charging. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices” and all related objectives. It sets forth a straw proposal which would require each electric distribution company to submit a ten-year strategic grid modernization plan (GMP) within six months of a final Order. As part of the GMP each company must also include a comprehensive advanced metering plan (CAMP), and each company is required to achieve advanced metering functionality. The filing of a GMP will be 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. A cost recovery mechanism is proposed only for investments in advanced metering. The MDPU also proposes to address in separate, upcoming proceedings (1) time varying rates, (2) cybersecurity, privacy, and access to meter data, and (3) electric vehicles (EVs). In the Electric Vehicle Order, the MDPU seeks to establish policies and regulations that will help facilitate and accommodate the widespread adoption of EVs. Among other objectives, the proceeding looks to evaluate (1) EV charging and its impact on the electric distribution system, (2) electric distribution company involvement in EV charging, (3) residential metering practices and rates for EVs, and (4) consumer protection issues. Both of these matters remain pending.

Unitil Corporation—FERC Audit—On November 3, 2011, the FERC commenced an audit of Unitil Corporation, including its associated service company and its electric and natural gas distribution companies. Among other requirements, the audit evaluated the Company’s compliance with: i) cross-subsidization restrictions on affiliate transactions; ii) regulations under the Energy Policy Act of 2005; and the iii) uniform system of accounts for centralized service companies. The final audit report was issued on February 28, 2013 and the Company submitted its plan to address the audit findings and implement the audit recommendations on March 29, 2013. The Company submitted its quarterly progress update on the implementation of the audit recommendations on April 30, 2013. On June 5, 2013 the FERC advised the Company that the audit is complete; no further action is required by the Company. The audit findings did not have an 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 the Company’s financial position.

In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (Fitchburg), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman 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 Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit would now proceed with only the twelve named plaintiffs seeking damages; however, the plaintiffs have appealed this decision to the Massachusetts Supreme Judicial Court (the “SJC”). The SJC has accepted the matter for review. The Town of Lunenburg has also filed a separate action in Massachusetts Worcester County Superior Court arising out of the December 2008 ice storm. The parties to this action have agreed to put this matter on hold pending the decision of the Supreme Judicial Court in Bellermann. The Company continues to believe these suits are without merit and will continue to defend itself vigorously.

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 believes it is in material compliance with applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2013, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you 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.

Northern Utilities Manufactured Gas Plant Sites—Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites that were operated from the mid-1800s through the mid-1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. This program has also documented the presence of MGP sites in Lewiston and Portland, Maine and a former MGP disposal site in Scarborough, Maine. Northern Utilities has worked with the environmental regulatory agencies in both New Hampshire and Maine to address environmental concerns with these sites.

Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, Lewiston and Scarborough sites. The site in Portland has been investigated and remedial activities are ongoing with the most recent phase completed in December 2013. Although Northern Utilities recently finalized a long-term lease on the Portland property, the State of Maine has announced its intention to acquire the site in the short-term for the expansion of the adjacent marine terminal. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs pending either State acquisition or until all remedial activities are completed.

The NHPUC and MPUC have approved the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over a seven-year amortization period. For Northern Utilities’ Maine division, the MPUC authorized the recovery of environmental remediation costs over a rolling five-year amortization schedule.

Included in Environmental Obligations on the Company’s Consolidated Balance Sheet at December 31, 2013 are accrued liabilities totaling $1.8 million associated with Northern Utilities’ environmental remediation obligations for former MGP sites. In addition to the amounts noted above, there are $1.0 million of accrued liabilities in Other Current Liabilities on the Company’s Consolidated Balance Sheet at December 31, 2013 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 is in the process of seeking regulatory approval to implement a permanent remediation solution at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts. Included in Environmental Obligations on the Company’s Consolidated Balance Sheets at December 31, 2013 are accrued liabilities totaling $12.0 million related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site. A corresponding Regulatory Asset was recorded to reflect that the recovery of this environmental remediation cost is 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, without carrying costs.

The Company’s ultimate liability for future environmental remediation costs, including MGP site costs, may vary from estimates, which may be adjusted as new information or future developments become available. 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.

The following table shows the balances and activity in the Company’s liability for Environmental Obligations for 2013 and 2012.

ENVIRONMENTAL OBLIGATIONS

(Millions)	December 31,
	2013		2012
Total Environmental Obligations—Balance at Beginning of Period	$	14.8	$	14.7
Changes in Estimates		—		0.1
Liabilities Assumed		—		—
Less: Payments / Reductions		—		—
Total Environmental Obligations—Balance at End of Period		14.8		14.8
Less: Current Portion(1)		1.0		1.0
Environmental Obligations—noncurrent—Balance at End of Period	$	13.8	$	13.8

⁽¹⁾  Reflects amounts included in Other Current Liabilities on the Company’s Consolidated Balance Sheets.

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Retirement Benefit Plans

12 Months Ended

Dec. 31, 2013

Retirement Benefit Plans

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.

• The Unitil Corporation Supplemental Executive Retirement Plan (SERP)—The SERP is an unfunded retirement plan, with participation limited to executives selected by the Board of Directors.

Effective with the acquisitions of Northern Utilities and Granite State, the Company assumed the assets and obligations of the Northern Utilities and Granite State pension plans with respect to active union employees. All other active employees of Northern Utilities and Granite State effectively became members of the Company’s Pension Plan as of the acquisitions closing date.

Certain employees of Northern Utilities qualified for participation in the Company’s PBOP Plan effective with the acquisition closing date.

