10-K 1 d262242d10k.htm FORM 10-K

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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, 2011

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 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. (Check one):

Large Accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨

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 shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Based on the closing price of June 30, 2011, the aggregate market value of common stock held by non-affiliates of the registrant was $282,734,913.

The number of common shares outstanding of the registrant was 10,955,671 as of January 30, 2012.

Documents Incorporated by Reference:

Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 19, 2012 are incorporated by reference into Part III of this Report

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UNITIL CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2011

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 |  |  | 9 |
|  | Directors and Executive Officers of the Registrant |  |  | 9 |
|  | Investor Information |  |  | 11 |
1A. |  | Risk Factors |  |  | 12 |
1B. |  | Unresolved Staff Comments |  |  | 17 |
2. |  | Properties |  |  | 17 |
3. |  | Legal Proceedings |  |  | 18 |
|  | PART II |  |  |  |
5. |  | Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities |  |  | 20 |
6. |  | Selected Financial Data |  |  | 23 |
7. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) |  |  | 24 |
7A. |  | Quantitative and Qualitative Disclosures about Market Risk |  |  | 44 |
8. |  | Financial Statements and Supplementary Data |  |  | 46 |
9. |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |  |  | 88 |
9A. |  | Controls and Procedures |  |  | 88 |
9B. |  | Other Information |  |  | 88 |
|  | PART III |  |  |  |
10. |  | Directors, Executive Officers of the Registrant and Corporate Governance |  |  | 89 |
11. |  | Executive Compensation |  |  | 89 |
12. |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |  |  | 89 |
13. |  | Certain Relationships and Related Transactions, and Director Independence |  |  | 89 |
14. |  | Principal Accountant Fees and Services |  |  | 89 |
|  | PART IV |  |  |  |
15. |  | Exhibits and Financial Statement Schedules |  |  | 90 |
|  | Signatures |  |  | 94 |

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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. (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 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 101,400 electric customers and 71,900 natural gas customers.

Unitil’s distribution utilities had an investment in Net Utility Plant of $510.7 million at December 31, 2011. Unitil’s total operating revenue was $352.8 million in 2011. Substantially all of Unitil’s operating revenue is derived from regulated distribution utility operations.

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 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 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

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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, see Part II, Item 8, Note 8 herein).

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 $159.2 million for 2011, which represent about 45% of Unitil’s total operating revenue. In 2008, the Company significantly expanded its gas operations by acquiring Northern Utilities and Granite State.

On December 1, 2008, the Company purchased Northern Utilities, a natural gas distribution utility serving customers in Maine and New Hampshire, from Bay State Gas Company (Bay State) and Granite State, an interstate natural gas transmission pipeline company primarily serving the needs of Northern Utilities, from NiSource Inc. (NiSource).

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 territory in New Hampshire, Massachusetts and Maine. As a result of a restructuring of the gas utility industry in New Hampshire, Massachusetts and Maine, Fitchburg’s residential and commercial and industrial (C&I) customers and Northern Utilities’ 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 56,600 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 industries of auto, housing, rubber, printing, textile, pharmaceutical, electronics, wires and food production as well as a military installation. Northern Utilities’ 2011 gas operating revenue was $123.1 million, of which approximately 40.0% was derived from residential firm sales and 60.0% from commercial/industrial firm sales.

Natural gas is supplied and distributed by Fitchburg to approximately 15,300 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 2011 gas operating revenue was $31.5 million, of which approximately 51% was derived from residential firm sales and 49.0% 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 provides Northern Utilities with interconnection to major natural gas pipelines and access to North American pipeline supplies. Granite State had operating revenue of $4.6 million for 2011. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and to third-party marketers.

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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 $188.1 million for 2011, which represents about 53% 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 73,100 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 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, wires and plastics, healthcare and education. Unitil Energy’s 2011 electric operating revenue was $128.8 million, of which approximately 54.0% was derived from residential sales and 46.0% 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 28,300 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 education. Fitchburg’s 2011 electric operating revenue was $59.3 million, of which approximately 52.0% was derived from residential sales and 48.0% from C&I sales.

Seasonality

As a result of the acquisitions of Northern Utilities and Granite State in 2008, consolidated results for the Company in the current period may not be directly comparable to some prior period results until such time as the acquisitions are fully reflected in all reporting periods presented. In particular, 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.

Electric sales in New England are far less seasonal than natural gas sales; however, the highest usage typically occurs in both the summer months due to air conditioning demand and the winter months due to heating-related requirements and shorter daylight hours. 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 $5.5 million in 2011.

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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 Part II, Item 8, Note 8 herein).

(For details on Unitil’s Results of Operations, see Part II, Item 7 herein.)

RATES AND 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 New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the Massachusetts Department of Public Utilities (MDPU); and Northern Utilities is regulated by the NHPUC and Maine Public Utilities Commission (MPUC). Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under 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. As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, 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.

Rate Case Activity

Fitchburg—Increase in Base Rates Approved—On August 1, 2011, the MDPU issued an order approving increases of $3.3 million and $3.7 million in annual distribution revenues for Fitchburg’s electric and gas divisions, respectively. The MDPU also approved revenue decoupling mechanisms and a return on equity of 9.2% for both the electric and gas divisions of Fitchburg. The rate increase for Fitchburg’s electric division included the recovery of $11.4 million of previously deferred emergency storm restoration costs associated with the December 2008 ice storm, which costs are to be amortized and recovered over seven (7) years without carrying costs. The order provides resolution to the open regulatory matters concerning the ratemaking treatment and cost recovery related to the December 2008 ice storm event.

Granite State—Increase in Base Rates Approved—On January 31, 2011, the FERC approved a settlement agreement providing for an increase of $1.7 million in annual revenue, based on new gas transportation rates to be effective January 1, 2011. Subsequently, on August 31, 2011, the FERC approved an amendment to the settlement agreement which provides for an additional increase of approximately $0.5 million in Granite State’s annual revenues effective August 1, 2011. Under the amended settlement agreement, beginning in 2012, Granite State is permitted to file limited annual rate adjustment filings to recover the revenue requirements for certain specified future capital cost additions to transmission plant projects. The limited rate adjustments would be effective August 1 of each year, and are projected to conclude in 2014 when the major projects will be completed. The annual revenue increases for the limited rate adjustments are estimated to be approximately $0.5 million each year during 2012 through 2014.

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Unitil Energy—Increase in Base Rates Approved—On April 26, 2011, the NHPUC approved a final rate settlement which makes permanent a temporary increase of $5.2 million in annual revenue effective July 1, 2010, and provides for 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 estimated future increases of $1.5 million to $2.0 million in annual revenue to occur on May 1, 2012, May 1, 2013 and May 1, 2014, to support Unitil Energy’s continued capital improvements to its distribution system. The rate plan allows Unitil to file for additional rate relief if its return on equity is less than 7% and a sharing of earnings with customers if its return on equity is greater than 10% in a calendar year. The settlement provides for a return on equity of 9.67%, a common equity ratio of 45.45% and an overall weighted cost of capital of 8.39% to determine changes to distribution rate levels.

The settlement approved Unitil Energy’s proposal for an augmented vegetation management program and reliability enhancement program. Under the augmented vegetation management program, Unitil Energy will be increasing its vegetation management spending from a test-year spending level of approximately $0.7 million to $3.1 million per year by 2013. Under the new reliability enhancement program, Unitil Energy will spend $1.8 million annually towards targeted projects designed to enhance system reliability. The funding for both of these programs is included in the future rate increases discussed above.

The settlement provides for recovery of deferred December 2008 ice storm and February 2010 wind storm costs of approximately $7.6 million, including carrying charges. These costs will be recovered over eight years in the form of a tariff surcharge. Finally, the settlement establishes a major storm reserve of $400,000 annually, which will be used to recover costs associated with responding to and recovering from future qualifying major storm events.

Northern Utilities—Base Rate Case Filings—In May 2011, Northern Utilities filed two separate rate cases with the NHPUC and MPUC requesting approval to increase its natural gas distribution base rates in New Hampshire and Maine, respectively.

On November 29, 2011, the MPUC approved a comprehensive settlement agreement providing for a $7.8 million permanent increase in annual distribution revenue for Northern Utilities’ Maine operations, effective January 1, 2012, and an additional permanent increase in annual distribution revenue of $0.85 million to recover the costs of 2011 cast iron pipe replacement capital spending effective May 1, 2012. The settlement is inclusive of an earlier settlement for a temporary rate increase of $3.5 million in annual distribution revenue effective November 1, 2011. The settlement also precludes Northern Utilities from filing for a new base rate increase with an effective date prior to January 1, 2014.

In New Hampshire, Northern Utilities requested an increase of $5.2 million in annual gas distribution base revenue, which represents an increase of approximately 8.1%. On July 22, 2011, the NHPUC approved a settlement for a temporary rate increase of approximately $1.7 million in annual revenue effective August 1, 2011. Once permanent rates are approved by the NHPUC, they will be reconciled back to August 1, 2011. The Company is currently in settlement discussions with the NHPUC and a final rate order is expected in the first quarter of 2012.

Also see Part II, Item 7 below for Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulatory Matters and Note 5 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.

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

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to purchase their supplies at regulated rates from Fitchburg. 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. 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 Purchased Gas in the Consolidated Statements of Earnings.

On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered the Company’s electric and natural gas distribution utility, Fitchburg, to refund $4.6 million of natural gas costs, plus interest. The MDPU’s original order, issued in 2009, found that Fitchburg had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU’s prior approval and that Fitchburg’s natural gas purchasing practices were imprudent. The Company appealed the MDPU’s decision to the SJC. The SJC’s decision vacates the MDPU’s order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. The Company had previously recorded a pre-tax charge to earnings and recognized a Regulatory Liability of $4.9 million in the fourth quarter of 2009 based on the MDPU’s original order. As a result of the decision, the Regulatory Liability has been adjusted and the Company recognized a pre-tax credit of $4.7 million in the fourth quarter of 2011. This credit is recognized on the Company’s 2011 Consolidated Statement of Earnings as a $4.5 million reduction in Purchased Gas expense and a reduction of $0.2 million in Interest Expense, net.

Regulated Natural Gas Supply

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 liquefied natural gas (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 million British Thermal Units (MMbtu) per day for transportation and underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and a LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

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

Northern Utilities has available under firm contract 100,000 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.

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 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

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electric supply from competitive third-party energy suppliers. As of December 2011, 106 or 71% of Unitil’s largest New Hampshire customers, representing 25% of total New Hampshire electric energy sales, and 28 or 93% of Unitil’s largest Massachusetts customers, representing 33% 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. 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.

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. Currently, all Basic Service power supply contracts for large general accounts are three months in duration and provide 100% of supply requirements. 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.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Unitil Energy procures Default Service supply for its large general service accounts through competitive solicitations for power contracts of three months in duration for 100% of supply requirements. Unitil Energy procures Default Service supply for its other customers through a series of two one-year contracts and two two-year contracts, each providing 25% of the total supply requirements of the group.

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 economic manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England is 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 power system operation in a reliable manner 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.

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 compliance with applicable environmental and safety laws and regulations, and the Company believes that

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as of December 31, 2011, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, there can be no assurance 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.

Fitchburg’s Manufactured Gas Plant Site—Fitchburg continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. Fitchburg has proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection, which allows Fitchburg to work towards temporary closure of the site. A status of temporary closure requires Fitchburg to monitor the site until a feasible permanent remediation alternative can be developed and completed.

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. Fitchburg had filed suit against several of its former insurance carriers seeking coverage for past and future environmental response costs at the site. In January 2011, Fitchburg settled with the remaining insurance carriers for approximately $2.0 million and received these payments in the first quarter of 2011. Any recovery that Fitchburg receives from insurance or third-parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are shared equally between Fitchburg and its gas customers.

Northern Utilities’ Manufactured Gas Plant Sites—Northern Utilities has an extensive program to identify, investigate and remediate former 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, and Scarborough sites. The sites in Lewiston and Portland have been investigated and remedial activities are currently underway. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs 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.

Also, see Part II, Item 7 below for Management’s Discussion and Analysis of Financial Condition and Results of Operations—Environmental Matters and Note 5 to the accompanying Consolidated Financial Statements for additional information on Environmental Matters.

EMPLOYEES

As of December 31, 2011, the Company and its subsidiaries had 454 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of December 31, 2011, 151 of the Company’s employees were represented by labor unions. These employees are covered by four separate collective bargaining agreements which expire on March 31, 2012, May 31, 2012, May 31, 2013 and June 5, 2014. The agreements provide discreet salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.

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AVAILABLE INFORMATION

The Company’s Internet address is www.unitil.com. There, 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 through the Investors section of Unitil’s website via a direct link to the section of the SEC’s website which contains Unitil’s SEC filings.

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.”

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table provides information about our directors and senior management as of February 1, 2012:

Name |  | Age |  |  | Position
Robert G. Schoenberger |  |  | 61 |  |  | Chairman of the Board, Chief Executive Officer and President
Mark H. Collin |  |  | 52 |  |  | Senior Vice President, Chief Financial Officer and Treasurer
Thomas P. Meissner, Jr. |  |  | 49 |  |  | Senior Vice President and Chief Operating Officer
Laurence M. Brock |  |  | 58 |  |  | Controller and Chief Accounting Officer
Todd R. Black |  |  | 47 |  |  | Senior Vice President, External Affairs and Customer Relations, Unitil Service
George R. Gantz |  |  | 60 |  |  | Senior Vice President, Distributed Energy Resources, Unitil Service
George E. Long, Jr. |  |  | 55 |  |  | Vice President, Administration, Unitil Service
Sandra L. Whitney |  |  | 48 |  |  | Corporate Secretary
William D. Adams |  |  | 64 |  |  | Director
Dr. Robert V. Antonucci |  |  | 66 |  |  | Director
David P. Brownell |  |  | 68 |  |  | Director
Michael J. Dalton |  |  | 71 |  |  | Director
Albert H. Elfner, III |  |  | 67 |  |  | Director
Edward F. Godfrey |  |  | 62 |  |  | Director
Michael B. Green |  |  | 62 |  |  | Director
Eben S. Moulton |  |  | 65 |  |  | Director
M. Brian O’Shaughnessy |  |  | 68 |  |  | Director
Dr. Sarah P. Voll |  |  | 69 |  |  | Director

Robert G. Schoenberger has been Unitil’s Chairman of the Board of Directors and Chief Executive Officer since October 1997, and his current term will expire in 2012. Mr. Schoenberger will stand for re-election to the Board of Directors at the Annual Meeting of Shareholders in April 2012. Mr. Schoenberger has also served as Unitil’s President since 2003. Prior to his employment with Unitil, Mr. Schoenberger was president and chief operating officer of the New York Power Authority (a state-owned utility) from 1993 until 1997. Mr. Schoenberger has also served as a director of Satcon Technology Corporation, Boston, Massachusetts (a company that develops innovative power conversion solutions for the renewable power industry) since 2007. Mr. Schoenberger also serves as chairman of the Tocqueville Society of the Greater Seacoast (New Hampshire) United Way. Mr. Schoenberger formerly served as chairman and trustee of Exeter Health Resources, Exeter, New Hampshire, from 1998 until 2009, and as a director of the Southwest Power Pool from 2003 until 2005.

Mark H. Collin has been Unitil’s Senior Vice President and Chief Financial Officer since February 2003. Mr. Collin has also served as Treasurer since 1998. Mr. Collin joined Unitil in 1988, and served as Vice President of Finance from 1995 until 2003.

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Thomas P. Meissner, Jr. has been Unitil’s Senior Vice President and Chief Operating Officer since June 2005. Mr. Meissner served as Senior Vice President, Operations, from February 2003 until June 2005. Mr. Meissner joined Unitil in 1994 and served as Director of Engineering from 1998 until 2003.

Laurence M. Brock has been Unitil’s Controller and Chief Accounting Officer since June 2005. Mr. Brock joined Unitil in 1995 as Vice President and Controller, and is a certified public accountant in the state of New Hampshire.

Todd R. Black has been Unitil’s Senior Vice President, External Affairs and Customer Relations, Unitil Service, since September 2009. Mr. Black joined Unitil in 1998 and served as Vice President, Sales and Marketing, for Usource from 1998 until 2003, and President of Usource from 2003 until 2009.

George R. Gantz has been Unitil’s Senior Vice President, Distributed Energy Resources, Unitil Service, since September 2009. Mr. Gantz joined Unitil in 1983 and served as Senior Vice President, Communication and Regulation, from 1994 until 2003, and Senior Vice President, Customer Services and Communications, from 2003 until 2009.

George E. Long, Jr. has been Unitil’s Vice President, Administration, Unitil Service, since February 2003. Mr. Long joined Unitil in 1994 and was Director, Human Resources, from 1998 until 2003.

Sandra L. Whitney has been Unitil’s Corporate Secretary and secretary of our Board of Directors since February 2003. Ms. Whitney joined Unitil in 1990 and also serves as the Corporate Secretary of Unitil’s subsidiary companies.

William D. Adams has been a member of Unitil’s Board of Directors since March 2009, and his current term will expire in 2012. Mr. Adams will stand for re-election to the Board of Directors at the Annual Meeting of Shareholders in April 2012. Mr. Adams has been the president of Colby College in Waterville, Maine, since 2000, and as president, Mr. Adams also serves on the board of trustees of Colby College. Prior to going to Colby, Mr. Adams served as president of Bucknell University in Pennsylvania from 1995 until 2000. Mr. Adams served as vice president and secretary of Wesleyan University in Connecticut, before Bucknell. Mr. Adams also taught political philosophy at the University of North Carolina at Chapel Hill and Santa Clara University, and was coordinator of the Great Works in Western Culture program at Stanford University. Mr. Adams has been a member of the board of directors of Maine Public Broadcasting Corporation since 2002. Mr. Adams formerly served on the board of directors of Wittenberg University from 2007—2011, and also the board of directors of Maine General Health from 2002 to 2010.

Dr. Robert V. Antonucci has been a member of Unitil’s Board of Directors since December 2004, and his current term will expire in 2014. Dr. Antonucci has been the president of Fitchburg State University (FSU) in Fitchburg, Massachusetts, since 2003. Prior to his employment with FSU, Dr. Antonucci was president of the School Group of Riverdeep, Inc., San Francisco, California, from 2001 until 2003 and president and chief executive officer of Harcourt Learning Direct and Harcourt Online College, Chestnut Hill, Massachusetts from 1998 until 2001. Dr. Antonucci also served as the commissioner of education for the Commonwealth of Massachusetts from 1992 until 1998. In addition, Dr. Antonucci has served as a trustee of Eastern Bank since 1988. Dr. Antonucci also serves as a director of the North Central Massachusetts Chamber of Commerce and a director of the North Central Massachusetts United Way.

David P. Brownell has been a member of Unitil’s Board of Directors since June 2001, and his current term will expire in 2014. Mr. Brownell has been a retired senior vice president of Tyco International Ltd. (Tyco) (a diversified global manufacturing and service company), Portsmouth, New Hampshire, since 2003. Mr. Brownell had been with Tyco since 1984. Mr. Brownell is a member of the board of the University of New Hampshire (UNH) Foundation. Mr. Brownell was also interim president of the UNH Foundation, former vice chairman of the board of the UNH Foundation, former volunteer board president of the United Way of the Greater Seacoast, and a former board member of the New Hampshire Junior Achievement Advisory Council.

Michael J. Dalton has been a member of Unitil’s Board of Directors since September 1984, and his current term will expire in 2013. Mr. Dalton retired as President and Chief Operating Officer of Unitil in

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2003. Mr. Dalton is a member of the College Advisory Board of the UNH College of Engineering and Physical Science and Vice President of the Alumni Society of the College of Engineering and Physical Science. Mr. Dalton was formerly a director of the New England Gas Association, the Electric Council of New England, the UNH Foundation, the UNH Alumni Association, and the UNH President’s Council.

Albert H. Elfner, III has been a member of Unitil’s Board of Directors since January 1999, and his current term will expire in 2014. Mr. Elfner was the chairman of Evergreen Investment Management Company, Boston, Massachusetts, from 1994 until 1999 and its chief executive officer from 1995 until 1999. Mr. Elfner is also a director of Main Street America Insurance Company (Main Street), Jacksonville, Florida, as well as chairman of the Main Street finance committee.

Edward F. Godfrey has been a member of Unitil’s Board of Directors since January 2002 and his current term will expire in 2013. Mr. Godfrey was the executive vice president and chief operating officer of Keystone Investments, Incorporated (Keystone), Boston, Massachusetts, from 1997 until 1998. Mr. Godfrey was senior vice president, chief financial officer and treasurer of Keystone from 1988 until 1996. Mr. Godfrey has also been a director of Vector Fleet Management, LLC, Charlotte, North Carolina, since 2006.

Michael B. Green has been a member of Unitil’s Board of Directors since June 2001, and his current term will expire in 2014. Mr. Green has been the president and chief executive officer of Capital Region Health Care and Concord Hospital, Concord, New Hampshire, since 1992. Mr. Green is also a member of the adjunct faculty, Dartmouth Medical School, Dartmouth College, Hanover, New Hampshire. In addition, Mr. Green currently serves on the board of the Foundation for Healthy Communities, is a director of the New Hampshire Hospital Association, a director of Concord General Mutual Insurance Company, and a director of Merrimack County Savings Bank (Merrimack), including membership on Merrimack’s investment and audit committees.

Eben S. Moulton has been a member of Unitil’s Board of Directors since March 2000, and his current term will expire in 2014. Mr. Moulton has been the managing partner of Seacoast Capital Corporation, Danvers, Massachusetts, (a private investment company) since 1995. Mr. Moulton is also a director of IEC Electronics Corp. (a company that provides electronic manufacturing services to advanced technology companies), Newark, New York, and a director of six private companies.