The following table includes the key assumptions used in determining the Company’s benefit plan costs and obligations:

	2013			2012			2011
Used to Determine Plan costs for years ended December 31:
Discount Rate		4.00	%		4.60	%		5.35	%
Rate of Compensation Increase		3.00	%		3.00	%		3.50	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		6.50	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2017			2017			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	1,169		$	981		$	909
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(895	)	$	(756	)	$	(705	)
Used to Determine Benefit Obligations at December 31:
Discount Rate		4.80	%		4.00	%		4.60	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		8.00	%		6.50	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health care Cost Trend Rate is reached		2018			2017			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	9,957		$	11,808		$	9,109
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(7,942	)	$	(9,291	)	$	(7,217	)

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 2013, 2012 and 2011, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $431,000, $367,000 and $325,000, respectively, in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2013, 2012 and 2011 was 3.00%, 3.00% and 3.50%, based on the expected long-term increase in compensation costs for personnel covered by the plans.

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

	Pension Plan									PBOP Plan									SERP
	2013			2012			2011			2013			2012			2011			2013		2012		2011
Service Cost	$	3,573		$	3,227		$	2,941		$	2,523		$	2,066		$	1,918		$	73	$	289	$	285
Interest Cost		4,567			4,633			4,684			2,448			2,303			2,279			241		211		227
Expected Return on Plan Assets		(5,955	)		(5,390	)		(4,840	)		(722	)		(695	)		(818	)		—		—		—
Prior Service Cost Amortization		208			188			249			1,701			1,729			1,729			11		11		11
Transition Obligation Amortization		—			—			—			—			21			21			—		—		—
Actuarial Loss Amortization		4,229			3,617			3,132			786			129			—			184		64		78
Sub-total		6,622			6,275			6,166			6,736			5,553			5,129			509		575		601
Amounts Capitalized and Deferred		(2,929	)		(2,726	)		(2,590	)		(3,010	)		(2,127	)		(1,622	)		—		—		—
NPBC Recognized	$	3,693		$	3,549		$	3,576		$	3,726		$	3,426		$	3,507		$	509	$	575	$	601

The estimated amortizations related to Actuarial Loss and Prior Service Cost included in the Company’s Retirement plan costs over the next fiscal year is $3.1 million, $1.7 million and $0.1 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 2013, 2012 and 2011 before capitalization and deferral was $6.6 million, $6.3 million and $6.2 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2013, 2012 and 2011 would have been $6.6 million, $6.7 million and $5.7 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:	2013			2012			2013			2012			2013			2012
Plan Assets at Beginning of Year	$	72,411		$	59,700		$	8,301		$	7,339		$	—		$	—
Actual Return on Plan Assets		10,204			7,780			1,154			837			—			—
Employer Contributions		3,700			9,387			3,280			2,190			53			53
Participant Contributions		—			—			36			18			—			—
Acquired Plan Assets		—			—			—			—			—			—
Benefits Paid		(3,764	)		(4,456	)		(1,942	)		(2,083	)		(53	)		(53	)
Plan Assets at End of Year	$	82,551		$	72,411		$	10,829		$	8,301		$	—		$	—
Change in PBO:
PBO at Beginning of Year	$	116,492		$	102,719		$	62,092		$	50,930		$	6,207		$	4,615
Service Cost		3,573			3,227			2,523			2,066			73			289
Interest Cost		4,567			4,633			2,448			2,303			241			211
Participant Contributions		—			—			36			18			—			—
Plan Amendments		—			617			(183	)		(318	)		—			—
Benefits Paid		(3,764	)		(4,456	)		(1,942	)		(2,083	)		(53	)		(53	)
Actuarial (Gain) or Loss		(12,573	)		9,752			(8,075	)		9,176			(611	)		1,145
PBO at End of Year	$	108,295		$	116,492		$	56,899		$	62,092		$	5,857		$	6,207
Funded Status: Assets vs PBO	$	(25,744	)	$	(44,081	)	$	(46,070	)	$	(53,791	)	$	(5,857	)	$	(6,207	)

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 of $42.6 million and $62.5 million at December 31, 2013 and 2012, 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 $96.9 million and $103.4 million as of December 31, 2013 and 2012, respectively. The ABO for the SERP was $5.1 million and $4.8 million as of December 31, 2013 and 2012, respectively. For the PBOP Plan, the ABO and PBO are the same.

On August 17, 2006, the Pension Protection Act of 2006 (PPA) was signed into law. Included in the PPA were new minimum funding rules which went into effect for plan years beginning in 2008. The funding target was 100% of a plan’s liability (as determined under the PPA) with any shortfall amortized over seven years, with lower (92% – 100%) funding targets available to well-funded plans during the transition period. Due to the significant declines in the valuation of capital markets during 2008, the Worker, Retiree, and Employer Recovery Act of 2008 (Recovery Act) was signed into law on December 23, 2008. Included in the Recovery Act are temporary modifications to the minimum funding rules set forth in the PPA such that all plans, except those that were subject to deficit reduction contribution requirements in 2007, are allowed to amortize any shortfall from the lower funding targets, rather than the 100% target, for the 2008—2010 plan years. The Company’s Pension Plan was 80% funded under the requirements of the Employee Retirement Income Security Act of 1974 (ERISA) as of January 1, 2010, which resulted in a shortfall of $10.2 million. This shortfall was being amortized over seven years with annual payments of $1.7 million, beginning in 2010. The $1.7 million payment for 2011 is included in the Employer Contributions amounts shown in the table below.

On June 25, 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 (Relief Act) was signed into law. The pension relief portion of the Relief Act provides two alternative shortfall amortization periods to the seven year amortization period required under the PPA. The Company evaluated the two alternative shortfall amortization periods under the Relief Act and made the decision to continue with the seven year amortization period.

On July 6, 2012, the Moving Ahead for Progress in the 21st Century Act (MAP-21) was signed into law. MAP-21 increased the interest rates used to determine pension liability. The Company elected to apply the provisions of MAP-21 for purposes of determining pension liability for minimum funding purposes for the 2012 plan year. As part of this decision, the Company contributed $3.1 million in additional contributions in 2012 for the 2011 plan year to achieve 100% funding on the MAP-21 basis as of January 1, 2012. This eliminated the amortization payments created in prior years, discussed above. In addition, the minimum required contribution for the 2012 plan year decreased from $6.1 million to $1.0 million.

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2014 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
	2013		2012		2011		2013		2012		2011		2013		2012		2011
Employer Contributions	$	3,700	$	9,387	$	8,813	$	3,280	$	2,190	$	—	$	53	$	53	$	53
Participant Contributions	$	—	$	—	$	—	$	36	$	18	$	13	$	—	$	—	$	—
Benefit Payments	$	3,764	$	4,456	$	3,438	$	1,942	$	2,083	$	1,644	$	53	$	53	$	53

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

Estimated Future Benefit Payments
	Pension		PBOP		SERP
2014	$	4,495	$	1,914	$	384
2015		4,617		2,056		380
2016		4,742		2,129		375
2017		5,050		2,277		369
2018		5,188		2,404		364
2019 - 2023	$	31,826	$	14,496	$	1,925

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 48% in common stock equities, 37% in fixed income securities, 10% in real estate securities and 5% 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 2014			Actual Allocation at December 31,
				2013			2012			2011
Equity Funds		48	%		54	%		48	%		49	%
Debt Funds		37	%		32	%		47	%		46	%
Real Estate Fund		10	%		1	%		0	%		0	%
Asset Allocation Fund(1)		5	%		5	%		5	%		5	%
Other(2)		0	%		8	%		0	%		0	%
Total					100	%		100	%		100	%

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

⁽²⁾ Represents investments being held in cash equivalents as of December 31, 2013 pending transfer into a Real Estate Fund.

PBOP Plan	Target Allocation 2014			Actual Allocation at December 31,
				2013			2012			2011
Equity Funds		55	%		57	%		56	%		55	%
Debt Funds		45	%		43	%		44	%		45	%
Total					100	%		100	%		100	%

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.50% for 2013. 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, 2013 and 2012. 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 and are categorized in Level 3.

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2013 and 2012 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)
2013
Pension Plan Assets:
Equity Funds	$	44,201	$	44,201	$	—	$	—
Fixed Income Funds		26,276		26,276		—		—
Asset Allocation Fund		4,574		4,574		—		—
Real Estate Fund		1,125		—		—		1,125
Cash Equivalents		6,375		6,375		—		—
Total Assets	$	82,551	$	81,426	$	—	$	1,125
2012
Pension Plan Assets:
Equity Funds	$	34,742	$	34,742	$	—	$	—
Fixed Income Funds		34,251		34,251		—		—
Asset Allocation Fund		3,418		3,418		—		—
Total Assets	$	72,411	$	72,411	$	—	$	—

The following tables set forth additional disclosures of Pension Plan investments whose fair value is estimated using net asset value per share as of December 31, 2013. There were no Pension Plan investments whose fair value is estimated using net asset value per share as of December 31, 2012:

	Fair Value Estimated Using NAV Per Share
	December 31, 2013
Description	Fair Value	Unfunded Commitment	Redemption Frequency	Redemption Notice Period
SEI Core Property Collective Investment Trust Fund(1)	$1,125,000	$—	Quarterly	65 days

⁽¹⁾  The SEI Core Property Collective Investment Trust Fund, through the SEI Core Property Fund, seeks both current income and long-term capital appreciation through investing in underlying funds that acquire, manage, and dispose of commercial real estate properties.

The table below sets forth a summary of changes in the fair value of the Pension Plan’s Level 3 assets for the year ended December 31, 2013:

	Level 3 Assets
	SEI Core  Property Collective Investment Trust Fund
Balance at December 31, 2012	$	—
Purchases		1,125,000
Balance at December 31, 2013	$	1,125,000
Amount of Total Gains or Losses for the Year Attributable to the Change in Unrealized Gains or Losses Relating to Assets Still Held at December 31, 2013	$	—

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2013 and 2012 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)
2013
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	4,689	$	4,689	$	—	$	—
Index Funds		4,467		4,467
Equity Funds		1,673		1,673
Total Assets	$	10,829	$	10,829	$	—	$	—
2012
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	3,670	$	3,670	$	—	$	—
Index Funds		3,357		3,357
Equity Funds		1,274		1,274
Total Assets	$	8,301	$	8,301	$	—	$	—

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 $1,678,000, $1,387,000 and $1,190,000 for the years ended December 31, 2013, 2012, and 2011, respectively.

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Employer Contributions, Participant Contributions and Benefit Payments (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans
Defined Contribution Benefit Plans [Line Items]
Employer Contributions	$ 3,700,000	$ 9,387,000	$ 8,813,000
Benefit Payments	3,764,000	4,456,000	3,438,000
Other Postretirement Benefit Plans, Defined Benefit
Defined Contribution Benefit Plans [Line Items]
Employer Contributions	3,280,000	2,190,000
Participant Contributions	36,000	18,000	13,000
Benefit Payments	1,942,000	2,083,000	1,644,000
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Benefit Plans [Line Items]
Employer Contributions	53,000	53,000	53,000
Benefit Payments	$ 53,000	$ 53,000	$ 53,000