M. Brian O’Shaughnessy has been a member of Unitil’s Board of Directors since September 1998, and his current term will expire in 2014. Mr. O’Shaughnessy has been the chairman of the board of Revere Copper Products, Inc. (Revere), Rome, New York, since 1989. Mr. O’Shaughnessy also served as chief executive officer and president of Revere from 1988 until 2007. Mr. O’Shaughnessy also serves on the Board of Directors and as the chief co-chair of the Coalition for a Prosperous America, three copper industry trade associations, three manufacturing associations in New York State regarding energy-related issues, and the Economic Development Growth Enterprise of Mohawk Valley.

Dr. Sarah P. Voll has been a member of Unitil’s Board of Directors since January 2003, and her current term will expire in 2012. Dr. Voll will stand for re-election to the Board of Directors at the Annual Meeting of Shareholders in April 2012. Dr. Voll retired in 2007 as vice president from National Economic Research Associates, Inc. (NERA), Washington, District of Columbia, a firm of consulting economists specializing in industrial and financial economics, and currently serves as a special consultant to NERA. Dr. Voll had been with NERA in the position of vice president since 1999, and in the position of senior consultant from 1996 until 1999. Prior to her employment with NERA, Dr. Voll was a staff member at the NHPUC from 1980 until 1996.

INVESTOR INFORMATION

Annual Meeting

The annual meeting of shareholders is scheduled to be held at the offices of the Company, 6 Liberty Lane West, Hampton, New Hampshire, on Thursday, April 19, 2012, at 10:30 a.m.

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Transfer Agent

The Company’s transfer agent, Computershare Investor Services, is responsible for shareholder records, issuance of common stock, administration of the Dividend Reinvestment and Stock Purchase Plan, and the distribution of Unitil’s dividends and IRS Form 1099-DIV. Shareholders may contact Computershare at:

Computershare Investor Services

P.O. Box 43078

Providence, RI 02940-3078

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 common stock are registered directly in the shareholder’s name with the Company’s transfer agent, the shareholder is considered a holder of record of the shares. The following services and programs are available to shareholders of record:

| • |  | Internet Account Access is available at www.computershare.com/investor.

| • |  | Dividend Reinvestment and Stock Purchase Plan:

To enroll, please contact the Company’s Investor Relations Representative or Computershare.

| • |  | Dividend Direct Deposit Service:

To enroll, please contact the Company’s Investor Relations Representative or Computershare.

| • |  | Direct Registration:

For information, please contact Computershare at 800-935-9330 or the Company’s Investor Relations Representative at 800-999-6501.

Item 1A. | Risk Factors

Risks Relating to Our Business

The Company is subject to comprehensive regulation, which could impact the rates it is able to charge, its authorized rate of return and its ability to recover costs. This could adversely affect the Company’s financial condition or results of operations. In addition, certain regulatory authorities have the power to impose finance 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. Also, changes in regulations or the imposition of additional regulations 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

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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. This could adversely affect the Company’s financial condition or results of operations.

Severe storms 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 or operations could be adversely affected.

Please see (i) Regulatory Matters in Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and (ii) Regulatory Matters in Note 5 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements.

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 or 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.

Substantially all of the Company’s stranded costs relate to (i) Unitil Power’s long-term power purchase agreements (which Unitil Power divested under long-term contract buyout agreements) and (ii) Fitchburg’s formerly owned generation assets and purchase power agreements (which Fitchburg divested under a long-term contract buy-out agreement). Unitil Power made the final payment on its long-term contract buyout agreements in October 2010, which ended its obligations in the underlying purchase power contracts. As a result, in accordance with its retail stranded cost recovery rates, as of December 31, 2011, Unitil Energy has recovered substantially all of its stranded costs with the remaining $4.2 million of stranded costs projected to be fully recovered over the next ten years. Because Fitchburg continues to remain ultimately responsible for purchase power payments underlying its long-term buyout agreements, Fitchburg could incur additional stranded costs if they were required to resell such divested entitlements prior to the end of their term for amounts less than the amounts agreed to under the existing long-term buyout agreements. The Company expects that any such additional stranded costs would be recovered from its customers, however such recovery would require approval from the MDPU, the receipt of which cannot be assured. 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 (i) the section entitled Regulatory Matters—Overview (Unitil Energy, Fitchburg, and Northern Utilities) in Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and (ii) the section entitled Regulatory Matters—Overview (Unitil Energy, Fitchburg, and Northern Utilities) in Note 5 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements.

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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 and the Company’s operating and financial performance could negatively affect the Company’s ability to obtain such financings and the terms of such financings, which could correspondingly adversely affect the Company’s financial condition or results or operations.

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 or operations could be adversely affected.

Please see (i) 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 (ii) Note 9 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements.

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, 2011, the Company had approximately $87.9 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 Part II, Item 7 below for Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, Commitments and Capital Requirements section and Note 3 to the accompanying Consolidated Financial Statements.

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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 business operations (including their ability to incur material amounts of additional indebtedness), which could adversely affect the Company’s financial condition or results or operations.

See Part II, Item 7 below for Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, Commitments and Capital Requirements section and Note 3 to the accompanying Consolidated Financial Statements.

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 or 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.

On August 1, 2011, the MDPU issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of the Company’s Massachusetts combination electric and natural gas distribution utility, 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. The purpose of decoupling is to eliminate the disincentive a utility otherwise has to encourage energy efficiency programs. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011 forward, distribution revenues for Fitchburg based on predetermined amounts approved by the MDPU. The difference between distribution revenue amounts billed to customers and the predetermined 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 or credits.

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 due to long-term global climate change may cause a decrease in the amount of natural gas and electricity sold by the Company, which could correspondingly adversely affect the Company’s financial condition and results or operations. Conversely, colder winter temperatures and warmer summer temperatures due to long-term global climate change may 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) related to long-term global climate change may damage facilities or result in increased service interruptions and outages and

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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 could be adversely affected.

The Company is unable to predict the impacts on its financial condition and results or operations due to changes in weather 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.

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 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

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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, there can be no assurance 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.

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.

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.

Item 1B. | Unresolved Staff Comments

None.

Item 2. | Properties

As of December 31, 2011, Unitil owned, through its electric distribution utilities, three utility operation centers, approximately 1,707 primary pole miles of local transmission and distribution overhead electric lines and 367 conduit bank miles of underground electric distribution lines, along with 50 electric substations, including four mobile electric substations. The Company’s natural gas operations property includes two liquid propane gas plants, two liquid natural gas plants and 1,287 miles of underground gas mains. 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.

Unitil Energy owns and maintains distribution operations centers in Concord, New Hampshire and Kensington, New Hampshire. Unitil Energy’s 32 electric distribution substations, including a 5,000 kilovolt ampere (kVA) and a 10,500 kVA mobile substation, constitute 213,000 kVA of capacity, which excludes capacity of spare transformers, for the transformation of electric power from the 34.5 kilovolt

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subtransmission voltage to other primary distribution voltage levels. The electric substations are located on land owned by Unitil Energy or land occupied by Unitil Energy pursuant to perpetual easements.

Unitil Energy has a total of approximately 1,244 primary pole miles of local transmission and distribution overhead electric lines and a total of 310 conduit bank miles of underground electric distribution lines. The 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 properties consist principally of 463 primary pole miles of local transmission and distribution overhead electric lines, 57 conduit bank miles of underground electric distribution lines and 18 transmission and distribution stations (including two mobile electric substations). The capacity of these substations totals 441,650 kVA, which excludes capacity of spare transformers.

Fitchburg’s electric substations, with minor exceptions, are located 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, expressed or implied through use by Fitchburg without objection by the owners. Fitchburg leases its distribution operations center located in Fitchburg, Massachusetts.

Fitchburg owns a propane air gas plant and a liquid natural gas (LNG) storage and vaporization facility, both of which are located on land owned by Fitchburg. Fitchburg also has 263 miles of underground steel, cast iron and plastic gas mains.

Northern Utilities’ distribution system is comprised of 1,024 miles of gas mains and 38,935 service pipes. The gas mains are primarily made up of polyethylene plastic (70%), coated and wrapped cathodically protected steel (19%), cast/wrought iron (7%), and unprotected bare and coated steel (4%).

Northern Utilities’ New Hampshire division serving 21 communities has 500 miles of distribution gas mains and 21,110 service pipes. Northern Utilities’ Maine division serving 23 communities has 524 miles of distribution and 17,825 service pipes. Northern Utilities also owns a propane air gas plant and a LNG storage and vaporization facility.

Granite State is a natural gas transmission pipeline, regulated by the FERC, operating 86 miles of underground gas transmission pipeline located primarily in Maine and New Hampshire.

The Company believes that its facilities are currently adequate for their intended uses.

Item 3. | Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. The Company believes, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company’s financial position.

A putative class action complaint was filed against Fitchburg on January 7, 2009 in Worcester Superior Court in Worcester, Massachusetts, captioned Bellerman v. Fitchburg Gas and Electric Light Company. On April 1, 2009, an Amended Complaint was filed in Worcester Superior Court and served on Fitchburg. The Amended 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

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by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December, 2008. The Amended Complaint 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 Superior Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. The Company anticipates that the court will decide whether the lawsuit is appropriate for class action treatment in late 2012. The Company continues to believe the suit is without merit and will defend itself vigorously.

On November 2, 2011, the SJC issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered Fitchburg to refund $4.6 million of natural gas costs, plus interest. The MDPU’s original order issued in 2009 found that the Company had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU’s prior approval and that the Company’s natural gas purchasing practices were imprudent. The Company appealed the MDPU’s decision to the SJC. The SJC’s decision vacates the MDPU’s order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. See additional discussion below in Regulatory Matters.

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PART II

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

The Registrant’s common stock is listed on the New York Stock Exchange under the symbol “UTL.” As of December 31, 2011, there were 1,586 shareholders of record.

Common Stock Data

Dividends per Common Share |  | 2011 |  |  | 2010 |
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 below.

|  | 2011 |  |  | 2010 |
Price Range of Common Stock |  | High/Ask |  |  | Low/Bid |  |  | High/Ask |  |  | Low/Bid |
1st Quarter |  | $ | 23.94 |  |  | $ | 21.84 |  |  | $ | 24.40 |  |  | $ | 20.46 |
2nd Quarter |  | $ | 26.82 |  |  | $ | 23.12 |  |  | $ | 24.36 |  |  | $ | 19.28 |
3rd Quarter |  | $ | 26.82 |  |  | $ | 24.53 |  |  | $ | 22.99 |  |  | $ | 20.55 |
4th Quarter |  | $ | 28.60 |  |  | $ | 24.58 |  |  | $ | 23.49 |  |  | $ | 21.22 |

Information regarding Securities Authorized for Issuance Under Equity Compensation Plans, as of December 31, 2011, is set forth in the table below.

Equity Compensation Plan Benefit 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 |  |  |  |  |  |  |  |  |  |  |  |
Amended and Restated Unitil Corporation 2003 Stock Plan(1) |  |  | N/A |  |  |  | N/A |  |  |  | 38,460 |
Equity compensation plans not approved by security holders |  |  |  |  |  |  |  |  |  |  |  |
N/A |  |  | N/A |  |  |  | N/A |  |  |  | N/A |
Total |  |  | N/A |  |  |  | N/A |  |  |  | 38,460 |

NOTES: (also see Note 2 to the accompanying Consolidated Financial Statements)

(1) | The Amended and Restated Unitil Corporation 2003 Stock Plan (the Plan) was approved by shareholders in April 2003. 10,600 shares of restricted stock were awarded to Plan participants in May 2003; 10,700 shares of restricted stock were awarded to Plan participants in April 2004; 10,900 shares of restricted stock were awarded to Plan participants in March 2005; 14,375 shares of restricted stock were awarded to Plan participants in February 2006; 9,020 shares of restricted stock were awarded to Plan participants in February 2007; 15,540 shares of restricted stock were awarded to Plan participants in February 2008; 32,260 shares of restricted stock were awarded to Plan participants in February 2009; 12,520 shares of restricted stock were awarded to Plan participants in February 2010; 24,330 shares of restricted stock were awarded to Plan participants in February 2011.

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Stock Performance Graph

The following graph compares Unitil Corporation’s cumulative stockholder return since December 31, 2006 with the Peer Group index, comprised of the S&P 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, 2006.

Comparative Five-Year Total Returns

NOTE:

(1) | The graph above assumes $100 invested on December 31, 2006, in each category and the reinvestment of all dividends during the five-year period. The Peer Group is comprised of the S&P Utilities Index.

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Unregistered Sales of Equity Securities and Uses of Proceeds

There were no sales of unregistered equity securities by the Company for the fiscal period ended December 31, 2011.

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 24, 2011, 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. There is no pool or maximum number of shares related to these purchases; however, the trading plan will terminate when $224,500 in value of shares have been purchased or, if sooner, on March 24, 2012.

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.

|  | 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 |
10/1/11 – 10/31/11 |  |  | 7,838 |  |  | $ | 25.58 |  |  |  | 7,838 |  |  | $ | 13,132 |
11/1/11 – 11/30/11 |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 13,132 |
12/1/11 – 12/31/11 |  |  | 215 |  |  | $ | 27.80 |  |  |  | 215 |  |  | $ | 7,155 |
Total |  |  | 8,053 |  |  | $ | 25.64 |  |  |  | 8,053 |  |  |  |  |

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Item 6. | Selected Financial Data

For the Years Ended December 31, |  | 2011 |  |  | 2010 |  |  | 2009 |  |  | 2008 |  |  | 2007 |
(all data in millions except shares, % and per share data) (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consolidated Statements of Earnings: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating Revenue |  | $ | 352.8 |  |  | $ | 358.4 |  |  | $ | 367.0 |  |  | $ | 288.2 |  |  | $ | 262.9 |
Operating Income |  |  | 37.2 |  |  |  | 28.0 |  |  |  | 26.1 |  |  |  | 20.5 |  |  |  | 18.5 |
Other Non-operating Expense |  |  | 0.4 |  |  |  | 0.3 |  |  |  | 0.3 |  |  |  | 0.3 |  |  |  | 0.2 |
Income Before Interest Expense |  |  | 36.8 |  |  |  | 27.7 |  |  |  | 25.8 |  |  |  | 20.2 |  |  |  | 18.3 |
Interest Expense, net |  |  | 20.4 |  |  |  | 18.1 |  |  |  | 15.8 |  |  |  | 10.5 |  |  |  | 9.6 |
Net Income |  |  | 16.4 |  |  |  | 9.6 |  |  |  | 10.0 |  |  |  | 9.7 |  |  |  | 8.7 |
Dividends on Preferred Stock |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 0.1 |
Earnings Applicable to Common Shareholders |  | $ | 16.3 |  |  | $ | 9.5 |  |  | $ | 9.9 |  |  | $ | 9.6 |  |  | $ | 8.6 |
Balance Sheet Data (as of December 31,): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Utility Plant (Original Cost) |  | $ | 773.7 |  |  | $ | 728.4 |  |  | $ | 682.7 |  |  | $ | 641.4 |  |  | $ | 380.5 |
Total Assets |  | $ | 800.2 |  |  | $ | 759.6 |  |  | $ | 725.2 |  |  | $ | 733.2 |  |  | $ | 474.6 |
Capitalization: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common Stock Equity |  | $ | 191.7 |  |  | $ | 189.0 |  |  | $ | 193.1 |  |  | $ | 139.5 |  |  | $ | 100.4 |
Preferred Stock |  |  | 2.0 |  |  |  | 2.0 |  |  |  | 2.0 |  |  |  | 2.0 |  |  |  | 2.1 |
Long-Term Debt, less current portion |  |  | 287.8 |  |  |  | 288.3 |  |  |  | 248.9 |  |  |  | 249.3 |  |  |  | 159.6 |
Total Capitalization |  | $ | 481.5 |  |  | $ | 479.3 |  |  | $ | 444.0 |  |  | $ | 390.8 |  |  | $ | 262.1 |
Current Portion of Long-Term Debt |  | $ | 0.5 |  |  | $ | 0.5 |  |  | $ | 0.4 |  |  | $ | 0.4 |  |  | $ | 0.4 |
Short-term Debt |  | $ | 87.9 |  |  | $ | 66.8 |  |  | $ | 64.5 |  |  | $ | 74.1 |  |  | $ | 18.8 |
Capital Structure Ratios (as of December 31,): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common Stock Equity |  |  | 40 | % |  |  | 39 | % |  |  | 43 | % |  |  | 36 | % |  |  | 38 | %
Preferred Stock |  |  | 1 | % |  |  | 1 | % |  |  | 1 | % |  |  | 1 | % |  |  | 1 | %
Long-Term Debt |  |  | 59 | % |  |  | 60 | % |  |  | 56 | % |  |  | 63 | % |  |  | 61 | %
Earnings Per Share Data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Earnings Per Average Share |  | $ | 1.50 |  |  | $ | 0.88 |  |  | $ | 1.03 |  |  | $ | 1.65 |  |  | $ | 1.52 |
Common Stock Data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Shares of Common Stock—(Diluted Weighted Average Outstanding, 000’s) |  |  | 10,883 |  |  |  | 10,824 |  |  |  | 9,647 |  |  |  | 5,830 |  |  |  | 5,672 |
Dividends Paid Per Share |  | $ | 1.38 |  |  | $ | 1.38 |  |  | $ | 1.38 |  |  | $ | 1.38 |  |  | $ | 1.38 |
Book Value Per Share (Year-End) |  | $ | 17.50 |  |  | $ | 17.35 |  |  | $ | 17.83 |  |  | $ | 17.90 |  |  | $ | 17.50 |
Electric and Gas Sales: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric Distribution Sales (Millions kWh) |  |  | 1,682.1 |  |  |  | 1,691.1 |  |  |  | 1,618.8 |  |  |  | 1,695.9 |  |  |  | 1,743.0 |
Firm Natural Gas Distribution Sales (Millions Therms) |  |  | 186.9 |  |  |  | 172.9 |  |  |  | 178.7 |  |  |  | 47.2 |  |  |  | 28.4 |

(1) | As a result of the acquisitions of Northern Utilities and Granite State on December 1, 2008, consolidated results for the Company in the current period may not be directly comparable to some prior period results until such time as the acquisitions are fully reflected in all reporting periods.

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Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) (Note references are to Notes to the Consolidated Financial Statements in Item 8.)

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. On December 1, 2008, the Company purchased: (i) all of the outstanding capital stock of Northern Utilities, a natural gas distribution utility serving customers in New Hampshire and Maine, from Bay State and (ii) all of the outstanding capital stock of Granite State, an interstate natural gas transmission pipeline company from NiSource.

Unitil’s principal business is the local distribution of electricity and natural gas 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 101,400 electric customers and 71,900 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 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 $510.7 million at December 31, 2011. Unitil’s total revenue was $352.8 million in 2011, 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 $5.5 million in 2011. The Company’s other subsidiaries include Unitil Service, which provides, at cost, a variety of administrative and professional services to Unitil’s affiliated companies, and Unitil Realty, which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

Regulation

Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities are also regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the Massachusetts Department of Public Utilities (MDPU); and Northern Utilities is regulated

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by the NHPUC and Maine Public Utilities Commission (MPUC). Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under 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. As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, 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.

In 2011, the Company completed base rate cases for: Unitil Energy; the electric and gas divisions of Fitchburg; the Maine division of Northern Utilities; and Granite State. The completion of these rate cases resulted in increases in annual distribution revenues of: $10.2 million for Unitil Energy; $3.3 million and $3.7 million for the electric and gas divisions of Fitchburg, respectively; $7.8 million for the Maine Division of Northern Utilities. Granite State received approval for an increase of $2.2 million in annual revenue. The New Hampshire division of Northern Utilities requested an increase of $5.2 million in annual distribution revenues in its base rate case filing. The Company is currently in settlement discussions with the NHPUC regarding its base rate case filing for Northern Utilities’ New Hampshire division and a final rate order is expected in the first quarter 2012. See “Rate Case Activity” in Part I, Item 1 for additional information on these rate cases.

On August 1, 2011, the MDPU issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of the Company’s Massachusetts combination electric and natural gas distribution utility, 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 estimates that RDM applies to approximately 25% and 10% of Unitil’s total 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.

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, 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 Company’s future operations, 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

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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 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.

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. 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.

See also Item 1A Risk Factors.

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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 Item 8 of this report.

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.

Net Income and EPS Overview

2011 Compared to 2010—The Company’s Earnings Applicable to Common Shareholders (Earnings) were $16.3 million, or $1.50 per share, for the full year of 2011, an increase of $6.8 million, or $0.62 per share, over 2010, reflecting higher natural gas and electric sales margins partially offset by higher utility operating and interest costs. The Company’s Earnings were $10.0 million, or $0.92 per share, for the fourth quarter of 2011, compared to Earnings of $5.2 million, or $0.48 per share, in the fourth quarter of 2010. The results include a non-recurring pre-tax credit of $4.7 million recorded in the fourth quarter of 2011 in connection with the Company’s court appeal and the resulting favorable ruling vacating a 2009 regulatory order that had resulted in the previous charge off of Purchased Gas costs. Also included in the 2011 full year results is a non-recurring pre-tax charge of $2.0 million recorded in the third quarter, related to the resolution of the 2008 ice storm cost recovery in the Company’s Massachusetts base rate case.

Natural gas sales margin increased $11.1 million in 2011 compared to 2010, reflecting an increase in gas unit sales, higher gas distribution rates and the recovery of Purchased Gas costs that had previously been charged off in a prior period. Total natural gas therm unit sales increased 8.1% in 2011 compared to 2010. The increase in gas therm sales reflects the addition of new residential and commercial and industrial (C&I) business customers during the year, increased gas usage and colder weather in 2011 compared to 2010, particularly in the first quarter of 2011. Heating Degree Days in 2011 were 3.8% greater than in 2010. On a weather-normalized basis, natural gas therm sales in 2011 increased 7.0% compared to 2010 due to new customer growth and increased gas usage.

Electric sales margin increased $7.6 million in 2011 compared to 2010, reflecting higher electric distribution rates on lower unit sales. Total electric kilowatt hour (kWh) unit sales decreased 0.5% in 2011 compared to 2010 reflecting slightly higher sales to residential customers offset by lower sales to C&I business customers. The increased sales to residential customers reflect customer growth partially offset by the effect of the weather in 2011 compared to 2010. There were 14.6% fewer Cooling Degree Days in 2011 compared to 2010. On a weather-normalized basis, kWh sales in 2011 increased 0.4% compared to 2010.