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Actual Investment Allocations (Detail)				12 Months Ended			12 Months Ended			12 Months Ended			12 Months Ended															12 Months Ended			12 Months Ended
	Dec. 31, 2013 Pension Plans	Dec. 31, 2012 Pension Plans	Dec. 31, 2011 Pension Plans	Dec. 31, 2013 Pension Plans Equity Funds	Dec. 31, 2012 Pension Plans Equity Funds	Dec. 31, 2011 Pension Plans Equity Funds	Dec. 31, 2013 Pension Plans Fixed Income Securities	Dec. 31, 2012 Pension Plans Fixed Income Securities	Dec. 31, 2011 Pension Plans Fixed Income Securities	Dec. 31, 2013 Pension Plans Real Estate Funds	Dec. 31, 2012 Pension Plans Real Estate Funds	Dec. 31, 2011 Pension Plans Real Estate Funds	Dec. 31, 2013 Pension Plans Equity And Debt Securities		Dec. 31, 2012 Pension Plans Equity And Debt Securities		Dec. 31, 2011 Pension Plans Equity And Debt Securities		Dec. 31, 2013 Pension Plans Other		Dec. 31, 2012 Pension Plans Other		Dec. 31, 2011 Pension Plans Other		Dec. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit	Dec. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit	Dec. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit Equity Funds	Dec. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit Equity Funds	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit Equity Funds	Dec. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit Fixed Income Securities	Dec. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit Fixed Income Securities	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit Fixed Income Securities	Dec. 31, 2014 Scenario, Forecast Other Postretirement Benefit Plans, Defined Benefit Equity Funds	Dec. 31, 2014 Scenario, Forecast Other Postretirement Benefit Plans, Defined Benefit Fixed Income Securities
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Target Allocation				48.00%			37.00%			10.00%			5.00%															55.00%			45.00%
Actual Allocation	100.00%	100.00%	100.00%	54.00%	48.00%	49.00%	32.00%	47.00%	46.00%	1.00%	0.00%	0.00%	5.00%	[1]	5.00%	[1]	5.00%	[1]	8.00%	[2]	0.00%	[2]	0.00%	[2]	100.00%	100.00%	100.00%	57.00%	56.00%	55.00%	43.00%	44.00%	45.00%	55.00%	45.00%

[1] Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

[2] Represents investments being held in cash equivalents as of December 31, 2013 pending transfer into a Real Estate Fund.

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Summary of Information on Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Service Cost	$ 3,573,000	$ 3,227,000	$ 2,941,000
Interest Cost	4,567,000	4,633,000	4,684,000
Funded Status: Assets vs PBO	(25,744,000)	(44,081,000)
Pension Plans | Change in Plan Assets
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Plan Assets at Beginning of Year	72,411,000	59,700,000
Actual Return on Plan Assets	10,204,000	7,780,000
Employer Contributions	3,700,000	9,387,000
Acquired Plan Assets
Benefits Paid	(3,764,000)	(4,456,000)
Plan Assets at End of Year	82,551,000	72,411,000
Pension Plans | Change In Projected Benefit Obligation
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
PBO at Beginning of Year	116,492,000	102,719,000
Service Cost	3,573,000	3,227,000
Interest Cost	4,567,000	4,633,000
Plan Amendments		617,000
Benefits Paid	(3,764,000)	(4,456,000)
Actuarial (Gain) or Loss	(12,573,000)	9,752,000
PBO at End of Year	108,295,000	116,492,000
Other Postretirement Benefit Plans, Defined Benefit
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Service Cost	2,523,000	2,066,000	1,918,000
Interest Cost	2,448,000	2,303,000	2,279,000
Employer Contributions	3,280,000	2,190,000
Participant Contributions	36,000	18,000	13,000
Benefits Paid	(1,942,000)	(2,083,000)	(1,644,000)
Funded Status: Assets vs PBO	(46,070,000)	(53,791,000)
Other Postretirement Benefit Plans, Defined Benefit | Change in Plan Assets
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Plan Assets at Beginning of Year	8,301,000	7,339,000
Actual Return on Plan Assets	1,154,000	837,000
Employer Contributions	3,280,000	2,190,000
Participant Contributions	36,000	18,000
Acquired Plan Assets
Benefits Paid	(1,942,000)	(2,083,000)
Plan Assets at End of Year	10,829,000	8,301,000
Other Postretirement Benefit Plans, Defined Benefit | Change In Projected Benefit Obligation
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
PBO at Beginning of Year	62,092,000	50,930,000
Service Cost	2,523,000	2,066,000
Interest Cost	2,448,000	2,303,000
Participant Contributions	36,000	18,000
Plan Amendments	(183,000)	(318,000)
Benefits Paid	(1,942,000)	(2,083,000)
Actuarial (Gain) or Loss	(8,075,000)	9,176,000
PBO at End of Year	56,899,000	62,092,000
Supplemental Employee Retirement Plans, Defined Benefit
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Service Cost	73,000	289,000	285,000
Interest Cost	241,000	211,000	227,000
Employer Contributions	53,000	53,000	53,000
Benefits Paid	(53,000)	(53,000)	(53,000)
Funded Status: Assets vs PBO	(5,857,000)	(6,207,000)
Supplemental Employee Retirement Plans, Defined Benefit | Change in Plan Assets
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Employer Contributions	53,000	53,000
Acquired Plan Assets
Benefits Paid	(53,000)	(53,000)
Supplemental Employee Retirement Plans, Defined Benefit | Change In Projected Benefit Obligation
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
PBO at Beginning of Year	6,207,000	4,615,000
Service Cost	73,000	289,000
Interest Cost	241,000	211,000
Benefits Paid	(53,000)	(53,000)
Actuarial (Gain) or Loss	(611,000)	1,145,000
PBO at End of Year	$ 5,857,000	$ 6,207,000

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Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Purchased Gas (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Natural Gas Future Contract
Regulatory Assets [Line Items]
Loss recognized in Regulatory Assets	$ 0.3		$ 1.0
Gas Purchase Costs
Regulatory Assets [Line Items]
Loss Reclassified into unaudited Consolidated Statement of Earnings	$ 1.2	[1]	$ 2.6	[1]

[1] These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

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Reconciliation of Basic and Diluted Earnings Per Share (Detail) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Earnings Available to Common Shareholders	$ 10.3	$ 0.6	$ (0.1)	$ 10.8	$ 9.0	$ 0.5	$ (0.4)	$ 9.0	$ 21.6	$ 18.1	$ 16.3
Weighted Average Common Shares Outstanding-Basic									13,772,855	12,669,309	10,880,025
Plus: Diluted Effect of Incremental Shares (000's)									2,000	3,000	3,000
Weighted Average Common Shares Outstanding-Diluted									13,775,245	12,671,609	10,882,971
Earnings per Share-Basic and Diluted	$ 0.75	$ 0.04	$ (0.01)	$ 0.79	$ 0.66	$ 0.03	$ (0.03)	$ 0.83	$ 1.57	$ 1.43	$ 1.50

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Allowance for Doubtful Accounts (Tables)

12 Months Ended

Dec. 31, 2013

Allowance for Doubtful Accounts

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2011 – 2013 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2013
Electric	$	1.1	$	2.6	$	0.2	$	2.6	$	1.3
Gas		0.7		2.0		0.2		2.7		0.2
Other		0.1		—		—		—		0.1
	$	1.9	$	4.6	$	0.4	$	5.3	$	1.6
Year Ended December 31, 2012
Electric	$	1.7	$	1.4	$	0.3	$	2.3	$	1.1
Gas		0.5		2.2		0.3		2.3		0.7
Other		0.1		—		—		—		0.1
	$	2.3	$	3.6	$	0.6	$	4.6	$	1.9
Year Ended December 31, 2011
Electric	$	1.8	$	2.1	$	0.2	$	2.4	$	1.7
Gas		0.7		2.2		0.3		2.7		0.5
Other		0.1		—		—		—		0.1
	$	2.6	$	4.3	$	0.5	$	5.1	$	2.3

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Retirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2013

Key Assumptions used in Determining Benefit Plan Costs and Obligations

The following table includes the key assumptions used in determining the Company’s benefit plan costs and obligations:

	2013			2012			2011
Used to Determine Plan costs for years ended December 31:
Discount Rate		4.00	%		4.60	%		5.35	%
Rate of Compensation Increase		3.00	%		3.00	%		3.50	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		6.50	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2017			2017			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	1,169		$	981		$	909
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(895	)	$	(756	)	$	(705	)
Used to Determine Benefit Obligations at December 31:
Discount Rate		4.80	%		4.00	%		4.60	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		8.00	%		6.50	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health care Cost Trend Rate is reached		2018			2017			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	9,957		$	11,808		$	9,109
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(7,942	)	$	(9,291	)	$	(7,217	)

Components of Retirement Plan Costs

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

	Pension Plan									PBOP Plan									SERP
	2013			2012			2011			2013			2012			2011			2013		2012		2011
Service Cost	$	3,573		$	3,227		$	2,941		$	2,523		$	2,066		$	1,918		$	73	$	289	$	285
Interest Cost		4,567			4,633			4,684			2,448			2,303			2,279			241		211		227
Expected Return on Plan Assets		(5,955	)		(5,390	)		(4,840	)		(722	)		(695	)		(818	)		—		—		—
Prior Service Cost Amortization		208			188			249			1,701			1,729			1,729			11		11		11
Transition Obligation Amortization		—			—			—			—			21			21			—		—		—
Actuarial Loss Amortization		4,229			3,617			3,132			786			129			—			184		64		78
Sub-total		6,622			6,275			6,166			6,736			5,553			5,129			509		575		601
Amounts Capitalized and Deferred		(2,929	)		(2,726	)		(2,590	)		(3,010	)		(2,127	)		(1,622	)		—		—		—
NPBC Recognized	$	3,693		$	3,549		$	3,576		$	3,726		$	3,426		$	3,507		$	509	$	575	$	601

Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status

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:	2013			2012			2013			2012			2013			2012
Plan Assets at Beginning of Year	$	72,411		$	59,700		$	8,301		$	7,339		$	—		$	—
Actual Return on Plan Assets		10,204			7,780			1,154			837			—			—
Employer Contributions		3,700			9,387			3,280			2,190			53			53
Participant Contributions		—			—			36			18			—			—
Acquired Plan Assets		—			—			—			—			—			—
Benefits Paid		(3,764	)		(4,456	)		(1,942	)		(2,083	)		(53	)		(53	)
Plan Assets at End of Year	$	82,551		$	72,411		$	10,829		$	8,301		$	—		$	—
Change in PBO:
PBO at Beginning of Year	$	116,492		$	102,719		$	62,092		$	50,930		$	6,207		$	4,615
Service Cost		3,573			3,227			2,523			2,066			73			289
Interest Cost		4,567			4,633			2,448			2,303			241			211
Participant Contributions		—			—			36			18			—			—
Plan Amendments		—			617			(183	)		(318	)		—			—
Benefits Paid		(3,764	)		(4,456	)		(1,942	)		(2,083	)		(53	)		(53	)
Actuarial (Gain) or Loss		(12,573	)		9,752			(8,075	)		9,176			(611	)		1,145
PBO at End of Year	$	108,295		$	116,492		$	56,899		$	62,092		$	5,857		$	6,207
Funded Status: Assets vs PBO	$	(25,744	)	$	(44,081	)	$	(46,070	)	$	(53,791	)	$	(5,857	)	$	(6,207	)

Employer Contributions, Participant Contributions and Benefit Payments

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

	Pension Plan						PBOP Plan						SERP
	2013		2012		2011		2013		2012		2011		2013		2012		2011
Employer Contributions	$	3,700	$	9,387	$	8,813	$	3,280	$	2,190	$	—	$	53	$	53	$	53
Participant Contributions	$	—	$	—	$	—	$	36	$	18	$	13	$	—	$	—	$	—
Benefit Payments	$	3,764	$	4,456	$	3,438	$	1,942	$	2,083	$	1,644	$	53	$	53	$	53

Estimated Future Benefit Payments

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

Estimated Future Benefit Payments
	Pension		PBOP		SERP
2014	$	4,495	$	1,914	$	384
2015		4,617		2,056		380
2016		4,742		2,129		375
2017		5,050		2,277		369
2018		5,188		2,404		364
2019 - 2023	$	31,826	$	14,496	$	1,925

Actual Investment Allocations

The actual investment allocations are shown in the tables below.