Total Operation & Maintenance (O&M) expenses increased $2.7 million, or 5.5%, in 2011 compared to 2010. The changes in O&M expenses reflect higher utility operating costs of $1.9 million and higher employee compensation and benefit costs of $1.8 million, partially offset by a credit of $1.0 million for proceeds from insurance related settlements. Utility operating costs in 2011 include approximately $1.7 million of spending on vegetation management and reliability enhancement programs. These costs are recovered through cost tracker rate mechanisms that result in corresponding increases in revenue.

Depreciation and Amortization expense increased $0.4 million in 2011 compared to 2010 reflecting normal utility plant additions, amortization of previously deferred storm charges and changes in depreciation rates resulting from the Company’s recently completed base rate cases.

Local Property and Other Taxes increased $1.8 million in 2011 compared to 2010. This increase reflects higher state and local property tax rates on higher levels of utility plant in service.

Federal and State Income Taxes increased $5.5 million in 2011 due to higher pre-tax earnings in 2011 compared to 2010.

Other Non-operating Expenses increased $0.1 million in 2011 compared to 2010.

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Interest Expense, net increased $2.3 million in 2011 compared to 2010 due to lower interest income recorded on regulatory assets, including a non-recurring pre-tax charge, in the third quarter of 2011, against interest income of $1.8 million related to the final regulatory order issued in the Company’s Massachusetts base rate case. Interest expense also reflects the issuance of a total of $40 million of long-term notes by two of the Company’s operating utilities, Unitil Energy and Northern Utilities, in March 2010.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $5.5 million in 2011, an increase of $0.9 million compared to 2010, and contributed $0.15 per share to Earnings in 2011. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered the Company’s electric and natural gas distribution utility, Fitchburg, to refund $4.6 million of natural gas costs, plus interest. The MDPU’s original order, issued in 2009, found that Fitchburg had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU’s prior approval and that Fitchburg’s natural gas purchasing practices were imprudent. The Company appealed the MDPU’s decision to the SJC. The SJC’s decision vacates the MDPU’s refund amount of $4.6 million, plus interest, in favor of a refund amount of $0.2 million, plus interest. The Company had previously recorded a pre-tax charge to earnings and recognized a Regulatory Liability of $4.9 million in the fourth quarter of 2009 based on the MDPU’s original order. As a result of the decision, the Regulatory Liability has been adjusted and the Company recognized a pre-tax credit of $4.7 million in the fourth quarter of 2011. This credit is recognized on the Company’s 2011 Consolidated Statement of Earnings as a $4.5 million reduction in Purchased Gas expense and a reduction of $0.2 million in Interest Expense, net.

In 2011, 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, 2012 meeting, the Unitil Board of Directors declared a quarterly dividend on the Company’s common stock of $0.345 per share.

2010 Compared to 2009—The Company’s Earnings Applicable to Common Shareholders was $9.5 million, or $0.88 per share, for 2010, compared to $9.9 million, or $1.03 per share, for 2009. The lower earnings in 2010 compared to 2009 reflect higher operating and interest expenses in 2010.

A more detailed discussion of the Company’s 2011 and 2010 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 8.1% in 2011 compared to 2010. The increase in gas therm sales reflects the addition of new residential and C&I business customers during the year, increased gas usage and colder weather in 2011 compared to 2010, particularly in the first quarter of 2011. Heating Degree Days in 2011 were 3.8% greater than in 2010. On a weather-normalized basis, natural gas therm sales in 2011 increased 7.0% compared to 2010 due to new customer growth and increased gas usage.

As discussed above, under revenue decoupling for the Company’s Massachusetts combination electric and natural gas distribution utility, Fitchburg, distribution revenues, which are included in sales margin, will be recognized in the Company’s Consolidated Statements of Earnings from August 1, 2011 forward, on established revenue targets and will no longer be dependent on sales volumes. In 2011, approximately 3% of the Company’s gas therm sales were decoupled.

Unitil’s total therm sales of natural gas decreased 3.2% in 2010 compared to 2009. Lower gas therm sales in the Company’s utility service territories reflect the effect of milder winter temperatures in the early part of 2010 compared to 2009. Heating Degree Days in 2010 were 9% fewer than in the prior year. On a weather-normalized basis, natural gas therm sales in 2010 were essentially flat compared to 2009.

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

Therm Sales (millions) |  |  |  |  |  |  |  |  |  |  | Change |
|  |  |  |  |  |  |  |  |  |  | 2011 vs. 2010 |  |  | 2010 vs. 2009 |
|  | 2011 |  |  | 2010 |  |  | 2009 |  |  | Therms |  |  | % |  |  | Therms |  |  | % |
Residential |  |  | 37.7 |  |  |  | 35.1 |  |  |  | 36.7 |  |  |  | 2.6 |  |  |  | 7.4 | % |  |  | (1.6 | ) |  |  | (4.4 | %)
Commercial / Industrial |  |  | 149.2 |  |  |  | 137.8 |  |  |  | 142.0 |  |  |  | 11.4 |  |  |  | 8.3 | % |  |  | (4.2 | ) |  |  | (3.0 | %)
Total Therm Sales |  |  | 186.9 |  |  |  | 172.9 |  |  |  | 178.7 |  |  |  | 14.0 |  |  |  | 8.1 | % |  |  | (5.8 | ) |  |  | (3.2 | %)

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

Gas Operating Revenues and Sales Margin (millions) |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  | Change |
|  |  |  |  |  |  |  |  |  |  | 2011 vs. 2010 |  |  | 2010 vs. 2009 |
|  | 2011 |  |  | 2010 |  |  | 2009 |  |  | $ |  |  | %(1) |  |  | $ |  |  | %(1) |
Gas Operating Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 65.1 |  |  | $ | 61.5 |  |  | $ | 62.0 |  |  | $ | 3.6 |  |  |  | 2.4 | % |  | $ | (0.5 | ) |  |  | (0.3 | %)
Commercial / Industrial |  |  | 94.1 |  |  |  | 88.6 |  |  |  | 90.8 |  |  |  | 5.5 |  |  |  | 3.7 | % |  |  | (2.2 | ) |  |  | (1.4 | %)
Total Gas Operating Revenue |  | $ | 159.2 |  |  | $ | 150.1 |  |  | $ | 152.8 |  |  | $ | 9.1 |  |  |  | 6.1 | % |  | $ | (2.7 | ) |  |  | (1.7 | %)
Cost of Gas Sales: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchased Gas |  | $ | 89.1 |  |  | $ | 90.5 |  |  | $ | 96.4 |  |  | $ | (1.4 | ) |  |  | (0.9 | %) |  | $ | (5.9 | ) |  |  | (3.8 | %)
Conservation & Load Management |  |  | 2.2 |  |  |  | 2.8 |  |  |  | 1.9 |  |  |  | (0.6 | ) |  |  | (0.4 | %) |  |  | 0.9 |  |  |  | 0.6 | %
Total Cost of Gas Sales |  | $ | 91.3 |  |  | $ | 93.3 |  |  | $ | 98.3 |  |  | $ | (2.0 | ) |  |  | (1.3 | %) |  | $ | (5.0 | ) |  |  | (3.2 | %)
Gas Sales Margin |  | $ | 67.9 |  |  | $ | 56.8 |  |  | $ | 54.5 |  |  | $ | 11.1 |  |  |  | 7.4 | % |  | $ | 2.3 |  |  |  | 1.5 | %

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

Total Gas Operating Revenues increased $9.1 million, or 6.1%, in 2011 compared to 2010. Total Gas Operating Revenues include the recovery of the approved cost of sales, which are recorded as Purchased Gas and Conservation and Load Management (C&LM) in Operating Expenses. The increase in Total Gas Operating Revenues in 2011 reflects higher sales margin of $11.1 million partially offset by lower Purchased Gas revenues of $1.4 million and lower C&LM revenues of $0.6 million.

The Purchased Gas and C&LM components of Total Gas Operating Revenue decreased a combined $2.0 million, or 1.3%, of Total Gas Operating Revenues in 2011 compared to 2010, primarily reflecting the recovery of $4.5 million of Purchased Gas costs that had previously been charged off in a prior period, discussed above, lower natural gas commodity costs and an increase in the amount of natural gas purchased by customers directly from third-party suppliers, partially offset by higher sales of natural gas. Purchased Gas revenues include the recovery of the approved cost of gas supply as well as other energy supply related costs. C&LM revenues include the recovery of the cost of energy efficiency and conservation programs. The Company recovers the approved cost of Purchased Gas and C&LM in its rates at cost on a pass through basis.

Natural gas sales margin increased $11.1 million in 2011 compared to 2010, reflecting increased sales of $4.0 million, higher gas distribution rates of $2.6 million and the recovery of $4.5 million of Purchased Gas costs that had previously been charged off in a prior period, discussed above.

Total Gas Operating Revenues decreased $2.7 million, or 1.7%, in 2010 compared to 2009. The decrease in Total Gas Operating Revenues in 2010 reflects lower Purchased Gas costs of $5.9 million partially offset by higher C&LM revenues of $0.9 million and higher sales margin of $2.3 million.

Natural gas sales margin increased $2.3 million in 2010 compared to 2009, reflecting the effect of the ordered refund of $4.9 million of natural gas supply costs recorded in 2009, discussed above. Absent the effect of this refund, natural gas sales margin decreased $2.6 million in 2010 compared to 2009, principally due to lower sales of natural gas, which reflect the effect of the milder winter heating season in the early part of 2010 compared to 2009.

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Electric Sales, Revenues and Margin

Kilowatt-hour Sales—Unitil’s total electric kWh sales decreased 0.5% in 2011 compared to 2010 reflecting slightly higher sales to residential customers offset by lower sales to C&I business customers. The increased sales to residential customers reflect customer growth partially offset by the effect of the weather in 2011 compared to 2010. There were 14.6% fewer Cooling Degree Days in 2011 compared to 2010. On a weather-normalized basis, kWh sales in 2011 increased 0.4% compared to 2010.

As discussed above, under revenue decoupling for the Company’s Massachusetts combination electric and natural gas distribution utility, Fitchburg, distribution revenues, which are included in sales margin, will be recognized in the Company’s Consolidated Statements of Earnings from August 1, 2011 forward, on established revenue targets and will no longer be dependent on sales volumes. In 2011, approximately 10% of the Company’s electric kWh sales were decoupled from revenue and sales margin.

Unitil’s total electric kWh sales increased 4.5% in 2010 compared to 2009. Electric kWh sales to residential customers and C&I customers increased 5.5% and 3.8%, respectively, in 2010 compared to 2009. The increased sales reflect higher than average summer temperatures in the Company’s utility service territories in 2010 where there were approximately 61% more Cooling Degree Days in the three month period ended September 30, 2010, compared to the prior year, coupled with an improving regional economy. According to ISO-New England, the regional transmission operator in New England, July of 2010 was the second-hottest July in New England since 1960 and New England’s all-time electricity consumption for one month was recorded in that month. On a weather-normalized basis, kWh sales in 2010 increased 1.6% compared to 2009.

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

kWh Sales (millions) |  |  |  |  |  |  |  |  |  |  | Change |
|  |  |  |  |  |  |  |  |  |  | 2011 vs. 2010 |  |  | 2010 vs. 2009 |
|  | 2011 |  |  | 2010 |  |  | 2009 |  |  | kWh |  |  | % |  |  | kWh |  |  | % |
Residential |  |  | 682.8 |  |  |  | 681.2 |  |  |  | 645.9 |  |  |  | 1.6 |  |  |  | 0.2 | % |  |  | 35.3 |  |  |  | 5.5 | %
Commercial / Industrial |  |  | 999.3 |  |  |  | 1,009.9 |  |  |  | 972.9 |  |  |  | (10.6 | ) |  |  | (1.0 | %) |  |  | 37.0 |  |  |  | 3.8 | %
Total kWh Sales |  |  | 1,682.1 |  |  |  | 1,691.1 |  |  |  | 1,618.8 |  |  |  | (9.0 | ) |  |  | (0.5 | %) |  |  | 72.3 |  |  |  | 4.5 | %

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

Electric Operating Revenues (millions) |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  | Change |
|  |  |  |  |  |  |  |  |  |  | 2011 vs. 2010 |  |  | 2010 vs. 2009 |
|  | 2011 |  |  | 2010 |  |  | 2009 |  |  | $ |  |  | %(1) |  |  | $ |  |  | %(1) |
Electric Operating Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 100.8 |  |  | $ | 108.5 |  |  | $ | 108.9 |  |  | $ | (7.7 | ) |  |  | (3.8 | %) |  | $ | (0.4 | ) |  |  | (0.2 | %)
Commercial / Industrial |  |  | 87.3 |  |  |  | 95.2 |  |  |  | 101.0 |  |  |  | (7.9 | ) |  |  | (3.9 | %) |  |  | (5.8 | ) |  |  | (2.7 | %)
Total Electric Operating Revenue |  | $ | 188.1 |  |  | $ | 203.7 |  |  | $ | 209.9 |  |  | $ | (15.6 | ) |  |  | (7.7 | %) |  | $ | (6.2 | ) |  |  | (2.9 | %)
Cost of Electric Sales: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchased Electricity |  | $ | 114.2 |  |  | $ | 137.7 |  |  | $ | 151.6 |  |  | $ | (23.5 | ) |  |  | (11.5 | %) |  | $ | (13.9 | ) |  |  | (6.6 | %)
Conservation & Load Management |  |  | 6.3 |  |  |  | 6.0 |  |  |  | 3.1 |  |  |  | 0.3 |  |  |  | 0.1 | % |  |  | 2.9 |  |  |  | 1.4 | %
Total Cost of Electric Sales |  | $ | 120.5 |  |  | $ | 143.7 |  |  | $ | 154.7 |  |  | $ | (23.2 | ) |  |  | (11.4 | %) |  | $ | (11.0 | ) |  |  | (5.2 | %)
Electric Sales Margin |  | $ | 67.6 |  |  | $ | 60.0 |  |  | $ | 55.2 |  |  | $ | 7.6 |  |  |  | 3.7 | % |  | $ | 4.8 |  |  |  | 2.3 | %

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

Total Electric Operating Revenues decreased $15.6 million, or 7.7%, in 2011 compared to 2010. Total Electric Operating Revenues include the recovery of approved costs of electric sales, which are recorded as Purchased Electricity and C&LM in Operating Expenses. The net decrease in Total Electric Operating Revenues in 2011 reflects lower Purchased Electricity revenues of $23.5 million partially offset by higher C&LM revenues of $0.3 million and higher sales margin of $7.6 million.

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The Purchased Electricity and C&LM components of Total Electric Operating Revenue decreased a combined $23.2 million, or 11.4%, of Total Electric Operating Revenues in 2011 compared to 2010, primarily reflecting lower electric commodity costs and an increase in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by higher spending on energy efficiency and conservation programs. Purchased Electricity revenues include the recovery of the cost of electric supply as well as other energy supply related restructuring costs, including long-term power supply contract buyout costs. C&LM revenues include the recovery of the approved cost of energy efficiency and conservation programs. The Company recovers the approved cost of Purchased Electricity and C&LM in its rates at cost on a pass through basis.

Electric sales margin increased $7.6 million in 2011 compared to 2010, reflecting higher electric distribution rates of $7.8 million, partially offset by reduced margins on lower unit sales of ($0.2 million).

Total Electric Operating Revenues decreased $6.2 million, or 2.9%, in 2010 compared to 2009. The net decrease in Total Electric Operating Revenues in 2010 reflects lower Purchased Electricity costs of $13.9 million offset by higher C&LM revenues of $2.9 million and higher sales margin of $4.8 million.

Electric sales margin increased $4.8 million in 2010 compared to 2009. The increase in electric sales margin reflects higher electric kWh sales and an electric rate increase, implemented in July 2010 for the Company’s New Hampshire electric distribution utility.

Operating Revenue—Other

Total Other Revenue increased $0.9 million in 2011 compared to 2010 and $0.3 million in 2010 compared to 2009. These increases were the result of growth in revenues from the Company’s non-regulated energy brokering business, Usource. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

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

Other Revenue (millions) |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  | Change |
|  |  |  |  |  |  |  |  |  |  | 2011 vs. 2010 |  |  | 2010 vs. 2009 |
|  | 2011 |  |  | 2010 |  |  | 2009 |  |  | $ |  |  | % |  |  | $ |  |  | % |
Usource |  | $ | 5.5 |  |  | $ | 4.6 |  |  | $ | 4.3 |  |  | $ | 0.9 |  |  |  | 19.6 | % |  | $ | 0.3 |  |  |  | 7.0 | %
Total Other Revenue |  | $ | 5.5 |  |  | $ | 4.6 |  |  | $ | 4.3 |  |  | $ | 0.9 |  |  |  | 19.6 | % |  | $ | 0.3 |  |  |  | 7.0 | %

Operating Expenses

Purchased Gas—Purchased Gas includes the cost of natural gas purchased and manufactured to supply the Company’s total gas supply requirements. Purchased Gas decreased $1.4 million, or 1.6%, in 2011 compared to 2010. This decrease reflects a credit of $4.5 million for the recovery of Purchased Gas costs that had previously been charged off in a prior period, discussed above, lower natural gas commodity costs and an increase in the amount of natural gas purchased by customers directly from third-party suppliers, partially offset by higher sales of natural gas. The Company recovers the approved costs of Purchased Gas in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

In 2010, Purchased Gas decreased $5.9 million, or 6.1%, compared to 2009. This decrease reflects the effect of the ordered refund of $4.9 million of Purchased Gas costs recorded in 2009, discussed above. Absent the effect of this refund, Purchased Gas decreased $1.0 million in 2010 compared to 2009, principally due to lower sales of natural gas, which reflect the effect of the milder winter heating season in the early part of 2010 compared to 2009, partially offset by higher natural gas commodity prices in 2010.

Purchased Electricity—Purchased Electricity includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs. Purchased Electricity decreased $23.5 million, or 17.1%, in 2011 compared to 2010. This decrease primarily reflects lower electric commodity costs and an increase in the amount of electricity purchased by customers directly from

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third-party suppliers. The Company recovers the approved costs of Purchased Electricity in its rates at cost and therefore changes in approved expenses do not affect earnings.

In 2010, Purchased Electricity expenses decreased $13.9 million, or 9.2%, compared to 2009, reflecting an increase in the amount of electricity purchased by customers directly from third-party suppliers and lower electric commodity costs, partially offset by increased sales.

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 $2.7 million, or 5.5%, in 2011 compared to 2010. The changes in O&M expenses reflect higher utility operating costs of $1.9 million and higher employee compensation and benefit costs of $1.8 million, partially offset by a credit of $1.0 million for proceeds from insurance related settlements. Utility operating costs primarily consist of utility distribution and transmission system maintenance costs, bad debt expenses, office expenses and insurance costs. Utility operating costs in 2011 include approximately $1.7 million of spending on vegetation management and reliability enhancement programs. These costs are recovered through cost tracker rate mechanisms that result in corresponding increases in revenue.

In 2010, total O&M expense increased $4.1 million, or 9.2%, compared to 2009. The changes in O&M expenses reflect higher compensation and benefit expenses of $2.7 million and higher utility operating costs of $1.4 million. O&M expenses in 2010 reflect the full integration of Northern Utilities and Granite State into the Company’s consolidated operating results.

Conservation & Load Management—C&LM expenses are expenses associated with the development, management, and delivery of the Company’s energy efficiency programs. Energy efficiency programs are designed, in conformity to state regulatory requirements, to help consumers use natural gas and electricity more efficiently and thereby decrease their energy costs. Programs are tailored to residential, small business and large business customer groups and provide educational materials, technical assistance, and rebates that contribute toward the cost of purchasing and installing approved measures. Approximately 74% of these costs are related to electric operations and 26% to gas operations.

Total Conservation & Load Management expenses decreased $0.3 million, in 2011 compared to 2010. These costs are collected from customers on a fully reconciling basis and therefore, fluctuations in program costs do not affect earnings.

Total Conservation & Load Management expenses increased $3.8 million in 2010 compared to 2009.

Depreciation and Amortization—Depreciation and Amortization expense increased $0.4 million, or 1.4%, in 2011 compared to 2010 reflecting normal utility plant additions, amortization of previously deferred storm charges and changes in depreciation rates resulting from the Company’s recently completed base rate cases.

In 2010, Depreciation and Amortization expense increased $1.5 million, or 5.5%, compared to 2009. This increase reflects higher depreciation on normal utility plant additions partially offset by lower amortization expense in the current year.

Local Property and Other Taxes—Local Property and Other Taxes increased $1.8 million, or 16.1%, in 2011 compared to 2010. This increase reflects higher state and local property tax rates on higher levels of utility plant in service.

In 2010, Local Property and Other Taxes increased $0.8 million, or 7.7%, compared to 2009. This increase reflects higher state and local property tax rates on higher levels of utility plant in service and higher payroll taxes on higher compensation expenses.

Federal and State Income Taxes—Federal and State Income Taxes increased $5.5 million in 2011 compared to 2010 due to higher pre-tax earnings in 2011 compared to 2010 (See Note 7 to the accompanying Consolidated Financial Statements).

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Federal and State Income Taxes decreased $0.9 million in 2010 compared to 2009 due to lower pre-tax operating income in 2010 compared to 2009 (See Note 7 to the accompanying Consolidated Financial Statements).

Other Non-operating Expenses (Income)—Other Non-operating Expenses (Income) increased $0.1 million in 2011 compared to 2010 and was flat in 2010 compared to 2009.

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 3 to the accompanying Consolidated Financial Statements).

Interest Expense, net increased $2.3 million in 2011 compared to 2010 due to lower interest income recorded on regulatory assets, including a non-recurring pre-tax charge, in the third quarter of 2011, against interest income of $1.8 million related to the final regulatory order issued in the Company’s Massachusetts base rate case. Interest expense also reflects the issuance of a total of $40 million of long-term notes by two of the Company’s operating utilities, Unitil Energy and Northern Utilities, in March 2010.