Pension Plan	Target Allocation 2014			Actual Allocation at December 31,
				2013			2012			2011
Equity Funds		48	%		54	%		48	%		49	%
Debt Funds		37	%		32	%		47	%		46	%
Real Estate Fund		10	%		1	%		0	%		0	%
Asset Allocation Fund(1)		5	%		5	%		5	%		5	%
Other(2)		0	%		8	%		0	%		0	%
Total					100	%		100	%		100	%

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

⁽²⁾ Represents investments being held in cash equivalents as of December 31, 2013 pending transfer into a Real Estate Fund.

PBOP Plan	Target Allocation 2014			Actual Allocation at December 31,
				2013			2012			2011
Equity Funds		55	%		57	%		56	%		55	%
Debt Funds		45	%		43	%		44	%		45	%
Total					100	%		100	%		100	%

Fair Value of Pension Plan Investments Estimated using Net Asset Value

The following tables set forth additional disclosures of Pension Plan investments whose fair value is estimated using net asset value per share as of December 31, 2013. There were no Pension Plan investments whose fair value is estimated using net asset value per share as of December 31, 2012:

	Fair Value Estimated Using NAV Per Share
	December 31, 2013
Description	Fair Value	Unfunded Commitment	Redemption Frequency	Redemption Notice Period
SEI Core Property Collective Investment Trust Fund(1)	$1,125,000	$—	Quarterly	65 days

⁽¹⁾  The SEI Core Property Collective Investment Trust Fund, through the SEI Core Property Fund, seeks both current income and long-term capital appreciation through investing in underlying funds that acquire, manage, and dispose of commercial real estate properties.

Summary of Changes in the Fair Value of the Pension Plan Level 3 Assets

The table below sets forth a summary of changes in the fair value of the Pension Plan’s Level 3 assets for the year ended December 31, 2013:

	Level 3 Assets
	SEI Core  Property Collective Investment Trust Fund
Balance at December 31, 2012	$	—
Purchases		1,125,000
Balance at December 31, 2013	$	1,125,000
Amount of Total Gains or Losses for the Year Attributable to the Change in Unrealized Gains or Losses Relating to Assets Still Held at December 31, 2013	$	—

Pension Plans

Assets Measured at Fair Value on Recurring Basis

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2013 and 2012 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)
2013
Pension Plan Assets:
Equity Funds	$	44,201	$	44,201	$	—	$	—
Fixed Income Funds		26,276		26,276		—		—
Asset Allocation Fund		4,574		4,574		—		—
Real Estate Fund		1,125		—		—		1,125
Cash Equivalents		6,375		6,375		—		—
Total Assets	$	82,551	$	81,426	$	—	$	1,125
2012
Pension Plan Assets:
Equity Funds	$	34,742	$	34,742	$	—	$	—
Fixed Income Funds		34,251		34,251		—		—
Asset Allocation Fund		3,418		3,418		—		—
Total Assets	$	72,411	$	72,411	$	—	$	—

Other Postretirement Benefit Plans, Defined Benefit

Assets Measured at Fair Value on Recurring Basis

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2013 and 2012 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)
2013
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	4,689	$	4,689	$	—	$	—
Index Funds		4,467		4,467
Equity Funds		1,673		1,673
Total Assets	$	10,829	$	10,829	$	—	$	—
2012
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	3,670	$	3,670	$	—	$	—
Index Funds		3,357		3,357
Equity Funds		1,274		1,274
Total Assets	$	8,301	$	8,301	$	—	$	—

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Restricted Shares Issued in Conjunction with Stock Plan (Detail) (Restricted Shares, USD $)	12 Months Ended
	Dec. 31, 2013
Period 1
Class of Stock [Line Items]
Issuance Date	Feb. 09, 2011
Shares	24,330
Aggregate Market Value	$ 600,000
Period 2
Class of Stock [Line Items]
Issuance Date	Feb. 03, 2012
Shares	25,600
Aggregate Market Value	$ 700,000
Period 3
Class of Stock [Line Items]
Issuance Date	Feb. 04, 2013
Shares	21,240
Aggregate Market Value	$ 600,000

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Debt and Financing Arrangements - Additional Information (Detail) (USD $)	12 Months Ended								1 Months Ended	12 Months Ended		1 Months Ended							12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Unitil Corporation Maximum	Dec. 31, 2013 Fitchburg Gas and Electric Light Company	Dec. 31, 2013 Northern Utilities Inc	Dec. 31, 2012 Northern Utilities Inc	Dec. 31, 2013 Granite State Gas Transmission Inc	Oct. 04, 2013 Revolving Credit Facility	Dec. 31, 2013 Revolving Credit Facility	Dec. 31, 2012 Revolving Credit Facility	Oct. 04, 2013 Revolving Credit Facility London Interbank Offered Rate	Dec. 31, 2013 8.00% Senior Secured Notes, Due August 1, 2017 Unitil Realty Corp	Dec. 31, 2012 8.00% Senior Secured Notes, Due August 1, 2017 Unitil Realty Corp	Dec. 31, 2013 8.00% Senior Secured Notes, Due August 1, 2017 Unitil Realty Corp Debt Outstanding, Principal Amount	Dec. 31, 2013 7.15% Senior Notes, Due December 15, 2018 Granite State Gas Transmission Inc	Dec. 31, 2012 7.15% Senior Notes, Due December 15, 2018 Granite State Gas Transmission Inc	Dec. 31, 2013 7.15% Senior Notes, Due December 15, 2018 Granite State Gas Transmission Inc Debt Outstanding, Principal Amount	Dec. 31, 2013 Bonds	Dec. 31, 2012 Bonds	Dec. 31, 2011 Bonds
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization				70.00%	65.00%	65.00%		65.00%
Long term debt repayments	$ 500,000	$ 500,000	$ 500,000																$ 541,938	$ 500,405	$ 462,055
Debt repayment, 2014																			2,486,919
Debt repayment, 2015																			4,035,633
Debt repayment, 2016																			17,421,724
Debt repayment, 2017																			17,160,985
Debt repayment, 2018																			30,133,332
Revolving credit facility expiration date									Oct. 04, 2018
Revolving credit facility									120,000,000	120,000,000	60,000,000
Sublimit for the issuance of standby letters of credit									25,000,000
Credit facility, daily fluctuating rate of interest												1.375%
Credit Facility by an aggregate additional amount									30,000,000
Percentage of capitalization										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, 2013, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.
Weighted average interest rate on short term borrowings	1.80%	2.00%	2.20%
Outstanding inventory						12,500,000	10,700,000
Accounts Payable	38,100,000	32,700,000				2,700,000	2,100,000
Total rental expense under operating leases	1,200,000	1,300,000	1,400,000
Guarantee outstanding	19,100,000
Guarantee end date	Oct. 31, 2014
Senior Secured Notes													2,300,000	2,800,000	2,300,000
Senior Notes																$ 10,000,000	$ 10,000,000	$ 10,000,000

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Consolidated Statements of Changes in Common Stock Equity (USD $) In Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Jan. 01, 2011	$ 189.0	$ 160.8	$ 28.2
Net Income	16.4		16.4
Dividends	(15.2)		(15.2)
Shares Issued Under Stock Plans	0.5	0.5
Issuance of Common Shares	1.0	1.0
Ending Balance at Dec. 31, 2011	191.7	162.3	29.4
Net Income	18.2		18.2
Dividends	(17.2)		(17.2)
Shares Issued Under Stock Plans	0.9	0.9
Issuance of Common Shares	1.1	1.1
Issuance of Common Shares	65.7	65.7
Ending Balance at Dec. 31, 2012	260.4	230.0	30.4
Net Income	21.6		21.6
Dividends	(19.1)		(19.1)
Shares Issued Under Stock Plans	1.0	1.0
Issuance of Common Shares	1.1	1.1
Ending Balance at Dec. 31, 2013	$ 265.0	$ 232.1	$ 32.9

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Allowance for Doubtful Accounts

12 Months Ended

Dec. 31, 2013

Allowance for Doubtful Accounts

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 2013, 2012 and 2011, the Company recorded provisions for the energy commodity portion of bad debts of $1.4 million, $1.9 million and $1.8 million, respectively. These provisions were recognized in Purchased Electricity and Purchased Gas expense as the associated electric and gas utility revenues were billed. Purchased Electricity and Purchased Gas costs are recovered from customers through periodic rate reconciling mechanisms.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2011 – 2013 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2013
Electric	$	1.1	$	2.6	$	0.2	$	2.6	$	1.3
Gas		0.7		2.0		0.2		2.7		0.2
Other		0.1		—		—		—		0.1
	$	1.9	$	4.6	$	0.4	$	5.3	$	1.6
Year Ended December 31, 2012
Electric	$	1.7	$	1.4	$	0.3	$	2.3	$	1.1
Gas		0.5		2.2		0.3		2.3		0.7
Other		0.1		—		—		—		0.1
	$	2.3	$	3.6	$	0.6	$	4.6	$	1.9
Year Ended December 31, 2011
Electric	$	1.8	$	2.1	$	0.2	$	2.4	$	1.7
Gas		0.7		2.2		0.3		2.7		0.5
Other		0.1		—		—		—		0.1
	$	2.6	$	4.3	$	0.5	$	5.1	$	2.3

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Deferred Tax Assets and Liabilities, Non Current (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Schedule of Deferred Tax Assets and Liabilities [Line Items]
Utility Plant Differences	$ 102,479,000	$ 66,907,000
Net Operating Loss Carryforwards	(17,403,000)	(8,521,000)
AMT Tax Credit Carryforwards	(1,538,000)	(1,538,000)
Regulatory Assets & Liabilities	17,174,000	17,872,000
Retirement Benefit Obligations	(28,287,000)	(38,644,000)
Other, net	754,000	2,606,000
Total Noncurrent Deferred Income Tax Liabilities	$ 73,200,000	$ 38,700,000

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Summary of Changes in the Fair Value of the Pension Plan Level 3 Assets (Detail) (SEI Core Property Collective Investment Trust Fund, USD $)	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at End of Year	$ 1,125,000	[1]
Fair Value, Inputs, Level 3
Defined Benefit Plan Disclosure [Line Items]
Purchases	1,125,000
Plan Assets at End of Year	1,125,000
Amount of Total Gains or Losses for the Year Attributable to the Change in Unrealized Gains or Losses Relating to Assets Still Held at December 31, 2013

[1] The SEI Core Property Collective Investment Trust Fund, through the SEI Core Property Fund, seeks both current income and long-term capital appreciation through investing in underlying funds that acquire, manage, and dispose of commercial real estate properties.