In 2010, Interest Expense, net increased $2.3 million compared to 2009. In March 2010, Unitil Energy and Northern Utilities collectively issued $40 million of long-term debt which contributed to the higher interest expense in 2010.

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 and future 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, with respect to public offerings of securities, the Company files registration statements with the Securities and Exchange Commission under the Securities Act of 1933, as amended. 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, along with its subsidiaries, are individually and collectively members of the Unitil Cash Pool (the Cash Pool). The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool allows for an efficient exchange of cash among the Company and its subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on actual interest costs from lenders under the Company’s revolving credit facility. At December 31, 2011 and 2010, all of the Company’s subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

Unitil has a revolving credit facility with a group of banks that extends to October 8, 2013. The borrowing limit under the revolving credit facility was $115.0 million at December 31, 2011 and $80.0 million at December 31, 2010. There was $87.9 million and $66.8 million in short-term debt outstanding through bank borrowings under the revolving credit facility at December 31, 2011 and 2010, respectively. The total amount of credit available under the Company’s revolving credit facility was $27.1 million and $13.2 million at December 31, 2011 and 2010, respectively. The revolving credit facility contains customary terms and conditions for credit facilities of this type, including, without limitation, covenants restricting the Company’s ability to incur liens, merge or consolidate with another entity or change its line of business. The revolving credit agreement also contains a covenant restricting the Company’s ability to

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permit funded debt to exceed 65% of capitalization at the end of each fiscal quarter. As of December 31, 2011 and 2010, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

On October 12, 2011, Unitil entered into the Fifth Amendment agreement with Bank of America, N.A., as administrative agent, and a syndicate of other lenders party thereto, further amending the revolving credit agreement dated as of November 26, 2008. The revolving credit agreement was previously amended on January 2, 2009, March 16, 2009, October 13, 2009 and October 8, 2010 to, among other things, increase the maximum borrowings under the facility, provide for a base rate interest rate option, reflect letter of credit availability, modify certain financial reporting requirements and extend the scheduled termination date of the facility. The Fifth Amendment agreement increased the maximum borrowings under the facility to $115 million, changed the additional interest margin applicable to borrowings at a fluctuating rate of interest per annum equal to the daily London Interbank Offered Rate from 2.00% to 1.75%, and changed the annual letter of credit fee from 1.625% of the daily amount available to be drawn under letters of credit issued under the credit facility to 1.500% of such daily amount. Also, see Credit Arrangements in Note 3.

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, 2011.

|  |  |  |  | Payments Due by Period |
Significant Contractual Obligations (millions) as of December 31, 2011 |  | Total |  |  | 2012 |  |  | 2013- 2014 |  |  | 2015- 2016 |  |  | 2017 & Beyond |
Long-term Debt |  | $ | 288.3 |  |  | $ | 0.5 |  |  | $ | 3.0 |  |  | $ | 21.5 |  |  | $ | 263.3 |
Interest on Long-term Debt |  |  | 264.0 |  |  |  | 19.9 |  |  |  | 39.8 |  |  |  | 39.1 |  |  |  | 165.2 |
Gas Supply Contracts |  |  | 252.8 |  |  |  | 43.1 |  |  |  | 78.8 |  |  |  | 73.7 |  |  |  | 57.2 |
Power Supply Contract Obligations |  |  | 12.9 |  |  |  | 8.7 |  |  |  | 1.7 |  |  |  | 0.9 |  |  |  | 1.6 |
Other |  |  | 5.0 |  |  |  | 2.0 |  |  |  | 2.1 |  |  |  | 0.7 |  |  |  | 0.2 |
Total Contractual Cash Obligations |  | $ | 823.0 |  |  | $ | 74.2 |  |  | $ | 125.4 |  |  | $ | 135.9 |  |  | $ | 487.5 |

The Company and its subsidiaries have material energy supply commitments that are discussed in Note 5 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, 2011, there were approximately $37.2 million of guarantees outstanding and the longest term guarantee extends through February 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 $14.9 million and $11.7 million outstanding at December 31, 2011 and 2010, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2011, which was payable in January 2012, is $2.5 million and recorded in Accounts Payable at December 31, 2011. The amount of natural gas inventory released in December 2010, which was payable in January 2011, is $3.9 million and recorded in Accounts Payable at December 31, 2010.

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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, 2011, the principal amount outstanding for the 8% Unitil Realty notes was $3.3 million, and the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

Benefit Plan Funding

The Company, along with its subsidiaries, made cash contributions to its Pension Plan in the amount of $8.8 million and $4.3 million in 2011 and 2010, respectively. The Company, along with its subsidiaries, contributed $3.5 million to Voluntary Employee Benefit Trusts (VEBT) in 2010. No contributions were made to the VEBTs in 2011. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan and the VEBTs in 2012 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 9 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 3 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 2011 and 2010.

|  | 2011 |  |  | 2010 |
Cash Provided by Operating Activities |  | $ | 45.9 |  |  | $ | 25.9 |

Cash Provided by Operating Activities—Cash Provided by Operating Activities was $45.9 million in 2011, an increase of $20.0 million over 2010. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes, was $54.4 million in 2011 compared to $49.0 million in 2010, representing an increase of $5.4 million. Working capital changes in Current Assets and Liabilities resulted in a ($13.7) million net use of cash in 2011, compared to a ($12.1) million net use of cash in 2010. Deferred Regulatory and Other Charges resulted in a $7.5 million source of cash in 2011, compared to a ($4.5) million use of cash in 2010. All Other, net operating activities resulted in a use of cash of $(2.3) million in 2011 compared to a use of cash of ($6.5) million in 2010.

|  | 2011 |  |  | 2010 |
Cash (Used in) Investing Activities |  | $ | (57.1 | ) |  | $ | (49.6 | )

Cash (Used in) Investing Activities—Cash Used in Investing Activities was ($57.1) million for 2011 compared to ($49.6) million in 2010. The capital spending in both periods is representative of normal distribution utility capital expenditures reflecting normal electric and gas utility system additions. Capital expenditures are projected to be approximately ($59) million in 2012.

|  | 2011 |  |  | 2010 |
Cash Provided by Financing Activities |  | $ | 9.8 |  |  | $ | 24.9 |

Cash Provided by Financing Activities—Cash Provided by Financing Activities was $9.8 million in 2011 compared to $24.9 million in 2010. In 2011, sources of cash from financing activities included proceeds from issuance of short-term debt of $21.1 million, an increase in gas inventory financing of $4.6

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million and the issuance of common stock of $1.0 million. Uses of cash included regular quarterly dividend payments on common and preferred stock of ($15.2) million, payment of long term debt of ($0.5) million and all other financing activities which resulted in a use of ($1.2) million.

FINANCIAL COVENANTS AND RESTRICTIONS

The agreements under which the Company’s and its subsidiaries’ long-term debt 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 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 3 to the accompanying Consolidated Financial Statements.)

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

The Company’s revolving credit facility contains customary terms and conditions for credit facilities of this type, including certain financial covenants, including, without limitation, covenants restricting the Company’s ability to incur liens, merge or consolidate with another entity or change its line of business. The revolving credit agreement also contains a covenant restricting the Company’s ability to permit funded debt to exceed 65% of capitalization at the end of each fiscal quarter.

The Company and its subsidiaries are currently in compliance with all such covenants in these debt instruments.

DIVIDENDS

Unitil’s annualized common dividend was $1.38 per common share in 2011, 2010 and 2009. 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, 2012 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.

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.

A putative class action complaint was filed against Fitchburg on January 7, 2009 in Worcester Superior Court in Worcester, Massachusetts, captioned Bellerman v. Fitchburg Gas and Electric Light Company. On April 1, 2009, an Amended Complaint was filed in Worcester Superior Court and served on Fitchburg. The Amended 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 Amended Complaint 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 Superior Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. The Company anticipates that the court will decide whether the lawsuit is appropriate for class action treatment in late 2012. The Company continues to believe the suit is without merit and will defend itself vigorously.

On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered Fitchburg to refund $4.6

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million of natural gas costs, plus interest. The MDPU’s original order issued in 2009 found that the Company had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU’s prior approval and that the Company’s natural gas purchasing practices were imprudent. The Company appealed the MDPU’s decision to the SJC. The SJC’s decision vacates the MDPU’s order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. See additional discussion below in Regulatory Matters.

REGULATORY MATTERS

Overview (Unitil Energy, Fitchburg, and Northern Utilities)—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. 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, 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 remaining balance of these assets, to be recovered principally over the next one to three years, is $34.7 million as of December 31, 2011 including $12.4 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.

Fitchburg—Increase in Base Rates Approved—On August 1, 2011, the MDPU issued an order approving increases of $3.3 million and $3.7 million in annual distribution revenues for Fitchburg’s electric and gas divisions, respectively. The MDPU also approved revenue decoupling mechanisms and a return on equity of 9.2% for both the electric and gas divisions of Fitchburg. The rate increase for Fitchburg’s electric division included the recovery of $11.4 million of previously deferred emergency storm restoration costs associated with the December 2008 ice storm, which costs are to be amortized and recovered over seven (7) years without carrying costs. The order provides resolution to the open regulatory matters concerning the ratemaking treatment and cost recovery related to the December 2008 ice storm event.

Granite State—Increase in Base Rates Approved—On January 31, 2011, the FERC approved a settlement agreement providing for an increase of $1.7 million in annual revenue, based on new gas transportation rates to be effective January 1, 2011. Subsequently, on August 31, 2011, the FERC approved an amendment to the settlement agreement which provides for an additional increase of approximately $0.5 million in Granite State’s annual revenues effective August 1, 2011. Under the amended settlement agreement, beginning in 2012, Granite State is permitted to file limited annual rate adjustment filings to recover the revenue requirements for certain specified future capital cost additions to transmission plant projects. The limited rate adjustments would be effective August 1 of each year, and are projected to conclude in 2014 when the major projects will be completed. The annual revenue increases for the limited rate adjustments are estimated to be approximately $0.5 million each year during 2012 through 2014.

Unitil Energy—Increase in Base Rates Approved—On April 26, 2011, the NHPUC approved a final rate settlement which makes permanent a temporary increase of $5.2 million in annual revenue effective July 1, 2010, and provides for an additional increase of $5.0 million in annual revenue effective May 1, 2011.

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The settlement extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with estimated future increases of $1.5 million to $2.0 million in annual revenue to occur on May 1, 2012, May 1, 2013 and May 1, 2014, to support Unitil Energy’s continued capital improvements to its distribution system. The rate plan allows Unitil to file for additional rate relief if its return on equity is less than 7% and a sharing of earnings with customers if its return on equity is greater than 10% in a calendar year. The settlement provides for a return on equity of 9.67%, a common equity ratio of 45.45% and an overall weighted cost of capital of 8.39% to determine changes to distribution rate levels.

The settlement approved Unitil Energy’s proposal for an augmented vegetation management program and reliability enhancement program. Under the augmented vegetation management program, Unitil Energy will be increasing its vegetation management spending from a test-year spending level of approximately $0.7 million to $3.1 million per year by 2013. Under the new reliability enhancement program, Unitil Energy will spend $1.8 million annually towards targeted projects designed to enhance system reliability. The funding for both of these programs is included in the future rate increases discussed above.

The settlement provides for recovery of deferred December 2008 ice storm and February 2010 wind storm costs of approximately $7.6 million, including carrying charges. These costs will be recovered over eight years in the form of a tariff surcharge. Finally, the settlement establishes a major storm reserve of $400,000 annually, which will be used to recover costs associated with responding to and recovering from future qualifying major storm events.

Northern Utilities—Base Rate Case Filings—In May 2011, Northern Utilities filed two separate rate cases with the NHPUC and MPUC requesting approval to increase its natural gas distribution base rates in New Hampshire and Maine, respectively.

On November 29, 2011, the MPUC approved a comprehensive settlement agreement providing for a $7.8 million permanent increase in annual distribution revenue for Northern Utilities’ Maine operations, effective January 1, 2012, and an additional permanent increase in annual distribution revenue of $0.85 million to recover the costs of 2011 cast iron pipe replacement capital spending effective May 1, 2012. The settlement is inclusive of an earlier settlement for a temporary rate increase of $3.5 million in annual distribution revenue effective November 1, 2011. The settlement also precludes Northern Utilities from filing for a new base rate increase with an effective date prior to January 1, 2014.

In New Hampshire, Northern Utilities requested an increase of $5.2 million in annual gas distribution base revenue, which represents an increase of approximately 8.1%. On July 22, 2011, the NHPUC approved a settlement for a temporary rate increase of approximately $1.7 million in annual revenue effective August 1, 2011. Once permanent rates are approved by the NHPUC, they will be reconciled back to August 1, 2011. The Company is currently in settlement discussions with the NHPUC and a final rate order is expected in the first quarter of 2012.

Fitchburg—Management Audit—As a result of its investigation of Fitchburg’s preparation for, and response to, the December 2008 ice storm, the MDPU ordered a comprehensive independent management audit of Fitchburg’s management practices. The management audit, which was performed by Jacobs Consultancy, Inc. (Jacobs), was completed and the audit report was submitted by Jacobs to the MDPU on April 13, 2011. The audit report found Unitil’s management practices to be comprehensive, sound and in-line with industry practice. It also included sixteen recommendations intended to further improve the results of Unitil’s management strategy, and acknowledged that many of these recommendations were already being implemented by the Company. On September 1, 2011, the MDPU issued its order with respect to the audit, accepting the majority of Jacob’s audit report, and requiring the company to implement the remaining recommendations, as well as provide semi-annual status updates as to the company’s implementation progress. On September 30, 2011, the Company filed its first implementation status report with the MDPU.

Fitchburg—Electric Operations—On November 30, 2011, Fitchburg submitted its annual reconciliation of costs and revenues for Transition and Transmission under its restructuring plan. The filing includes the reconciliation of costs and revenues for a number of surcharges and cost factors which are under individual review in separate proceedings before the MDPU, including the Pension/PBOP

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Adjustment, Residential Assistance Adjustment Factor, Net Metering Recovery Surcharge, Attorney General Consultant Expense Factor and Revenue Decoupling Adjustment Factor. The rates were approved effective January 1, 2012, subject to reconciliation pending investigation by the MDPU. This matter remains pending. Final orders on Fitchburg’s 2009 and 2010 annual reconciliation filings also remain pending.

Fitchburg—Gas Operations—On November 2, 2011, the SJC issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered Fitchburg to refund $4.6 million of natural gas costs, plus interest. The MDPU’s original order issued in 2009 found that the Company had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU’s prior approval and that the Company’s natural gas purchasing practices were imprudent. The Company appealed the MDPU’s decision to the SJC. The SJC’s decision vacates the MDPU’s order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. The Company had previously recorded a pre-tax charge to earnings and recognized a Regulatory Liability of $4.9 million in the fourth quarter of 2009 based on the MDPU’s original order. As a result of the decision, the Regulatory Liability was adjusted and the Company recognized a credit of $4.7 million in the fourth quarter of 2011.

On December 28, 2011, the MDPU approved Fitchburg’s proposal to discontinue the previously ordered refund of the $4.6 million of natural gas costs, and to begin the recoupment of the amounts previously refunded, with interest, effective January 1, 2012. In order to minimize the rate impact on customers, the recoupment will occur over the next three winter heating seasons.

Fitchburg—Storm Cost Deferral Petition—On December 16, 2011, Fitchburg filed a request with the MDPU for authorization to defer, for future recovery in rates, the costs incurred to perform storm- related emergency repairs on its electric distribution system as a result of two recent storms, Tropical Storm Irene, which occurred on August 28, 2011, and a severe snow storm, which occurred on October 29-30, 2011. Fitchburg estimates that it incurred $1.5 million in costs for Tropical Storm Irene and $3.2 million in costs for the October snow storm. Fitchburg also requested that it be allowed to accrue carrying charges on the deferred amount. This matter remains pending.

Fitchburg—Other—On February 11, 2009, the 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 matter of how 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, 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 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 March 1, 2011, Fitchburg submitted its 2010 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 January 13, 2012, the MDPU issued its order approving the 2010 Service Quality Report for Fitchburg’s gas division. On January 26, 2011, the MDPU issued

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orders with respect to Fitchburg’s 2008 and 2009 Service Quality Reports for its electric division. Fitchburg failed to meet certain of its service quality benchmarks in 2008, and a penalty of $100,478 was ordered to be refunded to its electric customers. The Company refunded this amount to customers in their June and July 2011 billings. For 2009 performance, no net penalty was assessed. As required by the order, on February 16, 2011 Fitchburg filed a report regarding the actions it has taken to improve its performance in the metrics it had not met.

Unitil Energy—Annual Rate Reconciliation Filing—On July 29, 2011, the NHPUC approved Unitil Energy’s annual reconciliation and rate filing under its restructuring plan, for rates effective August 1, 2011, including reconciliation of prior year costs and revenues.

Unitil Energy—Billing—In August 2011, Unitil Energy and one of its larger customers in New Hampshire settled a lawsuit filed by the customer in June 2011 regarding a billing error that resulted from a transformer connected to the customer’s meter, which had been mislabeled by the manufacturer, and caused Unitil Energy to overcharge the customer for bills issued from October 2004 through January 2011. The amount of the customer’s overpayment was calculated to be $1.8 million (Distribution and Other Delivery Charges—$0.5 million; Supply Charges—$1.3 million). As a result of the settlement, Unitil Energy reimbursed the customer $1.8 million plus $0.3 million of interest. The Company recognized a non-recurring charge of $0.4 million for distribution charges plus interest in 2011.

As a result of this metering issue, which was discovered in February 2011, certain other customers in the Company’s service territory were under-billed from October 2004 through January 2011 for supply charges. Accordingly, the Company has requested authorization from the NHPUC to process the billing correction. The Company’s request remains pending before the NHPUC.

Northern Utilities—NOPV—On November 21, 2008, the MPUC issued an order approving a settlement agreement resolving a number of Notices of Probable Violation (NOPVs) of certain safety related procedures and rules by Northern Utilities. Under the Settlement, Northern Utilities will incur total expenditures of approximately $3.8 million for safety related improvements to Northern Utilities’ distribution system to ensure compliance with the relevant state and federal gas safety laws, for which no rate recovery will be allowed. These compliance costs were accrued by Northern Utilities prior to the acquisition date and the remaining amount on the Company’s consolidated balance sheet at December 31, 2011 was $0.8 million.

Northern Utilities—Cast Iron Pipe Replacement Program—On July 30, 2010, the MPUC approved a Settlement Agreement providing for an accelerated replacement program for cast iron distribution pipe remaining in portions of Northern Utilities’ Maine service areas. Under the Agreement, Northern Utilities will proceed with a comprehensive upgrade and replacement program (the Program), which will provide for the systematic replacement of cast iron, wrought iron and bare steel pipe in Northern Utilities’ natural gas distribution system in Portland and Westbrook, Maine and the conversion of the system to intermediate pressure. The Agreement establishes the objective of completing the Program by the end of the 2024 construction season.

Northern Utilities—Maine Sales Tax Under-Collection—As previously reported, during 2011 the Company determined that during the conversion of the Northern Utilities customer portfolio from the prior owner to Unitil’s customer information system, a portion of Northern Utilities’ commercial and industrial customers were incorrectly converted as exempt from Maine sales tax. This issue has been resolved with Maine Revenue Services and the MPUC and the Company has collected substantially all of the arrears.

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 will evaluate 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 Company expects the final audit report will be issued by December 31, 2012.

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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 compliance with applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2011, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, there can be no assurance 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.

Fitchburg’s Manufactured Gas Plant Site—Fitchburg continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. Fitchburg has proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection, which allows Fitchburg to work towards temporary closure of the site. A status of temporary closure requires Fitchburg to monitor the site until a feasible permanent remediation alternative can be developed and completed.

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. Fitchburg had filed suit against several of its former insurance carriers seeking coverage for past and future environmental response costs at the site. In January 2011, Fitchburg settled with the remaining insurance carriers for approximately $2.0 million and received these payments in the first quarter of 2011. Any recovery that Fitchburg receives from insurance or third-parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are shared equally between Fitchburg and its gas customers.

Northern Utilities’ Manufactured Gas Plant Sites—Northern Utilities has an extensive program to identify, investigate and remediate former 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, and Scarborough sites. The sites in Lewiston and Portland have been investigated and remedial activities are currently underway. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs 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.

Also, see Note 5 to the accompanying Consolidated Financial Statements for additional information on Environmental Matters.

EMPLOYEES AND EMPLOYEE RELATIONS

As of December 31, 2011, the Company and its subsidiaries had 454 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of December 31, 2011, 151 of the Company’s employees were represented by labor unions. These employees are covered by four separate collective bargaining agreements which expire on March 31,

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2012, May 31, 2012, May 31, 2013 and June 5, 2014. The agreements provide discreet 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.

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.

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Utility Revenue Recognition—Utility revenues are recognized according to regulations and are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on estimated customer usage by class and applicable customer rates.

On August 1, 2011, the MDPU issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of the Company’s Massachusetts combination electric and natural gas distribution utility, 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.

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

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corporate bond interest rate indices and pension yield curves. For the years ended December 31, 2011 and 2010, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $325,000 and $300,000, respectively, in the Net Periodic Benefit Cost for the Pension Plan. For the years ended December 31, 2011 and 2010, 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 $909,000 and $728,000, 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 $705,000 and $565,000, respectively. (See Note 9 to the accompanying Consolidated Financial Statements).

Income Taxes—The Company is subject to Federal and State income taxes as well as various other business taxes. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with the FASB Codification guidance on Income Taxes. The Company classifies penalty and interest expense related to income tax liabilities as income tax expense and interest expense, respectively, in the Consolidated Statements of Earnings.