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Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013 Bcf	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012 Bcf	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013 mi Entity Bcf	Dec. 31, 2012 Bcf	Dec. 31, 2011
Significant Accounting Policies [Line Items]
Number of Subsidiaries									3
Length Of Pipeline									86
Depreciation rate based on average depreciable property balance									3.59%	3.60%	3.43%
Common stock dividend paid per share	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 1.38	$ 1.38	$ 1.38
Average interest rates									1.92%	2.04%	2.28%
Cost of removal obligation	$ 57.3				$ 51.4				$ 57.3	$ 51.4
Number of Natural Gas Storage Outstanding	1.8				1.9				1.8	1.9
Intangible Assets, Purchase Adjustments									12.2
Plant
Significant Accounting Policies [Line Items]
Intangible Asset Amortization Period									10 years
Bargain Purchase Adjustment
Significant Accounting Policies [Line Items]
Intangible Asset Amortization Period									5 years
Maximum
Significant Accounting Policies [Line Items]
Cash equivalents maturity period									3 months
Quarterly Dividends
Significant Accounting Policies [Line Items]
Common stock dividend paid per share									$ 0.345	$ 0.345	$ 0.345
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits	7.3				5.4				7.3	5.4
Natural Gas Hedging Program
Significant Accounting Policies [Line Items]
Cash Deposits	$ 0				$ 1.2				$ 0	$ 1.2
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries									3
Other Subsidiaries
Significant Accounting Policies [Line Items]
Number of Subsidiaries									3

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Significant Segment Financial Data (Detail) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	$ 109,800,000	$ 72,500,000	$ 66,400,000	$ 118,200,000	$ 98,800,000	$ 71,300,000	$ 68,800,000	$ 114,200,000	$ 366,900,000	$ 353,100,000	$ 352,800,000
Interest Income									3,200,000	4,200,000	1,600,000
Interest Expense									22,000,000	22,300,000	22,000,000
Depreciation & Amortization Expense									37,700,000	35,100,000	29,300,000
Income Tax Expense									12,652,000	10,976,000	10,025,000
Segment Profit	10,300,000	600,000	(100,000)	10,800,000	9,000,000	500,000	(400,000)	9,000,000	21,600,000	18,100,000	16,300,000
Segment Assets	920,600,000				892,300,000				920,600,000	892,300,000	856,100,000
Capital Expenditures									89,500,000	68,500,000	57,100,000
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									170,400,000	160,600,000	159,200,000
Interest Income									500,000	800,000	500,000
Interest Expense									11,000,000	11,100,000	10,700,000
Depreciation & Amortization Expense									17,200,000	15,700,000	13,600,000
Income Tax Expense									7,500	5,800	4,300
Segment Profit									12,500,000	8,900,000	6,700,000
Segment Assets	502,300,000				471,700,000				502,300,000	471,700,000	442,200,000
Capital Expenditures									61,100,000	43,900,000	33,600,000
Electricity
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									190,700,000	187,000,000	188,100,000
Interest Income									2,200,000	2,900,000	900,000
Interest Expense									9,500,000	9,500,000	9,600,000
Depreciation & Amortization Expense									19,500,000	18,000,000	14,200,000
Income Tax Expense									5,100	4,800	5,200
Segment Profit									7,600,000	7,600,000	7,800,000
Segment Assets	402,800,000				409,300,000				402,800,000	409,300,000	401,900,000
Capital Expenditures									23,600,000	21,200,000	20,300,000
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									5,800,000	5,500,000	5,500,000
Interest Income									100,000	100,000	100,000
Income Tax Expense									800	900	1,100
Segment Profit									1,200,000	1,300,000	1,700,000
Segment Assets	6,200,000				5,700,000				6,200,000	5,700,000	5,500,000
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income									400,000	400,000	100,000
Interest Expense									1,500,000	1,700,000	1,700,000
Depreciation & Amortization Expense									1,000,000	1,400,000	1,500,000
Income Tax Expense									(700)	(500)	(600)
Segment Profit									300,000	300,000	100,000
Segment Assets	9,300,000				5,600,000				9,300,000	5,600,000	6,500,000
Capital Expenditures									$ 4,800,000	$ 3,400,000	$ 3,200,000

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2013

Significant Segment Financial Data

The following table provides significant segment financial data for the years ended December 31, 2013, 2012 and 2011 (millions):

Year Ended December 31, 2013	Gas		Electric		Non- Regulated		Other			Total
Revenues	$	170.4	$	190.7	$	5.8	$	—		$	366.9
Interest Income		0.5		2.2		0.1		0.4			3.2
Interest Expense		11.0		9.5		—		1.5			22.0
Depreciation & Amortization Expense		17.2		19.5		—		1.0			37.7
Income Tax Expense (Benefit)		7.5		5.1		0.8		(0.7	)		12.7
Segment Profit (Loss)		12.5		7.6		1.2		0.3			21.6
Segment Assets		502.3		402.8		6.2		9.3			920.6
Capital Expenditures		61.1		23.6		—		4.8			89.5
Year Ended December 31, 2012
Revenues	$	160.6	$	187.0	$	5.5	$	—		$	353.1
Interest Income		0.8		2.9		0.1		0.4			4.2
Interest Expense		11.1		9.5		—		1.7			22.3
Depreciation & Amortization Expense		15.7		18.0		—		1.4			35.1
Income Tax Expense (Benefit)		5.8		4.8		0.9		(0.5	)		11.0
Segment Profit (Loss)		8.9		7.6		1.3		0.3			18.1
Segment Assets		471.7		409.3		5.7		5.6			892.3
Capital Expenditures		43.9		21.2		—		3.4			68.5
Year Ended December 31, 2011
Revenues	$	159.2	$	188.1	$	5.5	$	—		$	352.8
Interest Income		0.5		0.9		0.1		0.1			1.6
Interest Expense		10.7		9.6		—		1.7			22.0
Depreciation & Amortization Expense		13.6		14.2		—		1.5			29.3
Income Tax Expense		4.3		5.2		1.1		(0.6	)		10.0
Segment Profit		6.7		7.8		1.7		0.1			16.3
Segment Assets		442.2		401.9		5.5		6.5			856.1
Capital Expenditures		33.6		20.3		—		3.2			57.1