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s 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, 2011, 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 these types of activities, see Note 1, “Summary of Significant Accounting Policies,” Note 7, “Income Taxes,” Note 4, “Energy Supply,” Note 9, “Retirement Benefit Plans,” and Note 5, “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”.

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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 2.2%, 2.3%, and 3.4% during 2011, 2010, and 2009, respectively.

MARKET 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 above and below in Regulatory Matters, 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, 2011 and 2010, and the related consolidated statements of earnings, cash flows and changes in common stock equity for both of the two years in the period ended December 31, 2011. We also have audited Unitil Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2011 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, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ McGladrey & Pullen, LLP

Boston, Massachusetts

February 1, 2012

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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 statements of earnings, cash flows and changes in common stock equity for the year ended December 31, 2009. The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of its operations and its cash flows for the year ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

/s/ Caturano and Company, P.C.

Boston, Massachusetts

February 10, 2010

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CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except common shares and per share data)

Year Ended December 31, |  | 2011 |  |  | 2010 |  |  | 2009 |
Operating Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Gas |  | $ | 159.2 |  |  | $ | 150.1 |  |  | $ | 152.8 |
Electric |  |  | 188.1 |  |  |  | 203.7 |  |  |  | 209.9 |
Other |  |  | 5.5 |  |  |  | 4.6 |  |  |  | 4.3 |
Total Operating Revenues |  |  | 352.8 |  |  |  | 358.4 |  |  |  | 367.0 |
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Purchased Gas |  |  | 89.1 |  |  |  | 90.5 |  |  |  | 96.4 |
Purchased Electricity |  |  | 114.2 |  |  |  | 137.7 |  |  |  | 151.6 |
Operation and Maintenance |  |  | 51.5 |  |  |  | 48.8 |  |  |  | 44.7 |
Conservation & Load Management |  |  | 8.5 |  |  |  | 8.8 |  |  |  | 5.0 |
Depreciation and Amortization |  |  | 29.3 |  |  |  | 28.9 |  |  |  | 27.4 |
Provisions for Taxes: |  |  |  |  |  |  |  |  |  |  |  |
Local Property and Other |  |  | 13.0 |  |  |  | 11.2 |  |  |  | 10.4 |
Federal and State Income |  |  | 10.0 |  |  |  | 4.5 |  |  |  | 5.4 |
Total Operating Expenses |  |  | 315.6 |  |  |  | 330.4 |  |  |  | 340.9 |
Operating Income |  |  | 37.2 |  |  |  | 28.0 |  |  |  | 26.1 |
Other Non-Operating Expenses |  |  | 0.4 |  |  |  | 0.3 |  |  |  | 0.3 |
Income Before Interest Expense |  |  | 36.8 |  |  |  | 27.7 |  |  |  | 25.8 |
Interest Expense, net |  |  | 20.4 |  |  |  | 18.1 |  |  |  | 15.8 |
Net Income |  |  | 16.4 |  |  |  | 9.6 |  |  |  | 10.0 |
Less Dividends on Preferred Stock |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 0.1 |
Earnings Applicable to Common Shareholders |  | $ | 16.3 |  |  | $ | 9.5 |  |  | $ | 9.9 |
Average Common Shares Outstanding (000’s)—Basic |  |  | 10,880 |  |  |  | 10,823 |  |  |  | 9,647 |
Average Common Shares Outstanding (000’s)—Diluted |  |  | 10,883 |  |  |  | 10,824 |  |  |  | 9,647 |
Earnings per Common Share—Basic and Diluted |  | $ | 1.50 |  |  | $ | 0.88 |  |  | $ | 1.03 |

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

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CONSOLIDATED BALANCE SHEETS (Millions)

ASSETS

December 31, |  | 2011 |  |  | 2010 |
Utility Plant: |  |  |  |  |  |  |  |
Electric |  | $ | 333.3 |  |  | $ | 321.5 |
Gas |  |  | 382.3 |  |  |  | 360.1 |
Common |  |  | 29.8 |  |  |  | 30.2 |
Construction Work in Progress |  |  | 28.3 |  |  |  | 16.6 |
Utility Plant |  |  | 773.7 |  |  |  | 728.4 |
Less: Accumulated Depreciation |  |  | 263.0 |  |  |  | 251.9 |
Net Utility Plant |  |  | 510.7 |  |  |  | 476.5 |
Current Assets: |  |  |  |  |  |  |  |
Cash |  |  | 7.5 |  |  |  | 8.9 |
Accounts Receivable, net |  |  | 44.2 |  |  |  | 36.9 |
Accrued Revenue |  |  | 56.6 |  |  |  | 46.7 |
Refundable Taxes |  |  | — |  |  |  | 7.5 |
Gas Inventory |  |  | 14.8 |  |  |  | 10.6 |
Material and Supplies |  |  | 3.6 |  |  |  | 2.9 |
Prepayments and Other |  |  | 4.5 |  |  |  | 3.6 |
Total Current Assets |  |  | 131.2 |  |  |  | 117.1 |
Noncurrent Assets: |  |  |  |  |  |  |  |
Regulatory Assets |  |  | 139.8 |  |  |  | 143.0 |
Other Noncurrent Assets |  |  | 18.5 |  |  |  | 23.0 |
Total Noncurrent Assets |  |  | 158.3 |  |  |  | 166.0 |
TOTAL ASSETS |  | $ | 800.2 |  |  | $ | 759.6 |

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

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CONSOLIDATED BALANCE SHEETS (cont.) (Millions)

CAPITALIZATION AND LIABILITIES

December 31, |  | 2011 |  |  | 2010 |
Capitalization: |  |  |  |  |  |  |  |
Common Stock Equity |  | $ | 191.7 |  |  | $ | 189.0 |
Preferred Stock |  |  | 2.0 |  |  |  | 2.0 |
Long-Term Debt, Less Current Portion |  |  | 287.8 |  |  |  | 288.3 |
Total Capitalization |  |  | 481.5 |  |  |  | 479.3 |
Current Liabilities: |  |  |  |  |  |  |  |
Long-Term Debt, Current Portion |  |  | 0.5 |  |  |  | 0.5 |
Accounts Payable |  |  | 26.4 |  |  |  | 26.5 |
Short-Term Debt |  |  | 87.9 |  |  |  | 66.8 |
Energy Supply Contract Obligations |  |  | 21.1 |  |  |  | 17.0 |
Taxes Payable |  |  | 1.0 |  |  |  | — |
Other Current Liabilities |  |  | 17.5 |  |  |  | 16.1 |
Total Current Liabilities |  |  | 154.4 |  |  |  | 126.9 |
Deferred Income Taxes |  |  | 46.3 |  |  |  | 43.8 |
Noncurrent Liabilities: |  |  |  |  |  |  |  |
Energy Supply Contract Obligations |  |  | 4.2 |  |  |  | 12.6 |
Retirement Benefit Obligations |  |  | 91.2 |  |  |  | 74.0 |
Environmental Obligations |  |  | 14.5 |  |  |  | 14.5 |
Other Noncurrent Liabilities |  |  | 8.1 |  |  |  | 8.5 |
Total Noncurrent Liabilities |  |  | 118.0 |  |  |  | 109.6 |
TOTAL CAPITALIZATION AND LIABILITIES |  | $ | 800.2 |  |  | $ | 759.6 |

(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, |  | 2011 |  |  | 2010 |  |  | 2009 |
Operating Activities: |  |  |  |  |  |  |  |  |  |  |  |
Net Income |  | $ | 16.4 |  |  | $ | 9.6 |  |  | $ | 10.0 |
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and Amortization |  |  | 29.3 |  |  |  | 28.9 |  |  |  | 27.4 |
Deferred Taxes Provision |  |  | 8.7 |  |  |  | 10.5 |  |  |  | 7.1 |
Changes in Working Capital Items: |  |  |  |  |  |  |  |  |  |  |  |
Accounts Receivable |  |  | (7.3 | ) |  |  | (3.4 | ) |  |  | 6.2 |
Accrued Revenue |  |  | (9.9 | ) |  |  | (2.7 | ) |  |  | 12.9 |
Taxes Refundable / Payable |  |  | 8.5 |  |  |  | (5.8 | ) |  |  | 1.5 |
Gas Inventory |  |  | (4.2 | ) |  |  | 3.7 |  |  |  | 17.3 |
Accounts Payable |  |  | (0.1 | ) |  |  | 1.4 |  |  |  | (3.4 | )
Other Changes in Working Capital Items |  |  | (0.7 | ) |  |  | (5.3 | ) |  |  | (5.1 | )
Deferred Regulatory and Other Charges |  |  | 7.5 |  |  |  | (4.5 | ) |  |  | (26.0 | )
Other, net |  |  | (2.3 | ) |  |  | (6.5 | ) |  |  | 3.0 |
Cash Provided by Operating Activities |  |  | 45.9 |  |  |  | 25.9 |  |  |  | 50.9 |
Investing Activities: |  |  |  |  |  |  |  |  |  |  |  |
Property, Plant and Equipment Additions |  |  | (57.1 | ) |  |  | (49.6 | ) |  |  | (58.7 | )
Acquisitions, net |  |  | — |  |  |  | — |  |  |  | (6.9 | )
Cash (Used In) Investing Activities |  |  | (57.1 | ) |  |  | (49.6 | ) |  |  | (65.6 | )
Financing Activities: |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from (Repayment of) Short-Term Debt, net |  |  | 21.1 |  |  |  | 2.3 |  |  |  | (9.6 | )
Proceeds from Issuance (Repayment) of Long-Term Debt, net |  |  | (0.5 | ) |  |  | 39.5 |  |  |  | (0.4 | )
Net Increase (Decrease) in Gas Inventory Financing |  |  | 4.6 |  |  |  | (2.2 | ) |  |  | (21.8 | )
Dividends Paid |  |  | (15.2 | ) |  |  | (15.0 | ) |  |  | (13.2 | )
Proceeds from Issuance of Common Stock |  |  | 1.0 |  |  |  | 0.9 |  |  |  | 56.4 |
Other, net |  |  | (1.2 | ) |  |  | (0.6 | ) |  |  | (0.5 | )
Cash Provided by Financing Activities |  |  | 9.8 |  |  |  | 24.9 |  |  |  | 10.9 |
Net Increase (Decrease) in Cash |  |  | (1.4 | ) |  |  | 1.2 |  |  |  | (3.8 | )
Cash at Beginning of Year |  |  | 8.9 |  |  |  | 7.7 |  |  |  | 11.5 |
Cash at End of Year |  | $ | 7.5 |  |  | $ | 8.9 |  |  | $ | 7.7 |
Supplemental Information: |  |  |  |  |  |  |  |  |  |  |  |
Interest Paid |  | $ | 21.2 |  |  | $ | 20.5 |  |  | $ | 19.3 |
Income Taxes (Refunded) Paid |  | $ | (7.3 | ) |  | $ | 2.3 |  |  | $ | (3.8 | )

(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, 2009 |  | $ | 102.7 |  |  | $ | 36.8 |  |  | $ | 139.5 |
Net Income for 2009 |  |  |  |  |  |  | 10.0 |  |  |  | 10.0 |
Dividends |  |  |  |  |  |  | (13.2 | ) |  |  | (13.2 | )
Shares Issued Under Stock Plans |  |  | 0.4 |  |  |  |  |  |  |  | 0.4 |
Issuance of 43,615 Common Shares |  |  | 0.9 |  |  |  |  |  |  |  | 0.9 |
Issuance of 2,970,000 Common Shares (See Note 2) |  |  | 55.5 |  |  |  |  |  |  |  | 55.5 |
Balance at December 31, 2009 |  |  | 159.5 |  |  |  | 33.6 |  |  |  | 193.1 |
Net Income for 2010 |  |  |  |  |  |  | 9.6 |  |  |  | 9.6 |
Dividends |  |  |  |  |  |  | (15.0 | ) |  |  | (15.0 | )
Shares Issued Under Stock Plans |  |  | 0.4 |  |  |  |  |  |  |  | 0.4 |
Issuance of 41,455 Common Shares |  |  | 0.9 |  |  |  |  |  |  |  | 0.9 |
Balance at December 31, 2010 |  |  | 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 |

(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, New Hampshire and Massachusetts. Granite State provides Northern Utilities with interconnection to major natural gas pipelines and access to North American pipeline supplies. 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.

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

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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 Accounting Standards Codification (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.

|  | December 31, |
Regulatory Assets consist of the following (millions) |  | 2011 |  |  | 2010 |
Energy Supply Contract Obligations |  | $ | 12.9 |  |  | $ | 21.7 |
Deferred Restructuring Costs |  |  | 21.8 |  |  |  | 25.0 |
Subtotal—Restructuring Related Items |  |  | 34.7 |  |  |  | 46.7 |
Retirement Benefit Obligations |  |  | 55.3 |  |  |  | 47.1 |
Income Taxes |  |  | 10.9 |  |  |  | 12.7 |
Environmental Obligations |  |  | 17.5 |  |  |  | 20.3 |
Deferred Storm Charges |  |  | 22.4 |  |  |  | 21.0 |
Other |  |  | 17.8 |  |  |  | 10.9 |
Total Regulatory Assets |  | $ | 158.6 |  |  | $ | 158.7 |
Less: Current Portion of Regulatory Assets (1) |  |  | 18.8 |  |  |  | 15.7 |
Regulatory Assets—noncurrent |  | $ | 139.8 |  |  | $ | 143.0 |

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

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.

Cash—Cash 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 affiliates 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 affiliates provide cash deposits covering approximately 2-1/2 months of outstanding obligations. On December 31, 2011 and 2010, the Unitil affiliates had deposited $4.6 million and $7.0 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, 2011 and 2010, there was $2.6 million and $1.5 million, respectively, deposited for this purpose.

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

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amortized over a ten year period, beginning with the date of the Acquisitions, as authorized by regulators. As of December 31, 2011, the unamortized balance of the bargain purchase adjustment was $17.1 million, to be amortized over the next seven years.

Off-Balance Sheet Arrangements—As of December 31, 2011, 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 3).

Derivatives—The Company has a regulatory commission 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 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 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), 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, 2011 and December 31, 2010, the Company had 1.6 billion and 1.3 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. As discussed above, the change in fair value related to these derivatives is recorded initially as a Regulatory Asset then reclassified to Purchased Gas in accordance with the recovery mechanism. The tables below include disclosure of the Regulatory Asset and reclassifications from the Regulatory Asset into Purchased Gas.

Fair Value Amount (millions) Offset in Regulatory Assets (1), as of:

|  |  |  | Fair Value |
Description |  | Balance Sheet Location |  | December 31, 2011 |  |  | December 31, 2010 |
Natural Gas Futures Contracts |  | Other Current Liabilities |  | $ | 1.7 |  |  | $ | 0.8 |
Natural Gas Futures Contracts |  | Other Noncurrent Liabilities |  |  | 0.6 |  |  |  | 0.2 |
Total |  |  |  | $ | 2.3 |  |  | $ | 1.0 |

(1) | The current portion of Regulatory Assets is recorded as Accrued Revenue on the Company’s Consolidated Balance Sheets.

|  | Twelve Months Ended December 31, |
(millions) |  | 2011 |  |  | 2010 |
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives: |  |  |  |  |  |  |  |
Natural Gas Futures Contracts |  | $ | 2.9 |  |  | $ | 3.9 |
Amount of Loss Reclassified into Consolidated Statements of Earnings(2): |  |  |  |  |  |  |  |
Purchased Gas |  | $ | 1.6 |  |  | $ | 5.2 |

(2) | These amounts are offset in the Consolidated Statements of Earnings with the recognition of accrued revenue as a component of Gas Operating Revenue and therefore there is no effect on earnings.

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Utility Revenue Recognition—Utility revenues are recognized according to regulations and are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on estimated customer usage by class and applicable customer rates.

On August 1, 2011, the MDPU issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of the Company’s Massachusetts combination electric and natural gas distribution utility, 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.

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.

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 9).

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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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, 2011, 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 5).

Utility Plant—The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 2.28%, 2.25% and 3.24% in 2011, 2010 and 2009, 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 and the cost of removal, less salvage, are 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, depreciation amounts to provide for future negative salvage value. At December 31, 2011 and 2010, the Company estimates that the negative salvage value of future retirements recorded on the consolidated balance sheets in Accumulated Depreciation is $46.5 million and $40.8 million, respectively.

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: 2011 – 3.43%, 2010 – 3.99% and 2009 – 4.02%.

Gas Inventory—The weighted average cost methodology is used to value natural gas in storage.

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, 2011, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 5, 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.

Stock-based Employee Compensation—Unitil accounts for stock-based employee compensation using the fair value-based method (See Note 2).

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.

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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. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.

Dividends—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, 2011, 2010 and 2009, the Company paid a dividend at an annual rate of $1.38 per common share.

Other Recently Issued Pronouncements—In December 2011, the Financial Accounting Standards Board (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 does not expect that the adoption of ASU 2011-11 will have a significant, if any, impact on the Company’s Consolidated Financial Statements.

In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS”, (ASU 2011-04). This update changes certain fair value measurement principles and enhances the disclosure requirements particularly for Level 3 fair value measurements. This update is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited, and requires prospective application. The Company does not expect that the adoption of ASU 2011-04 will have a significant, if 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.

Note 2: Equity

The Company has common stock and certain of our subsidiaries have preferred stock outstanding. Details regarding these forms of capitalization follow:

Common Stock

The Company’s common stock trades 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 10,954,065, and 10,890,262 of common shares outstanding at December 31, 2011 and December 31, 2010, respectively.

Dividend Reinvestment and Stock Purchase Plan—During 2011, the Company sold 39,473 shares of its common stock, at an average price of $24.97 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.0 million. The DRP

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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 2010 and 2009, the Company raised $0.9 million and $0.9 million, respectively, of additional common equity through the issuance of 41,455 and 43,615 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

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 24, 2011, 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 2011, 2010 and 2009, the Company repurchased 8,765, 3,225 and 3,619 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan. The expense recognized by the Company for these repurchases was $0.2 million, $0.1 million and $0.1 million in 2011, 2010 and 2009, respectively.

During 2011, 2010 and 2009, 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 Amended and Restated Unitil Corporation 2003 Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors from the eligible Participants to receive an annual award of restricted shares of Company common stock. The Compensation Committee has the power 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. 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 the 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. The maximum number of shares of restricted stock available for awards to participants under the Stock Plan is 177,500. The maximum aggregate number of shares of restricted stock 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 proportionate adjustments to prevent dilution or enlargement of rights, including, without limitation, an adjustment in the maximum number and kinds of shares available for awards and in the annual award limit.

Restricted shares issued for 2009 – 2011 in conjunction with the Stock Plan are presented in the following table:

Issuance Date |  | Shares |  | Aggregate Market Value (millions)
2/17/09 |  | 32,260 |  | $0.7
2/5/10 |  | 12,520 |  | $0.3
2/9/11 |  | 24,330 |  | $0.6

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, $0.5 million and $0.7 million in 2011, 2010 and 2009, respectively. There were 33,731 and 29,521 non-vested shares under the Stock Plan as of December 31, 2011 and 2010, respectively. The weighted average grant date fair value of these shares was

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$21.93 per share and $21.77 per share, respectively. At December 31, 2011, there was approximately $0.9 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.4 years. There were no forfeitures or cancellations under the Stock Plan during 2011.

The Stock Plan also includes restricted stock units as a type of award that the Company may grant to the Company’s employees, Directors or consultants. There were no restricted stock units issued under the Stock Plan during 2011.

Unitil Corporation 1998 Stock Option Plan—The “Unitil Corporation 1998 Stock Option Plan” became effective on December 11, 1998 and was terminated by the Board of Directors on January 16, 2003. There was no compensation expense associated with this plan in 2011, 2010 and 2009. The plan has remained in effect solely for the purposes of the continued administration of any options outstanding under the plan. No further grants of options have been made under this plan since it was terminated by the Board of Directors in 2003. As of December 31, 2011, 2010 and 2009, there was no aggregate intrinsic value of the options exercisable. As of December 31, 2011, all options under this plan have expired.

|  | 2011 |  |  | 2010 |  |  | 2009 |
|  | Number of Shares |  |  | Average Exercise Price |  |  | Number of Shares |  |  | Average Exercise Price |  |  | Number of Shares |  |  | Average Exercise Price |
Beginning Options Outstanding |  |  | 33,000 |  |  | $ | 25.88 |  |  |  | 63,500 |  |  | $ | 28.90 |  |  |  | 97,200 |  |  | $ | 27.16 |
Options Granted |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Options Exercised |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Options Forfeited / Expired |  |  | (33,000 | ) |  | $ | 25.88 |  |  |  | (30,500 | ) |  | $ | 32.17 |  |  |  | (33,700 | ) |  | $ | 23.88 |
Ending Options Outstanding |  |  | — |  |  | $ | — |  |  |  | 33,000 |  |  | $ | 25.88 |  |  |  | 63,500 |  |  | $ | 28.90 |
Options Vested and Exercisable- end of year |  |  | — |  |  | $ | — |  |  |  | 33,000 |  |  | $ | 25.88 |  |  |  | 63,500 |  |  | $ | 28.90 |

Preferred Stock

Two of Unitil’s distribution companies, Unitil Energy and Fitchburg, have an aggregate of $2.0 million of preferred stock outstanding. At December 31, 2011, Unitil Energy has $0.2 million of 6.00% Series Non-Redeemable, Non-Cumulative Preferred Stock series outstanding and Fitchburg has two series of Redeemable, Cumulative Preferred Stock outstanding, $0.8 million of 5.125% Series and $1.0 million of 8.00% Series.

Fitchburg is required to offer to redeem annually a given number of shares of each series of Redeemable, Cumulative Preferred Stock and to purchase such shares that shall have been tendered by holders of the respective stock. In addition, Fitchburg may opt to redeem the Redeemable, Cumulative Preferred Stock at a given redemption price, plus accrued dividends.

The aggregate purchases of Redeemable, Cumulative Preferred Stock during 2011, 2010 and 2009 related to the annual redemption offer were $8,600, $25,000 and $26,000, respectively. The aggregate amount of sinking fund requirements of the Redeemable, Cumulative Preferred Stock for each of the five years following 2011 is $117,000 per year.

Earnings Per Share

The following table reconciles basic and diluted earnings per share.

(Millions except shares and per share data) |  | 2011 |  |  | 2010 |  |  | 2009 |
Earnings Available to Common Shareholders |  | $ | 16.3 |  |  | $ | 9.5 |  |  | $ | 9.9 |
Weighted Average Common Shares Outstanding—Basic (000’s) |  |  | 10,880 |  |  |  | 10,823 |  |  |  | 9,647 |
Plus: Diluted Effect of Incremental Shares (000’s) |  |  | 3 |  |  |  | 1 |  |  |  | — |
Weighted Average Common Shares Outstanding—Diluted (000’s) |  |  | 10,883 |  |  |  | 10,824 |  |  |  | 9,647 |
Earnings per Share—Basic and Diluted |  | $ | 1.50 |  |  | $ | 0.88 |  |  | $ | 1.03 |

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Weighted average options to purchase 33,000 and 63,500 shares of common stock were outstanding during 2010 and 2009, respectively, but were not included in the computation of Weighted Average Common Shares Outstanding for purposes of computing diluted earnings per share, because the effect would have been antidilutive. Additionally, 1,642, 6,164 and 28,963 weighted average non-vested restricted shares for 2011, 2010 and 2009, respectively, were not included in the above computation because the effect would have been antidilutive.

Note 3: Long-Term Debt, Credit Arrangements, Leases and Guarantees

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 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 projected 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 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. Each of the Fitchburg, Northern Utilities and Granite State default provisions are not triggered by the actions or defaults of Unitil or any of its other subsidiaries.

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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, 2011, 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 $462,055, $426,643, and $393,946 in 2011, 2010, and 2009, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2011 is: 2012 – $500,405; 2013 – $541,938; 2014 – $2,486,919; 2015 – $4,035,633; and 2016 – $17,421,724, respectively.

Long-Term Debt Issuances

On March 2, 2010, both Unitil Energy and Northern Utilities closed long-term financings:

| (i) | Unitil Energy closed $15,000,000 of First Mortgage Bonds, through a private placement marketing process to institutional investors. The First Mortgage Bonds have a coupon rate of 5.24% and have a final maturity of ten years. Unitil Energy used the net proceeds from this long-term financing to repay short-term debt and for general corporate purposes.

| (ii) | Northern Utilities closed $25,000,000 of Senior Unsecured Notes, through a private placement marketing process to institutional investors. The Senior Unsecured Notes have a coupon rate of 5.29% and have a final maturity of ten years. Northern Utilities used the net proceeds from this long-term financing to repay short-term debt and for general corporate purposes.

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. 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 for December 2011. The carrying value of the Company’s long-term debt at December 31, 2011 is $288.3 million. The fair value of the Company’s long-term debt at December 31, 2011 is estimated to be approximately $338.7 million. Costs, including prepayment costs, associated with the early settlement of long-term debt are not taken into consideration in determining fair value.

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Details on long-term debt at December 31, 2011 and 2010 are shown below:

|  | December 31, |
Long-Term Debt (millions) |  | 2011 |  |  | 2010 |
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 |  |  | 3.3 |  |  |  | 3.8 |
Total Long-Term Debt |  |  | 288.3 |  |  |  | 288.8 |
Less: Current Portion |  |  | 0.5 |  |  |  | 0.5 |
Total Long-Term Debt, Less Current Portion |  | $ | 287.8 |  |  | $ | 288.3 |

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) |
|  | 2011 |  |  | 2010 |  |  | 2009 |
Interest Expense |  |  |  |  |  |  |  |  |  |  |  |
Long-term Debt |  | $ | 20.3 |  |  | $ | 20.0 |  |  | $ | 18.2 |
Short-term Debt |  |  | 1.7 |  |  |  | 1.7 |  |  |  | 2.1 |
Regulatory Liabilities |  |  | — |  |  |  | 0.3 |  |  |  | 0.3 |
Subtotal Interest Expense |  |  | 22.0 |  |  |  | 22.0 |  |  |  | 20.6 |
Interest Income |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  | (1.1 | ) |  |  | (3.5 | ) |  |  | (3.6 | )
AFUDC(1) and Other |  |  | (0.5 | ) |  |  | (0.4 | ) |  |  | (1.2 | )
Subtotal Interest Income |  |  | (1.6 | ) |  |  | (3.9 | ) |  |  | (4.8 | )
Total Interest Expense, net |  | $ | 20.4 |  |  | $ | 18.1 |  |  | $ | 15.8 |

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

Credit Arrangements

Unitil has a revolving credit facility with a group of banks that extends to October 8, 2013. The borrowing limit under the revolving credit facility was $115.0 million at December 31, 2011 and $80.0 million at December 31, 2010. There was $87.9 million and $66.8 million in short-term debt outstanding through bank borrowings under the revolving credit facility at December 31, 2011 and December 31, 2010, respectively. The total amount of credit available under the Company’s revolving credit facility was $27.1 million and $13.2 million at December 31, 2011 and December 31, 2010, respectively. The revolving credit facility contains customary terms and conditions for credit facilities of this type, including, without limitation, covenants restricting the Company’s ability to incur liens, merge or consolidate with another entity or change its line of business. The revolving credit agreement also contains a covenant restricting the Company’s ability to permit funded debt to exceed 65% of capitalization at the end of each fiscal quarter. As of December 31, 2011 and December 31, 2010, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

On October 12, 2011, Unitil entered into the Fifth Amendment agreement with Bank of America, N.A., as administrative agent, and a syndicate of other lenders party thereto, further amending the revolving credit agreement dated as of November 26, 2008. The revolving credit agreement was previously amended on January 2, 2009, March 16, 2009, October 13, 2009 and October 8, 2010 to, among other things, increase the maximum borrowings under the facility, provide for a base rate interest rate option, reflect letter of credit availability, modify certain financial reporting requirements and extend the scheduled termination date of the facility. The Fifth Amendment agreement increased the maximum borrowings under the facility to $115 million, changed the additional interest margin applicable to borrowings at a fluctuating rate of interest per annum equal to the daily London Interbank Offered Rate from 2.00% to 1.75%, and changed the annual letter of credit fee from 1.625% of the daily amount available to be drawn under letters of credit issued under the credit facility to 1.500% of such daily amount.

The weighted average interest rates on all short-term borrowings were 2.2%, 2.3%, and 3.4% during 2011, 2010, and 2009, 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 $14.9 million and $11.7 million outstanding at December 31, 2011 and 2010, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2011, which was payable in January 2012, is $2.5 million and recorded in Accounts Payable at December 31, 2011. The amount of natural gas inventory released in December 2010, which was payable in January 2011, is $3.9 million and recorded in Accounts Payable at December 31, 2010.

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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, 2011, 2010 and 2009 amounted to $1.4 million, $1.0 million and $1.0 million respectively. Fitchburg leases its operations facility in Fitchburg, Massachusetts under an operating lease, with a primary term through January 31, 2013. The lease agreement allows for three additional five-year renewal periods at the option of Fitchburg.

The following is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2011:

Year Ending December 31, (000’s) |  | Operating Leases |  |  | Capital Leases |
2012 |  | $ | 1,187 |  |  | $ | 829 |
2013 |  |  | 822 |  |  |  | 513 |
2014 |  |  | 584 |  |  |  | 161 |
2015 |  |  | 474 |  |  |  | 28 |
2016 |  |  | 240 |  |  |  | 9 |
2017 – 2021 |  |  | 178 |  |  |  | — |
Total Payments |  | $ | 3,485 |  |  | $ | 1,540 |

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, 2011, there were approximately $37.2 million of guarantees outstanding and the longest term guarantee extends through February 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, 2011, the principal amount outstanding for the 8% Unitil Realty notes was $3.3 million, and the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

Note 4: 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.

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. 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. 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 Purchased Gas in the Consolidated Statements of Earnings.

On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered the Company’s electric and natural gas distribution utility, Fitchburg, to refund $4.6 million of natural gas costs, plus interest. The

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MDPU’s original order, issued in 2009, found that Fitchburg had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU’s prior approval and that Fitchburg’s natural gas purchasing practices were imprudent. The Company appealed the MDPU’s decision to the SJC. The SJC’s decision vacates the MDPU’s order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. The Company had previously recorded a pre-tax charge to earnings and recognized a Regulatory Liability of $4.9 million in the fourth quarter of 2009 based on the MDPU’s original order. As a result of the decision, the Regulatory Liability has been adjusted and the Company recognized a pre-tax credit of $4.7 million in the fourth quarter of 2011. This credit is recognized on the Company’s 2011 Consolidated Statement of Earnings as a $4.5 million reduction in Purchased Gas expense and a reduction of $0.2 million in Interest Expense, net.

Regulated Natural Gas Supply

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 liquefied natural gas (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 for transportation and underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and a LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

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

Northern Utilities has available under firm contract 100,000 MMbtu per day of year-round and seasonal transportation capacity to its distribution facilities, and 3.4 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.

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 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 2011, 106 or 71% of Unitil’s largest New Hampshire customers, representing 25% of total New Hampshire electric energy sales, and 28 or 93% of Unitil’s largest Massachusetts customers, representing 33% of total Massachusetts electric energy sales, are purchasing their electric power supply in the competitive 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.

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.

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Currently, all Basic Service power supply contracts for large general accounts are three months in duration and provide 100% of supply requirements. 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.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Unitil Energy procures Default Service supply for its large general service accounts through competitive solicitations for power contracts of three months in duration for 100% of supply requirements. Unitil Energy procures Default Service supply for its other customers through a series of two one-year contracts and two two-year contracts, each providing 25% of the total supply requirements of the group.

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 economic manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England is 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 power system operation in a reliable manner 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.

Note 5: Commitments and Contingencies

Regulatory Matters

Overview (Unitil Energy, Fitchburg, and Northern Utilities)—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. 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, 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

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supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next one to three years, is $34.7 million as of December 31, 2011 including $12.4 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.

Fitchburg—Increase in Base Rates Approved—On August 1, 2011, the MDPU issued and order approving increases of $3.3 million and $3.7 million in annual distribution revenues for Fitchburg’s electric and gas divisions, respectively. The MDPU also approved revenue decoupling mechanisms and a return on equity of 9.2% for both the electric and gas divisions of Fitchburg. The rate increase for Fitchburg’s electric division included the recovery of $11.4 million of previously deferred emergency storm restoration costs associated with the December 2008 ice storm, which costs are to be amortized and recovered over seven (7) years without carrying costs. The order provides resolution to the open regulatory matters concerning the ratemaking treatment and cost recovery related to the December 2008 ice storm event.

Granite State—Increase in Base Rates Approved—On January 31, 2011, the FERC approved a settlement agreement providing for an increase of $1.7 million in annual revenue, based on new gas transportation rates to be effective January 1, 2011. Subsequently, on August 31, 2011, the FERC approved an amendment to the settlement agreement which provides for an additional increase of approximately $0.5 million in Granite State’s annual revenues effective August 1, 2011. Under the amended settlement agreement, beginning in 2012, Granite State is permitted to file limited annual rate adjustment filings to recover the revenue requirements for certain specified future capital cost additions to transmission plant projects. The limited rate adjustments would be effective August 1 of each year, and are projected to conclude in 2014 when the major projects will be completed. The annual revenue increases for the limited rate adjustments are estimated to be approximately $0.5 million each year during 2012 through 2014.

Unitil Energy—Increase in Base Rates Approved—On April 26, 2011, the NHPUC approved a final rate settlement which makes permanent a temporary increase of $5.2 million in annual revenue effective July 1, 2010, and provides for 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 estimated future increases of $1.5 million to $2.0 million in annual revenue to occur on May 1, 2012, May 1, 2013 and May 1, 2014, to support Unitil Energy’s continued capital improvements to its distribution system. The rate plan allows Unitil to file for additional rate relief if its return on equity is less than 7% and a sharing of earnings with customers if its return on equity is greater than 10% in a calendar year. The settlement provides for a return on equity of 9.67%, a common equity ratio of 45.45% and an overall weighted cost of capital of 8.39% to determine changes to distribution rate levels.

The settlement approved Unitil Energy’s proposal for an augmented vegetation management program and reliability enhancement program. Under the augmented vegetation management program, Unitil Energy will be increasing its vegetation management spending from a test-year spending level of approximately $0.7 million to $3.1 million per year by 2013. Under the new reliability enhancement program, Unitil Energy will spend $1.8 million annually towards targeted projects designed to enhance system reliability. The funding for both of these programs is included in the future rate increases discussed above.

The settlement provides for recovery of deferred December 2008 ice storm and February 2010 wind storm costs of approximately $7.6 million, including carrying charges. These costs will be recovered over eight years in the form of a tariff surcharge. Finally, the settlement establishes a major storm reserve of $400,000 annually, which will be used to recover costs associated with responding to and recovering from future qualifying major storm events.

Northern Utilities—Base Rate Case Filings—In May 2011, Northern Utilities filed two separate rate cases with the NHPUC and MPUC requesting approval to increase its natural gas distribution base rates in New Hampshire and Maine, respectively.

On November 29, 2011, the MPUC approved a comprehensive settlement agreement providing for a $7.8 million permanent increase in annual distribution revenue for Northern Utilities’ Maine operations,

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effective January 1, 2012, and an additional permanent increase in annual distribution revenue of $0.85 million to recover the costs of 2011 cast iron pipe replacement capital spending effective May 1, 2012. The settlement is inclusive of an earlier settlement for a temporary rate increase of $3.5 million in annual distribution revenue effective November 1, 2011. The settlement also precludes Northern Utilities from filing for a new base rate increase with an effective date prior to January 1, 2014.

In New Hampshire, Northern Utilities requested an increase of $5.2 million in annual gas distribution base revenue, which represents an increase of approximately 8.1%. On July 22, 2011, the NHPUC approved a settlement for a temporary rate increase of approximately $1.7 million in annual revenue effective August 1, 2011. Once permanent rates are approved by the NHPUC, they will be reconciled back to August 1, 2011. The Company is currently in settlement discussions with the NHPUC and a final rate order is expected in the first quarter of 2012.

Fitchburg—Management Audit—As a result of its investigation of Fitchburg’s preparation for, and response to, the December 2008 ice storm, the MDPU ordered a comprehensive independent management audit of Fitchburg’s management practices. The management audit, which was performed by Jacobs Consultancy, Inc. (Jacobs), was completed and the audit report was submitted by Jacobs to the MDPU on April 13, 2011. The audit report found Unitil’s management practices to be comprehensive, sound and in-line with industry practice. It also included sixteen recommendations intended to further improve the results of Unitil’s management strategy, and acknowledged that many of these recommendations were already being implemented by the Company. On September 1, 2011, the MDPU issued its order with respect to the audit, accepting the majority of Jacob’s audit report, and requiring the company to implement the remaining recommendations, as well as provide semi-annual status updates as to the company’s implementation progress. On September 30, 2011, the Company filed its first implementation status report with the MDPU.

Fitchburg—Electric Operations—On November 30, 2011, Fitchburg submitted its annual reconciliation of costs and revenues for Transition and Transmission under its restructuring plan. The filing includes the reconciliation of costs and revenues for a number of surcharges and cost factors which are under individual review in separate proceedings before the MDPU, including the Pension/PBOP Adjustment, Residential Assistance Adjustment Factor, Net Metering Recovery Surcharge, Attorney General Consultant Expense Factor and Revenue Decoupling Adjustment Factor. The rates were approved effective January 1, 2012, subject to reconciliation pending investigation by the MDPU. This matter remains pending. Final orders on Fitchburg’s 2009 and 2010 annual reconciliation filings also remain pending.

Fitchburg—Gas Operations—On November 2, 2011, the SJC issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered Fitchburg to refund $4.6 million of natural gas costs, plus interest. The MDPU’s original order issued in 2009 found that the Company had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU’s prior approval and that the Company’s natural gas purchasing practices were imprudent. The Company appealed the MDPU’s decision to the SJC. The SJC’s decision vacates the MDPU’s order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. The Company had previously recorded a pre-tax charge to earnings and recognized a Regulatory Liability of $4.9 million in the fourth quarter of 2009 based on the MDPU’s original order. As a result of the decision, the Regulatory Liability was adjusted and the Company recognized a credit of $4.7 million in the fourth quarter of 2011.

On December 28, 2011, the MDPU approved Fitchburg’s proposal to discontinue the previously ordered refund of the $4.6 million of natural gas costs, and to begin the recoupment of the amounts previously refunded, with interest, effective January 1, 2012. In order to minimize the rate impact on customers, the recoupment will occur over the next three winter heating seasons.

Fitchburg—Storm Cost Deferral Petition—On December 16, 2011, Fitchburg filed a request with the MDPU for authorization to defer, for future recovery in rates, the costs incurred to perform storm-related emergency repairs on its electric distribution system as a result of two recent storms, Tropical Storm Irene, which occurred on August 28, 2011, and a severe snow storm, which occurred on October 29-30, 2011. Fitchburg estimates that it incurred $1.5 million in costs for Tropical Storm Irene and $3.2 million in costs for the October snow storm. Fitchburg also requested that it be allowed to accrue carrying charges on the deferred amount. This matter remains pending.

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Fitchburg—Other—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 matter of how 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, 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 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 March 1, 2011, Fitchburg submitted its 2010 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 January 13, 2012, the MDPU issued its order approving the 2010 Service Quality Report for Fitchburg’s gas division. On January 26, 2011, the MDPU issued orders with respect to Fitchburg’s 2008 and 2009 Service Quality Reports for its electric division. Fitchburg failed to meet certain of its service quality benchmarks in 2008, and a penalty of $100,478 was ordered to be refunded to its electric customers. The Company refunded this amount to customers in their June and July 2011 billings. For 2009 performance, no net penalty was assessed. As required by the order, on February 16, 2011 Fitchburg filed a report regarding the actions it has taken to improve its performance in the metrics it had not met.

Unitil Energy—Annual Rate Reconciliation Filing—On July 29, 2011, the NHPUC approved Unitil Energy’s annual reconciliation and rate filing under its restructuring plan, for rates effective August 1, 2011, including reconciliation of prior year costs and revenues.

Unitil Energy—Billing—In August 2011, Unitil Energy and one of its larger customers in New Hampshire settled a lawsuit filed by the customer in June 2011 regarding a billing error that resulted from a transformer connected to the customer’s meter, which had been mislabeled by the manufacturer, and caused Unitil Energy to overcharge the customer for bills issued from October 2004 through January 2011. The amount of the customer’s overpayment was calculated to be $1.8 million (Distribution and Other Delivery Charges—$0.5 million; Supply Charges—$1.3 million). As a result of the settlement, Unitil Energy reimbursed the customer $1.8 million plus $0.3 million of interest. The Company recognized a non-recurring charge of $0.4 million for distribution charges plus interest in 2011.

As a result of this metering issue, which was discovered in February 2011, certain other customers in the Company’s service territory were under-billed from October 2004 through January 2011 for supply charges. Accordingly, the Company has requested authorization from the NHPUC to process the billing correction. The Company’s request remains pending before the NHPUC.

Northern Utilities—NOPV—On November 21, 2008, the MPUC issued an order approving a settlement agreement resolving a number of Notices of Probable Violation (NOPVs) of certain safety related procedures and rules by Northern Utilities. Under the Settlement, Northern Utilities will incur total expenditures of approximately $3.8 million for safety related improvements to Northern Utilities’ distribution system to ensure compliance with the relevant state and federal gas safety laws, for which no

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rate recovery will be allowed. These compliance costs were accrued by Northern Utilities prior to the acquisition date and the remaining amount on the Company’s consolidated balance sheet at December 31, 2011 was $0.8 million.

Northern Utilities—Cast Iron Pipe Replacement Program—On July 30, 2010, the MPUC approved a Settlement Agreement providing for an accelerated replacement program for cast iron distribution pipe remaining in portions of Northern Utilities’ Maine service areas. Under the Agreement, Northern Utilities will proceed with a comprehensive upgrade and replacement program (the Program), which will provide for the systematic replacement of cast iron, wrought iron and bare steel pipe in Northern Utilities’ natural gas distribution system in Portland and Westbrook, Maine and the conversion of the system to intermediate pressure. The Agreement establishes the objective of completing the Program by the end of the 2024 construction season.

Northern Utilities—Maine Sales Tax Under-Collection—As previously reported, during 2011 the Company determined that during the conversion of the Northern Utilities customer portfolio from the prior owner to Unitil’s customer information system, a portion of Northern Utilities’ commercial and industrial customers were incorrectly converted as exempt from Maine sales tax. This issue has been resolved with Maine Revenue Services and the MPUC and the Company has collected substantially all of the arrears.

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 will evaluate 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 Company expects the final audit report will be issued by December 31, 2012.

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.

A putative class action complaint was filed against Fitchburg on January 7, 2009 in Worcester Superior Court in Worcester, Massachusetts, captioned Bellerman v. Fitchburg Gas and Electric Light Company. On April 1, 2009, an Amended Complaint was filed in Worcester Superior Court and served on Fitchburg. The Amended 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 Amended Complaint 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 Superior Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. The Company anticipates that the court will decide whether the lawsuit is appropriate for class action treatment in late 2012. The Company continues to believe the suit is without merit and will defend itself vigorously.

On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered Fitchburg to refund $4.6 million of natural gas costs, plus interest. The MDPU’s original order issued in 2009 found that the Company had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU’s prior approval and that the Company’s natural gas purchasing practices were imprudent. The Company appealed the MDPU’s decision to the SJC. The SJC’s decision vacates the MDPU’s order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. See additional discussion above in Regulatory Matters.

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

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compliance with applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2011, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, there can be no assurance 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.

Fitchburg’s Manufactured Gas Plant Site—Fitchburg continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. Fitchburg has proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection, which allows Fitchburg to work towards temporary closure of the site. A status of temporary closure requires Fitchburg to monitor the site until a feasible permanent remediation alternative can be developed and completed.

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. Fitchburg had filed suit against several of its former insurance carriers seeking coverage for past and future environmental response costs at the site. In January 2011, Fitchburg settled with the remaining insurance carriers for approximately $2.0 million and received these payments in the first quarter of 2011. Any recovery that Fitchburg receives from insurance or third-parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are shared equally between Fitchburg and its gas customers.

Fitchburg is in the process of developing long-range plans for a feasible permanent remediation solution for the Sawyer Passway site, including alternatives for re-use of the site. Included on the Company’s Consolidated Balance Sheets at December 31, 2011 and 2010 in Environmental Obligations are accrued liabilities totaling $12.0 million and $12.0 million, respectively, related to estimated future clean-up 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.

Northern Utilities Manufactured Gas Plant Sites—Northern Utilities has an extensive program to identify, investigate and remediate former 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, and Scarborough sites. The sites in Lewiston and Portland have been investigated and remedial activities are currently underway. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs 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 the Company’s Consolidated Balance Sheets at December 31, 2011 and 2010 are current and non-current accrued liabilities totaling $2.7 million and $2.6 million, respectively, associated with Northern Utilities environmental remediation obligations for these former MGP sites. A corresponding Regulatory Asset was recorded to reflect that the recovery of these environmental remediation cost is probable through the regulatory process.

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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 2011 and 2010.

ENVIRONMENTAL OBLIGATIONS

(Millions) |  | December 31, |
|  | 2011 |  |  | 2010 |
Total Environmental Obligations—Balance at Beginning of Period |  | $ | 14.6 |  |  | $ | 14.5 |
Changes in Estimates |  |  | 0.1 |  |  |  | 0.2 |
Liabilities Assumed |  |  | — |  |  |  | — |
Less: Payments / Reductions |  |  | — |  |  |  | 0.1 |
Total Environmental Obligations—Balance at End of Period |  |  | 14.7 |  |  |  | 14.6 |
Less: Current Portion (1) |  |  | 0.2 |  |  |  | 0.1 |
Environmental Obligations – noncurrent – Balance at End of Period |  | $ | 14.5 |  |  | $ | 14.5 |

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

Note 6: Bad Debts

Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2011, 2010 and 2009, the Company recorded provisions for the energy commodity portion of bad debts of $1.8 million, $1.4 million and $1.9 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 2009 – 2011 ($ millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

|  | Balance at Beginning of Period |  |  | (a) Other |  |  | Provision |  |  | Recoveries |  |  | Accounts Written Off |  |  | Balance at End of Period |
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 |
Year Ended December 31, 2010 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 1.7 |  |  | $ | — |  |  | $ | 2.0 |  |  | $ | 0.2 |  |  | $ | 2.1 |  |  | $ | 1.8 |
Gas |  |  | 0.7 |  |  |  | — |  |  |  | 2.5 |  |  |  | 0.4 |  |  |  | 2.9 |  |  |  | 0.7 |
Other |  |  | 0.1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 0.1 |
|  | $ | 2.5 |  |  | $ | — |  |  | $ | 4.5 |  |  | $ | 0.6 |  |  | $ | 5.0 |  |  | $ | 2.6 |
Year Ended December 31, 2009 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 1.1 |  |  | $ | — |  |  | $ | 2.3 |  |  | $ | 0.2 |  |  | $ | 1.9 |  |  | $ | 1.7 |
Gas |  |  | 1.8 |  |  |  | 0.5 |  |  |  | 1.4 |  |  |  | 0.3 |  |  |  | 3.3 |  |  |  | 0.7 |
Other |  |  | 0.1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 0.1 |
|  | $ | 3.0 |  |  | $ | 0.5 |  |  | $ | 3.7 |  |  | $ | 0.5 |  |  | $ | 5.2 |  |  | $ | 2.5 |

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(a) | Includes Allowance for Doubtful Accounts of Northern Utilities and Granite State, which were acquired on December 1, 2008.

Note 7: Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2011, 2010 and 2009 are shown in the table below:

|  | ($000’s) |
|  | 2011 |  |  | 2010 |  |  | 2009 |
Current Federal Tax Provision (Benefit) |  |  |  |  |  |  |  |  |  |  |  |
Current Benefit of Operating Loss Carrybacks |  | $ | — |  |  | $ | (6,026 | ) |  | $ | (3,226 | )
Total Current Federal Tax Provision (Benefit) |  |  | — |  |  |  | (6,026 | ) |  |  | (3,226 | )
Deferred Federal Tax Provision (Benefit) |  |  |  |  |  |  |  |  |  |  |  |
Utility Plant Differences |  |  | 13,002 |  |  |  | 11,821 |  |  |  | 8,716 |
Net Operating Loss Carryforwards |  |  | (4,844 | ) |  |  | (5,520 | ) |  |  | — |
Regulatory Assets and Liabilities |  |  | 513 |  |  |  | 3,338 |  |  |  | (1,308 | )
Other, net |  |  | (695 | ) |  |  | (480 | ) |  |  | (120 | )
Total Deferred Federal Tax Provision (Benefit) |  |  | 7,976 |  |  |  | 9,159 |  |  |  | 7,288 |
Total Federal Tax Provision |  |  | 7,976 |  |  |  | 3,133 |  |  |  | 4,062 |
State |  |  |  |  |  |  |  |  |  |  |  |
Current |  |  | 1,358 |  |  |  | 28 |  |  |  | 1,578 |
Deferred |  |  | 691 |  |  |  | 1,303 |  |  |  | (218 | )
Total State Tax Provision |  |  | 2,049 |  |  |  | 1,331 |  |  |  | 1,360 |
Total Provision for Federal and State Income Taxes |  | $ | 10,025 |  |  | $ | 4,464 |  |  | $ | 5,422 |

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:

|  | 2011 |  |  | 2010 |  |  | 2009 |
Statutory Federal Income Tax Rate |  |  | 34 | % |  |  | 34 | % |  |  | 34 | %
Income Tax Effects of: |  |  |  |  |  |  |  |  |  |  |  |
State Income Taxes, Net |  |  | 5 |  |  |  | 6 |  |  |  | 6 |
Utility Plant Differences |  |  | (1 | ) |  |  | (7 | ) |  |  | (3 | )
Other, Net |  |  | — |  |  |  | (1 | ) |  |  | (1 | )
Effective Income Tax Rate |  |  | 38 | % |  |  | 32 | % |  |  | 36 | %

Temporary differences which gave rise to deferred tax assets and liabilities in 2011 and 2010 are shown below:

Deferred Income Taxes (000’s) |  | 2011 |  |  | 2010 |
Depreciation and Utility Plant |  | $ | 57,809 |  |  | $ | 44,608 |
Net Operating Loss Carryforwards |  |  | (11,656 | ) |  |  | (8,567 | )
AMT Tax Credit Carryforwards |  |  | (1,366 | ) |  |  | (1,366 | )
Regulatory Assets / Liabilities & Mechanisms |  |  | 32,627 |  |  |  | 33,421 |
Retirement Benefit Obligations |  |  | (33,591 | ) |  |  | (25,155 | )
Other, net |  |  | 2,463 |  |  |  | 883 |
Total Deferred Income Tax Liabilities |  | $ | 46,286 |  |  | $ | 43,824 |

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.

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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, 2010 with the Internal Revenue Service (IRS) in September 2011. As a result, the Company generated net operating loss (NOL) carryforwards for income tax purposes of $9.5 million.

As of December 31, 2011, the Company had recorded cumulative federal and state NOL carryforward assets of $11.7 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, 2011, the Company had $1.4 million of Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

In its federal income tax return filings for the year ended December 31, 2009, the Company recognized NOL carrybacks against its federal taxable income for the years ended December 31, 2004, 2005, and 2007 in the amounts of $1.1 million, $12.8 million, and $9.6 million, respectively. The carryback of the 2009 NOL resulted in tax refunds of $7.5 million, which were received in 2011.

According to Internal Revenue Code (IRC) rules, NOL refunds in excess of $2.0 million fall under the jurisdiction of the Joint Committee of Congress (Joint Committee) and are subject to review by the IRS and attorneys of the Joint Committee. As a result, the Company, on April 1, 2011, received notice that its federal income tax return filing for the year ended December 31, 2009 would be under examination by the IRS. The IRS is currently performing field work as part of their audit procedures. In addition, because of the application of the 2009 NOL, tax periods ended December 31, 2004, 2005 and 2007 are subject to examination to the extent of the application of the NOL to those periods. The Company believes that the ultimate resolution of this examination will not have a material impact on the Company’s consolidated financial position or results of operations.

On March 3, 2011 the Company received notice of approval from the Joint Committee regarding the settlement between the Company and the IRS for tax years ending December 31, 2006, December 31, 2007, and December 31, 2008, which were previously under examination. As a result of the settlement, in November 2010, the Company paid $1.7 million and $0.2 million in taxes and interest, respectively, principally for certain timing items deducted in 2008 related to emergency storm restoration costs; which, upon IRS review, were allowed to be deducted in the 2009 federal income tax returns. 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.

The Company evaluated its tax positions at December 31, 2011 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any unrecognized tax liabilities or assets as defined by the FASB Codification is required. The Company does not have any unrecognized tax positions for which it is reasonably possible that the total amounts recognized will significantly change within the next 12 months. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2008; December 31, 2009; and December 31, 2010.

Note 8: Segment Information

Unitil reports four segments: utility electric operations, utility gas operations, other, and non-regulated. Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine.

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Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to major natural gas pipelines and access to North American pipeline supplies. 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 NHPUC, MDPU, and MPUC. Assets allocated to each segment are based upon specific identification of such assets provided by Company records.

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The following table provides significant segment financial data for the years ended December 31, 2011, 2010 and 2009 (Millions):

Year Ended December 31, 2011 |  | Electric |  |  | Gas |  |  | Other |  |  | Non- Regulated |  |  | Total |
Revenues |  | $ | 188.1 |  |  | $ | 159.2 |  |  | $ | — |  |  | $ | 5.5 |  |  | $ | 352.8 |
Interest Income |  |  | 0.7 |  |  |  | 0.5 |  |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 1.4 |
Interest Expense |  |  | 9.4 |  |  |  | 10.7 |  |  |  | 1.7 |  |  |  | — |  |  |  | 21.8 |
Depreciation & Amortization Expense |  |  | 14.2 |  |  |  | 13.6 |  |  |  | 1.5 |  |  |  | — |  |  |  | 29.3 |
Income Tax Expense (Benefit) |  |  | 5.2 |  |  |  | 4.3 |  |  |  | (0.6 | ) |  |  | 1.1 |  |  |  | 10.0 |
Segment Profit (Loss) |  |  | 7.8 |  |  |  | 6.7 |  |  |  | 0.1 |  |  |  | 1.7 |  |  |  | 16.3 |
Segment Assets |  |  | 380.7 |  |  |  | 407.5 |  |  |  | 6.5 |  |  |  | 5.5 |  |  |  | 800.2 |
Capital Expenditures |  |  | 20.3 |  |  |  | 33.6 |  |  |  | 3.2 |  |  |  | — |  |  |  | 57.1 |
Year Ended December 31, 2010 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 203.7 |  |  | $ | 150.1 |  |  | $ | — |  |  | $ | 4.6 |  |  | $ | 358.4 |
Interest Income |  |  | 3.2 |  |  |  | 0.5 |  |  |  | 0.2 |  |  |  | 0.1 |  |  |  | 4.0 |
Interest Expense |  |  | 9.6 |  |  |  | 10.5 |  |  |  | 2.0 |  |  |  | — |  |  |  | 22.1 |
Depreciation & Amortization Expense |  |  | 13.9 |  |  |  | 14.2 |  |  |  | 0.8 |  |  |  | — |  |  |  | 28.9 |
Income Tax Expense (Benefit) |  |  | 3.7 |  |  |  | (0.7 | ) |  |  | 0.5 |  |  |  | 1.0 |  |  |  | 4.5 |
Segment Profit (Loss) |  |  | 8.0 |  |  |  | 1.4 |  |  |  | (1.4 | ) |  |  | 1.5 |  |  |  | 9.5 |
Segment Assets |  |  | 377.7 |  |  |  | 370.8 |  |  |  | 5.7 |  |  |  | 5.4 |  |  |  | 759.6 |
Capital Expenditures |  |  | 19.8 |  |  |  | 27.4 |  |  |  | 2.4 |  |  |  | — |  |  |  | 49.6 |
Year Ended December 31, 2009 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 209.9 |  |  | $ | 152.8 |  |  | $ | — |  |  | $ | 4.3 |  |  | $ | 367.0 |
Interest Income |  |  | 3.6 |  |  |  | 0.5 |  |  |  | 0.7 |  |  |  | — |  |  |  | 4.8 |
Interest Expense |  |  | 9.1 |  |  |  | 9.7 |  |  |  | 1.8 |  |  |  | — |  |  |  | 20.6 |
Depreciation & Amortization Expense |  |  | 14.0 |  |  |  | 12.8 |  |  |  | 0.6 |  |  |  | — |  |  |  | 27.4 |
Income Tax Expense |  |  | 2.4 |  |  |  | 1.9 |  |  |  | 0.1 |  |  |  | 1.0 |  |  |  | 5.4 |
Segment Profit |  |  | 4.9 |  |  |  | 3.3 |  |  |  | 0.1 |  |  |  | 1.6 |  |  |  | 9.9 |
Segment Assets |  |  | 365.6 |  |  |  | 349.7 |  |  |  | 7.3 |  |  |  | 2.6 |  |  |  | 725.2 |
Capital Expenditures |  |  | 27.7 |  |  |  | 30.0 |  |  |  | 1.0 |  |  |  | — |  |  |  | 58.7 |

Note 9: Retirement Benefit Plans

The Company sponsors the following retirement benefit plans to provide certain pension and postretirement 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. In September 2009, the Company amended the Pension Plan as follows:

| • |  | The Pension Plan was closed to non-union employees hired on or after January 1, 2010.

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| • |  | All non-union employees hired before January 1, 2010 had a choice of either:

| • |  | Remaining in the Pension Plan with the existing set of benefits, or

| • |  | Electing to move to Unitil Corporation’s enhanced Tax Deferred Savings and Investment Plan. Non-union employees who elected this option received a frozen benefit from the existing Pension Plan for all of the benefits that they had accrued to December 31, 2009. This frozen benefit will not grow with future salary increases or future service. Non-union employees who elected this option will receive an enhanced employer matching contribution as well as a Company contribution in the Unitil Corporation Tax Deferred Savings and Investment Plan.

| • |  | Union employees were not affected by this amendment.

In September 2010, the Company amended the Pension Plan as follows:

| • |  | The Pension Plan was closed to United Steelworker Local 12012-6 employees hired on or after January 1, 2011.

| • |  | All United Steelworker Local 12012-6 employees hired before January 1, 2011 had a choice of either:

| • |  | Remaining in the Pension Plan with the existing set of benefits, or

| • |  | Electing to move to Unitil Corporation’s enhanced Tax Deferred Savings and Investment Plan. The United Steelworker Local 12012-6 employees who elected this option received a frozen benefit from the existing Pension Plan for all of the benefits that they had accrued to December 31, 2010. This frozen benefit will not grow with future salary increases or future service. The employees who elected this option will receive an enhanced employer matching contribution as well as a Company contribution in the Unitil Corporation Tax Deferred Savings and Investment Plan.

| • |  | All other union employees were not affected by this amendment.

| • |  | 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. In 2009, the Company made the following changes to the PBOP Plan.

Changes to Utility Workers Union of America Local 341 Benefits

A new Collective Bargaining Agreement (Agreement) was entered into between Northern Utilities, Granite State and the Utility Workers Union of America Local 341 (UWUA) for the period April 1, 2009 through March 31, 2012. Included in the Agreement were changes to retiree medical benefits under the Plan. These changes are as follows:

| • |  | Retirees under sixty-five (65) years and their dependents will be covered by the medical benefits provided by the PBOP Plan. Early retirees will be responsible for contributing 20% of the premium for medical insurance for themselves and their dependents until age sixty-five (65).

| • |  | Retirees over sixty-five (65) years will be covered by a Supplement to Medicare Plan and will be responsible for a 20% premium cost sharing.

| • |  | For all employees hired on or after April 1, 2009, no post-65 retiree medical coverage will be provided.

| • |  | The Company is to determine post-65 drug coverage to be offered to all future retirees eligible for retiree medical.

These above-referenced retiree medical provisions were effective January 1, 2010.

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Changes to United Steelworker Local 12012-6 Benefits

A new Collective Bargaining Agreement (Agreement) was entered into between Northern Utilities and United Steelworker Local 12012-6 (USW) for the period June 6, 2010 through June 5, 2014. Included in the Agreement were changes to retiree medical benefits under the Plan. These changes are as follows:

| • |  | Retirees under sixty-five (65) years and their dependents will be covered by the medical benefits provided by the PBOP Plan. Early retirees will be responsible for contributing 20% of the premium for medical insurance for themselves and their dependents until age sixty-five (65).

| • |  | Retirees over sixty-five (65) years will be covered by a Supplement to Medicare Plan and will be responsible for a 20% premium cost sharing.

| • |  | For all employees hired on or after June 6, 2010, no post-65 retiree medical coverage will be provided.

These above-referenced retiree medical provisions were effective June 6, 2010.

Changes to Non-Union Employee Benefits

In September 2009, the Company announced the following PBOP Plan changes, effective January 1, 2010, for non-union employees:

| • |  | Employees who retire on or after January 1, 2010 will pay 20% of the cost of their retiree medical benefits.

| • |  | Employees who retire on or after January 1, 2010 will not receive any cash payments towards their Medicare premiums.

| • |  | Employees who are hired on or after January 1, 2010 will only be provided with company subsidized medical insurance until they reach age 65 and will not receive a Medicare supplement plan after age 65.

| • |  | 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:

|  | 2011 |  |  | 2010 |  |  | 2009 |
Used to Determine Plan costs for years ended December 31: |  |  |  |  |  |  |  |  |
Discount Rate (1) |  |  | 5.35 | % |  |  | 5.75 | % |  |  | 6.25 | %
Rate of Compensation Increase |  |  | 3.50 | % |  |  | 3.50 | % |  |  | 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 |  |  | 7.00 | % |  |  | 7.50 | % |  |  | 8.00 | %
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) |  | $ | 909 |  |  | $ | 728 |  |  | $ | 735 |
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s) |  | $ | (705 | ) |  | $ | (565 | ) |  | $ | (576 | )

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(1) | As a result of the changes to the PBOP Plan in September 2009 discussed above, the Company was required to update the discount rate used in determining the PBOP Plan costs for the remainder of 2009. Based on the market rates for long-term bonds at that time, the Company assumed a discount rate of 5.50% for the PBOP Plan from September through December of 2009.

Used to Determine Benefit Obligations at December 31: |  |  |  |  |  |  |  |  |
Discount Rate |  |  | 4.60 | % |  |  | 5.35 | % |  |  | 5.75 | %
Rate of Compensation Increase |  |  | 3.00 | % |  |  | 3.50 | % |  |  | 3.50 | %
Health Care Cost Trend Rate Assumed for Next Year |  |  | 6.50 | % |  |  | 7.00 | % |  |  | 7.50 | %
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) |  | $ | 9,109 |  |  | $ | 7,530 |  |  | $ | 5,887 |
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s) |  | $ | (7,217 | ) |  | $ | (5,997 | ) |  | $ | (4,704 | )

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 2011, 2010 and 2009, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $325,000, $300,000 and $300,000, respectively, in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2011, 2010 and 2009 was 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 |
|  | 2011 |  |  | 2010 |  |  | 2009 |  |  | 2011 |  |  | 2010 |  |  | 2009 |  |  | 2011 |  |  | 2010 |  |  | 2009 |
Service Cost |  | $ | 2,941 |  |  | $ | 2,608 |  |  | $ | 2,282 |  |  | $ | 1,918 |  |  | $ | 1,466 |  |  | $ | 1,417 |  |  | $ | 285 |  |  | $ | 285 |  |  | $ | 217 |
Interest Cost |  |  | 4,684 |  |  |  | 4,457 |  |  |  | 4,294 |  |  |  | 2,279 |  |  |  | 2,016 |  |  |  | 2,269 |  |  |  | 227 |  |  |  | 227 |  |  |  | 181 |
Expected Return on Plan Assets |  |  | (4,840 | ) |  |  | (4,181 | ) |  |  | (4,432 | ) |  |  | (818 | ) |  |  | (599 | ) |  |  | (440 | ) |  |  | — |  |  |  | — |  |  |  | — |
Prior Service Cost Amortization |  |  | 249 |  |  |  | 253 |  |  |  | 264 |  |  |  | 1,729 |  |  |  | 1,579 |  |  |  | 1,634 |  |  |  | 11 |  |  |  | 2 |  |  |  | (2 | )
Transition Obligation Amortization |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 21 |  |  |  | 21 |  |  |  | 21 |  |  |  | — |  |  |  | — |  |  |  | — |
Curtailment Loss |  |  | — |  |  |  | 41 |  |  |  | 32 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Actuarial Loss Amortization |  |  | 3,132 |  |  |  | 2,406 |  |  |  | 1,598 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 78 |  |  |  | 133 |  |  |  | 70 |
Sub-total |  |  | 6,166 |  |  |  | 5,584 |  |  |  | 4,038 |  |  |  | 5,129 |  |  |  | 4,483 |  |  |  | 4,901 |  |  |  | 601 |  |  |  | 647 |  |  |  | 466 |
Amounts Capitalized and Deferred |  |  | (2,590) |  |  |  | (2,240 | ) |  |  | (1,409 | ) |  |  | (1,622 | ) |  |  | (1,183 | ) |  |  | (1,642 | ) |  |  | — |  |  |  | — |  |  |  | — |
NPBC Recognized |  | $ | 3,576 |  |  | $ | 3,344 |  |  | $ | 2,629 |  |  | $ | 3,507 |  |  | $ | 3,300 |  |  | $ | 3,259 |  |  | $ | 601 |  |  | $ | 647 |  |  | $ | 466 |

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 $3.8 million, $1.9 million and $0.1 million for the Pension, PBOP and SERP plans, respectively.

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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 2011, 2010 and 2009 before capitalization and deferral was $6.2 million, $5.6 million and $4.0 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2011, 2010 and 2009 would have been $5.7 million, $6.2 million and $6.3 million respectively.

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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: |  | 2011 |  |  | 2010 |  |  | 2011 |  |  | 2010 |  |  | 2011 |  |  | 2010 |
Plan Assets at Beginning of Year |  | $ | 54,100 |  |  | $ | 47,082 |  |  | $ | 8,862 |  |  | $ | 6,306 |  |  | $ | — |  |  | $ | — |
Actual Return on Plan Assets |  |  | 225 |  |  |  | 5,901 |  |  |  | 108 |  |  |  | 922 |  |  |  | — |  |  |  | — |
Employer Contributions |  |  | 8,813 |  |  |  | 4,302 |  |  |  | — |  |  |  | 3,482 |  |  |  | 53 |  |  |  | 53 |
Participant Contributions |  |  | — |  |  |  | — |  |  |  | 13 |  |  |  | — |  |  |  | — |  |  |  | — |
Acquired Plan Assets |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Benefits Paid |  |  | (3,438 | ) |  |  | (3,185 | ) |  |  | (1,644 | ) |  |  | (1,848 | ) |  |  | (53 | ) |  |  | (53 | )
Plan Assets at End of Year |  | $ | 59,700 |  |  | $ | 54,100 |  |  | $ | 7,339 |  |  | $ | 8,862 |  |  | $ | — |  |  | $ | — |
Change in PBO: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
PBO at Beginning of Year |  | $ | 89,393 |  |  | $ | 79,288 |  |  | $ | 43,344 |  |  | $ | 35,694 |  |  | $ | 4,263 |  |  | $ | 3,979 |
Service Cost |  |  | 2,941 |  |  |  | 2,608 |  |  |  | 1,918 |  |  |  | 1,466 |  |  |  | 285 |  |  |  | 285 |
Interest Cost |  |  | 4,684 |  |  |  | 4,457 |  |  |  | 2,279 |  |  |  | 2,016 |  |  |  | 227 |  |  |  | 227 |
Participant Contributions |  |  | — |  |  |  | — |  |  |  | 13 |  |  |  | — |  |  |  | — |  |  |  | — |
Plan Amendments |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,683 |  |  |  | — |  |  |  | 138 |
Curtailment Gain |  |  | — |  |  |  | (1 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Benefits Paid |  |  | (3,438 | ) |  |  | (3,185 | ) |  |  | (1,644 | ) |  |  | (1,848 | ) |  |  | (53 | ) |  |  | (53 | )
Actuarial (Gain) or Loss |  |  | 9,139 |  |  |  | 6,226 |  |  |  | 5,020 |  |  |  | 4,333 |  |  |  | (107 | ) |  |  | (313 | )
PBO at End of Year |  | $ | 102,719 |  |  | $ | 89,393 |  |  | $ | 50,930 |  |  | $ | 43,344 |  |  | $ | 4,615 |  |  | $ | 4,263 |
Funded Status: Assets vs PBO |  | $ | (43,019 | ) |  | $ | (35,293 | ) |  | $ | (43,591 | ) |  | $ | (34,482 | ) |  | $ | (4,615 | ) |  | $ | (4,263 | )

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of their retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets of $55.3 million and $47.1 million at December 31, 2011 and 2010, respectively, to recognize 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 $91.3 million and $78.4 million as of December 31, 2011 and 2010, respectively. The ABO for the SERP was $0.5 million and $0.5 million as of December 31, 2011 and 2010, 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

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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 is being amortized over seven years with annual payments of $1.7 million, beginning in 2010. The $1.7 million payments for 2010 and 2011 are 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 has evaluated the two alternative shortfall amortization periods under the Relief Act and made the decision to continue with the seven year amortization period. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2012 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 |
|  | 2011 |  |  | 2010 |  |  | 2009 |  |  | 2011 |  |  | 2010 |  |  | 2009 |  |  | 2011 |  |  | 2010 |  |  | 2009 |
Employer Contributions |  | $ | 8,813 |  |  | $ | 4,302 |  |  | $ | 4,227 |  |  | $ | — |  |  | $ | 3,482 |  |  | $ | 2,800 |  |  | $ | 53 |  |  | $ | 53 |  |  | $ | 53 |
Participant Contributions |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 13 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Benefit Payments |  | $ | 3,438 |  |  | $ | 3,185 |  |  | $ | 3,742 |  |  | $ | 1,644 |  |  | $ | 1,848 |  |  | $ | 1,731 |  |  | $ | 53 |  |  | $ | 53 |  |  | $ | 53 |

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

Estimated Future Benefit Payments |
|  | Pension |  |  | PBOP |  |  | SERP |
2012 |  | $ | 4,040 |  |  | $ | 1,762 |  |  | $ | 52 |
2013 |  |  | 4,197 |  |  |  | 1,835 |  |  |  | 302 |
2014 |  |  | 4,466 |  |  |  | 1,941 |  |  |  | 301 |
2015 |  |  | 4,570 |  |  |  | 2,035 |  |  |  | 299 |
2016 |  |  | 4,738 |  |  |  | 2,088 |  |  |  | 298 |
2017 - 2021 |  | $ | 28,659 |  |  | $ | 12,214 |  |  | $ | 1,497 |

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, 47% in fixed income 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 2012 |  |  | Actual Allocation at December 31, |
|  |  | 2011 |  |  | 2010 |  |  | 2009 |
Equity Funds |  |  | 48 | % |  |  | 49 | % |  |  | 58 | % |  |  | 59 | %
Debt Funds |  |  | 47 | % |  |  | 46 | % |  |  | 42 | % |  |  | 40 | %
Asset Allocation Fund(1) |  |  | 5 | % |  |  | 5 | % |  |  | 0 | % |  |  | 1 | %
Total |  |  |  |  |  |  | 100 | % |  |  | 100 | % |  |  | 100 | %

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

PBOP Plan |  | Target Allocation 2012 |  |  | Actual Allocation at December 31, |
|  | 2011 |  |  | 2010 |  |  | 2009 |
Equity Funds |  |  | 55 | % |  |  | 55 | % |  |  | 56 | % |  |  | 56 | %
Debt Funds |  |  | 45 | % |  |  | 45 | % |  |  | 44 | % |  |  | 44 | %
Total |  |  |  |  |  |  | 100 | % |  |  | 100 | % |  |  | 100 | %

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The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.50% for 2011. 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.

The 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.

Valuation Techniques

There have been no changes in the valuation techniques used during the current period.

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2011 and 2010 are as follows ($000’s):

|  | Fair Value Measurements at Reporting Date Using |
Description |  | Balance as of December 31, 2011 |  |  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  |  | Significant Other Observable Inputs (Level 2) |  |  | Significant Unobservable Inputs (Level 3) |
Pension Plan Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mutual Funds: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity Funds |  | $ | 29,094 |  |  | $ | 29,094 |  |  | $ | — |  |  | $ | — |
Fixed Income Funds |  |  | 27,697 |  |  |  | 27,697 |  |  |  | — |  |  |  | — |
Asset Allocation Fund |  |  | 2,909 |  |  |  | 2,909 |  |  |  | — |  |  |  | — |
Total Assets |  | $ | 59,700 |  |  | $ | 59,700 |  |  | $ | — |  |  | $ | — |

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|  | Fair Value Measurements at Reporting Date Using |
Description |  | Balance as of December 31, 2010 |  |  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  |  | Significant Other Observable Inputs (Level 2) |  |  | Significant Unobservable Inputs (Level 3) |
Pension Plan Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mutual Funds: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity Funds |  | $ | 31,625 |  |  | $ | 31,625 |  |  | $ | — |  |  | $ | — |
Fixed Income Funds |  |  | 22,475 |  |  |  | 22,475 |  |  |  | — |  |  |  | — |
Total Assets |  | $ | 54,100 |  |  | $ | 54,100 |  |  | $ | — |  |  | $ | — |

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2011 and 2010 are as follows ($000’s):

|  | Fair Value Measurements at Reporting Date Using |
Description |  | Balance as of December 31, 2011 |  |  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  |  | Significant Other Observable Inputs (Level 2) |  |  | Significant Unobservable Inputs (Level 3) |
PBOP Plan Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mutual Funds: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed Income Funds |  | $ | 3,311 |  |  | $ | 3,311 |  |  | $ | — |  |  | $ | — |
Index Funds |  |  | 2,977 |  |  |  | 2,977 |  |  |  |  |  |  |  |  |
Equity Funds |  |  | 1,051 |  |  |  | 1,051 |  |  |  |  |  |  |  |  |
Total Assets |  | $ | 7,339 |  |  | $ | 7,339 |  |  | $ | — |  |  | $ | — |

|  | Fair Value Measurements at Reporting Date Using |
Description |  | Balance as of December 31, 2010 |  |  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  |  | Significant Other Observable Inputs (Level 2) |  |  | Significant Unobservable Inputs (Level 3) |
PBOP Plan Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mutual Funds: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed Income Funds |  | $ | 3,936 |  |  | $ | 3,936 |  |  | $ | — |  |  | $ | — |
Index Funds |  |  | 3,580 |  |  |  | 3,580 |  |  |  |  |  |  |  |  |
Equity Funds |  |  | 1,346 |  |  |  | 1,346 |  |  |  |  |  |  |  |  |
Total Assets |  | $ | 8,862 |  |  | $ | 8,862 |  |  | $ | — |  |  | $ | — |

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.

In September 2009, the Company amended the Plan as follows:

For current non-union employees who elect to stay with the Company’s existing Pension Plan, there will be no changes in the 401(k) Plan. For those employees, the Company will continue to match contributions, with a maximum matching contribution of 3% of current compensation and those participants will be 100% vested in these company matching contributions once they have completed three years of service.

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For non-union employees who are hired on or after January 1, 2010, and for non-union employees who elect to move from the Company’s existing Pension Plan and accept a frozen pension benefit, the Company will provide the following enhancements to the 401(k) Plan:

| • |  | The Company will contribute 4% of base pay each year, regardless of whether or not the non-union employee elects to contribute to the 401(k) Plan.

| • |  | The Company will increase the matching contributions from 3% of base pay to 6% of base pay. This will be a 100% match of the first 6% of the non-union employee’s contributions.

| • |  | All Company contributions will be 100% vested at all times.

| • |  | New non-union employees will be automatically enrolled in the 401(k) Plan following the completion of 1,000 hours of service, with the automatic contribution rate of 3%. This contribution rate will automatically increase by 1% on January 1 of each year until the non-union employee’s contribution is 10% of pay. Non-union employees may elect to opt-out of the automatic enrollment and/or automatic increase features of the enhanced 401(k) Plan.

The Company’s contributions to the 401(k) Plan were $1,190,000, $980,000 and $671,000 for the years ended December 31, 2011, 2010, and 2009, respectively.

Note 10: 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, |
|  | 2011 |  |  | 2010 |  |  | 2011 |  |  | 2010 |  |  | 2011 |  |  | 2010 |  |  | 2011 |  |  | 2010 |
Total Operating Revenues |  | $ | 115.4 |  |  | $ | 113.0 |  |  | $ | 69.5 |  |  | $ | 71.4 |  |  | $ | 73.2 |  |  | $ | 76.1 |  |  | $ | 94.7 |  |  | $ | 97.9 |
Operating Income |  | $ | 13.4 |  |  | $ | 10.9 |  |  | $ | 4.2 |  |  | $ | 2.6 |  |  | $ | 5.2 |  |  | $ | 4.7 |  |  | $ | 14.4 |  |  | $ | 9.8 |
Net Income (Loss) Applicable to Common |  | $ | 8.7 |  |  | $ | 6.5 |  |  | $ | (0.8 | ) |  | $ | (2.1 | ) |  | $ | (1.6 | ) |  | $ | (0.1 | ) |  | $ | 10.0 |  |  | $ | 5.2 |
|  | Per Share Data: |
Earnings Per Common Share |  | $ | 0.81 |  |  | $ | 0.61 |  |  | $ | (0.08 | ) |  | $ | (0.19 | ) |  | $ | (0.15 | ) |  | $ | (0.01 | ) |  | $ | 0.92 |  |  | $ | 0.48 |
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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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, 2011. Based on this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of December 31, 2011 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, 2011, 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, 2011.

McGladrey and Pullen, LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2011, 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, 2011 that have materially affected, or are reasonably likely to materially affect, Unitil’s internal control over financial reporting.

Item 9B. | Other Information

None.

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PART III

Item 10. | Directors, Executive Officers of the Registrant and Corporate Governance

Information required by this Item is set forth in Part I, Item 1 of this Form 10-K and in the “Proposal 1: Election of Directors” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 19, 2012. Information regarding the Company’s Audit Committee is set forth in the “Corporate Governance and Policies of the Board” and “Committees of the Board” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 19, 2012. Information regarding the Company’s Code of Ethics is set forth in the “Corporate Governance and Policies of the Board” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 19, 2012.

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 19, 2012.

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” and “Compensation of Directors” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 19, 2012, as well as the Equity Compensation Plan Benefit 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 “Transactions with Related Persons” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 19, 2012.

Item 14. | Principal Accountant Fees and Services

Information required by this Item is set forth in the “Principal Accountant Fees and Services” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 19, 2012.

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PART IV

Item 15. | Exhibits and Financial Statement Schedules

(a) (1) and (2) – LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

The following financial statements are included herein under Part II, Item 8, Financial Statements and Supplementary Data:

| • |  | Reports of Independent Registered Public Accounting Firm

| • |  | Consolidated Balance Sheets—December 31, 2011 and 2010

| • |  | Consolidated Statements of Earnings for the years ended December 31, 2011, 2010, and 2009

| • |  | Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010, and 2009

| • |  | Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2011, 2010, and 2009

| • |  | 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 the Company. |  | Exhibit 3.1 to Form S-14 Registration Statement 2-93769 dated October 12, 1984
| 3.2 |  |  | Articles of Amendment to the Articles of Incorporation Filed on March 4, 1992. |  | Exhibit 3.2 to Form 10-K for 1991
| 3.3 |  |  | Articles of Amendment to the Articles of Incorporation Filed on September 23, 2008. |  | Exhibit 3.3 to Form S-3/A Registration Statement 333-15282 dated November 25, 2008
| 3.4 |  |  | Articles of Amendment to the Articles of Incorporation Filed on April 27, 2011 |  | Annex A to Form DEF 14A dated March 14, 2011
| 3.5 |  |  | By-laws of the Company. |  | Exhibit 4.4 to Form S-8 Registration Statement 333-73327 dated March 4, 1999
| 3.6 |  |  | Amended By-laws of the Company. |  | Exhibit 3.1 to Form 8-K dated September 21, 2011
| 3.7 |  |  | Articles of Exchange of Concord Electric Company (CECo), Exeter & Hampton Electric Company (E&H) and the Company. |  | Exhibit 3.3 to 10-K for 1984
| 3.8 |  |  | Articles of Exchange of CECo, E&H, and the Company—Stipulation of the Parties Relative to Recordation and Effective Date. |  | Exhibit 3.4 to Form 10-K for 1984
| 3.9 |  |  | The Agreement and Plan of Merger dated March 1, 1989 among the Company, Fitchburg Gas and Electric Light Company (Fitchburg) and UMC Electric Co., Inc. (UMC). |  | Exhibit 25(b) to Form 8-K dated March 1, 1989

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Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 3.10 |  |  | Amendment No. 1 to The Agreement and Plan of Merger dated March 1, 1989 among the Company, Fitchburg and UMC. |  | Exhibit 28(b) to Form 8-K dated December 14, 1989
| 3.11 |  |  | Stock Purchase Agreement among Nisource Inc., Bay State Gas Company and Unitil Corporation |  | Exhibit 2.1 to Form 8-K dated February 20, 2008
| 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
| 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
| 4.3 |  |  | Fitchburg Note Agreement dated January 26, 1999 for the 7.37% Notes due January 15, 2028. |  | Exhibit 4.25 to Form 10-K for 1999
| 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
| 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
| 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
| 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
| 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
| 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
| 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
| 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
| 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
| 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

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Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 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
| 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
| 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
| 10.7 | *** |  | Unitil Corporation 1998 Stock Option Plan. |  | Exhibit 10.12 to Form 10-K for 1998
| 10.8 | *** |  | Amended and Restated Unitil Corporation Management Incentive Plan effective as of June 19, 2008 as further amended on December 1, 2008. |  | Exhibit 10.8 to Form 10-K for 2008
| 10.9 |  |  | Entitlement Sale and Administrative Service Agreement with Select Energy. |  | Exhibit 10.14 to Form 10-K for 1999
| 10.10 |  |  | Amended and Restated Unitil Corporation 2003 Stock Plan. |  | Exhibit 10.1 to Form 8-K dated March 24, 2011
| 10.11 |  |  | Portfolio Sale and Assignment and Transition Service and Default Service Supply Agreement By and Among Unitil Power Corp., Unitil Energy Systems, Inc. and Mirant Americas Energy Marketing, LP. |  | Exhibit 10.17 to Form 10-K for 2002
| 10.12 |  |  | Unitil Corporation Tax Deferred Savings and Investment Plan—Trust Agreement. |  | Exhibit 10.1 to Form 10-Q for September 30, 2004
| 10.13 | *** |  | Amended and Restated Employment Agreement effective as of November 1, 2009 by and between Unitil Corporation and Robert G. Schoenberger. |  | Exhibit 10.1 to Form 8-K dated September 23, 2009
| 10.14 |  |  | Credit Agreement between Unitil Corporation and Bank of America, N.A. dated November 26, 2008. |  | Exhibit 10.1 to Form 8-K dated November 26, 2008
| 10.15 |  |  | Amendment Agreement dated as of January 2, 2009 to the Credit Agreement between Unitil Corporation and Bank of America, N.A. dated November 26, 2008. |  | Exhibit 10.1 to Form 8-K dated January 2, 2009
| 10.16 |  |  | Amendment Agreement dated as of March 16, 2009 to the Credit Agreement between Unitil Corporation and Bank of America, N.A. dated November 26, 2008. |  | Exhibit 10.1 to Form 8-K dated March 16, 2009
| 10.17 |  |  | Amendment Agreement dated as of October 13, 2009 to the Credit Agreement between Unitil Corporation and Bank of America, N.A. dated November 26, 2008. |  | Exhibit 10.1 to Form 8-K dated October 13, 2009
| 10.18 |  |  | Fourth Amendment Agreement dated October 8, 2010 by and among Unitil Corporation and Bank of America, N.A. |  | Exhibit 10.5 to Form 8-K dated October 8, 2010
| 10.19 |  |  | Fifth Amendment Agreement dated October 12, 2011 by and among Unitil Corporation and Bank of America, N.A. |  | Exhibit 10.6 to Form 8-K dated October 12, 2011
| 10.20 |  |  | Credit Agreement between Unitil Corporation and Royal Bank of Canada dated December 1, 2008. |  | Exhibit 10.2 to Form 8-K dated November 26, 2008
| 10.21 |  |  | Transition Services Agreement between Unitil Corporation and NiSource, Inc. dated December 1, 2008. |  | Exhibit 10.3 to Form 8-K dated November 26, 2008
| 10.22 |  |  | 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
| 10.23 |  |  | Unitil Corporation—Compensation of Directors. |  | Filed herewith

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Exhibit Number |  |  | Description of Exhibit |  | Reference*
| 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
| 16.1 |  |  | Letter Re: Change in Certifying Accountant |  | Exhibit 16.1 to Form 8-K dated September 22, 2010
| 21.1 |  |  | Statement Re: Subsidiaries of Registrant. |  | Filed herewith
| 23.1 |  |  | Consent of Independent Registered Public Accounting Firm. |  | Filed herewith
| 23.2 |  |  | 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 31, 2012 Announcing Earnings For the Quarter and Year Ended December 31, 2011 |  | 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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

|  |  |  | UNITIL CORPORATION
Date February 1, 2012 |  |  |  | By |  | /s/ ROBERT G. SCHOENBERGER
|  |  |  |  |  |  |  | Robert G. Schoenberger
|  |  |  |  |  |  |  | Chairman of the Board of Directors, Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature |  | Capacity |  | Date
/S/ ROBERT G. SCHOENBERGER Robert G. Schoenberger |  | Principal Executive Officer; Director |  | February 1, 2012
/S/ MARK H. COLLIN Mark H. Collin |  | Principal Financial Officer |  | February 1, 2012
/S/ LAURENCE M. BROCK Laurence M. Brock |  | Principal Accounting Officer |  | February 1, 2012
/S/ MICHAEL J. DALTON Michael J. Dalton |  | Director |  | February 1, 2012
/S/ ALBERT H. ELFNER, III Albert H. Elfner, III |  | Director |  | February 1, 2012
/S/ M. BRIAN O’SHAUGHNESSY M. Brian O’Shaughnessy |  | Director |  | February 1, 2012
/S/ WILLIAM D. ADAMS William D. Adams |  | Director |  | February 1, 2012
/S/ DR. SARAH P. VOLL Dr. Sarah P. Voll |  | Director |  | February 1, 2012
/S/ EBEN S. MOULTON Eben S. Moulton |  | Director |  | February 1, 2012
/S/ DAVID P. BROWNELL David P. Brownell |  | Director |  | February 1, 2012
/S/ EDWARD F. GODFREY Edward F. Godfrey |  | Director |  | February 1, 2012
/S/ MICHAEL B. GREEN Michael B. Green |  | Director |  | February 1, 2012
/S/ DR. ROBERT V. ANTONUCCI Dr. Robert V. Antonucci |  | Director |  | February 1, 2012

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EXHIBIT INDEX

Exhibit No. |  |  | Description
| 10.23 |  |  | Unitil Corporation—Compensation of Directors
| 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
| 23.2 |  |  | 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 31, 2012 Announcing Earnings For the Quarter and Year Ended December 31, 2011
| 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.

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