Edgar Filing: UNITIL CORP

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2012

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

Commission file number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)


New Hampshire		02-0381573
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

6 Liberty Lane West, Hampton, New Hampshire		03842-1720
(Address of principal executive offices)		(Zip Code)

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

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


Title of Each Class		Name of Exchange on Which Registered
Common Stock, No Par Value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K x

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Based on the closing price of the registrant’s common stock on June 30, 2012, the aggregate market value of common stock held by non-affiliates of the registrant was $359,089,609.

The number of the registrant’s common shares outstanding was 13,780,921 as of January 25, 2013.

Documents Incorporated by Reference:

Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held on April 18, 2013 are incorporated by reference into Part III of this Report

UNITIL CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2012

Table of Contents


Item	Description	Page
	PART I
1.	Business		1
	Unitil Corporation		1
	Operations		2
	Rates and Regulation		4
	Natural Gas Supply		4
	Electric Power Supply		5
	Environmental Matters		6
	Employees		7
	Available Information		8
	Directors and Executive Officers of the Registrant		8
	Investor Information		11
1A.	Risk Factors		12
1B.	Unresolved Staff Comments		18
2.	Properties		18
3.	Legal Proceedings		19
4.	Mine Safety Disclosures		19

	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		45
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		84
9A.	Controls and Procedures		84
9B.	Other Information		84

	PART III
10.	Directors, Executive Officers and Corporate Governance		85
11.	Executive Compensation		85
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		85
13.	Certain Relationships and Related Transactions, and Director Independence		85
14.	Principal Accountant Fees and Services		85

	PART IV
15.	Exhibits and Financial Statement Schedules		86
	Signatures		90

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 negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in Part I, Item 1A (Risk Factors) and the following:

•

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

•

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

•

customers’ preferred energy sources;

•

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

•

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

•

declines in the valuation of capital markets, which could require the Company to make substantial cash contributions to cover its pension obligations, and the Company’s ability to recover pension obligation costs in its rates;

•

general economic conditions, which could adversely affect (i) the Company’s customers and, consequently, the demand for the Company’s distribution services, (ii) the availability of credit and liquidity resources and (iii) certain of the Company’s counterparty’s obligations (including those of its insurers and lenders);

•

the Company’s ability to obtain debt or equity financing on acceptable terms;

•

increases in interest rates, which could increase the Company’s interest expense;

•

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

•

variations in weather, which could decrease demand for the Company’s distribution services;

•

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

•

numerous hazards and operating risks relating to the Company’s electric and natural gas distribution activities, which could result in accidents and other operating risks and costs;

•

catastrophic events;

•

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

•

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

•

increased competition.

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.

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 to approximately 175,400 customers throughout its service territories in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities: i) Unitil Energy, which provides electric service in the southeastern seacoast and state capital regions of New Hampshire, including the capital city of Concord, ii) Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts, and iii) Northern Utilities, which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland, which is the largest city in northern New England. In addition, Unitil is the parent company of Granite State, an interstate natural gas transmission pipeline company that provides interstate natural gas pipeline access and transportation services to Northern Utilities in its New Hampshire and Maine service territory. Together, Unitil’s three distribution utilities serve approximately 101,700 electric customers and 73,700 natural gas customers.


	Customers Served as of December 31, 2012
	Residential		Commercial & Industrial (C&I)		Total
Electric		87,062		14,612		101,674
Natural Gas		56,745		16,977		73,722

Total		143,807		31,589		175,396

Unitil’s distribution utilities had an investment in Net Utility Plant of $601.2 million at December 31, 2012. Unitil’s total operating revenue was $353.1 million in 2012. Unitil’s operating revenue is substantially 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, but currently has limited business and operating activities. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy in 2003 and divested of substantially all of its long-term power supply contracts through the sale of the entitlements to the electricity associated with those contracts.

Unitil also has three other wholly-owned non-utility subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology and energy supply management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are indirect subsidiaries that are wholly-owned by Unitil Resources. Usource provides energy brokering and advisory services to a national client base of large commercial and industrial customers. For segment information, see Note 8 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report.

OPERATIONS

Natural Gas Operations

Unitil’s natural gas operations include gas distribution utility operations and interstate gas transmission pipeline operations, discussed below. Revenue from Unitil’s gas operations was $160.6 million for 2012, which represents about 45% of Unitil’s total operating revenue.

Natural Gas Distribution Utility Operations

Unitil’s natural gas distribution operations are conducted through two of the Company’s operating utilities, Northern Utilities and Fitchburg. The primary business of Unitil’s natural gas utility operations is the local distribution of natural gas to customers in its service 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 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 58,300 customers in 44 New Hampshire and southern Maine communities, from Plaistow, New Hampshire in the south to the city of Portland, Maine and then extending to Lewiston-Auburn, Maine in the north. Northern Utilities has a diversified customer base both in Maine and New Hampshire. Commercial businesses include healthcare, education, government and retail. Northern Utilities’ industrial base includes manufacturers in the auto, housing, rubber, printing, textile, pharmaceutical, electronics, wire and food production industries as well as a military installation. Northern Utilities’ 2012 gas operating revenue was $124.0 million, of which approximately 39% was derived from residential firm sales and 61% from commercial/industrial firm sales.

Natural gas is supplied and distributed by Fitchburg to approximately 15,400 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 2012 gas operating revenue was $31.6 million, of which approximately 52% was derived from residential firm sales and 48% from commercial/industrial firm sales.

Gas Transmission Pipeline Operations

Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to North American pipeline supplies. Granite State had operating revenue of $5.0 million for 2012. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and to third-party marketers.

Electric Distribution Utility Operations

Unitil’s electric distribution operations are conducted through two of the Company’s utilities, Unitil Energy and Fitchburg. Revenue from Unitil’s electric utility operations was $187.0 million for 2012, 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 73,300 customers in New Hampshire in the capital city of Concord as well as parts of 12 surrounding towns and all or part of 18 towns in the southeastern and seacoast regions of New Hampshire, including the towns of Hampton, Exeter, Atkinson and Plaistow. Unitil Energy’s service territory consists of approximately 408 square miles. In addition, Unitil Energy’s service territory encompasses retail trading and recreation centers for the central and southeastern parts of the state and includes the Hampton Beach recreational area. These areas serve diversified commercial and industrial businesses, including manufacturing firms engaged in the production of electronic components, wire and plastics, healthcare and education. Unitil Energy’s 2012 electric operating revenue was $128.2 million, of which approximately 55% was derived from residential sales and 45% from C&I sales.

Fitchburg is engaged in the distribution of both electricity and natural gas in the greater Fitchburg area of north central Massachusetts. Fitchburg’s service territory encompasses approximately 170 square miles. Electricity is supplied and distributed by Fitchburg to approximately 28,400 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companies and printing, publishing and associated industries and educational institutions. Fitchburg’s 2012 electric operating revenue was $58.8 million, of which approximately 53% was derived from residential sales and 47% from C&I sales.

Seasonality

The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the heating season as a result of higher sales of natural gas due to cold weather. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by the weather conditions in both the winter and summer seasons.

Unitil Energy, Fitchburg and Northern Utilities are not dependent on a single customer or a few customers for their electric and natural gas sales.

Non-Regulated and Other Non-Utility Operations

Unitil’s non-regulated operations are conducted through Usource, a subsidiary of Unitil Resources. Usource provides energy brokering and advisory services to a national client base of large commercial and industrial customers. Revenue from Unitil’s non-regulated operations was $5.5 million in 2012.

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

income. For segment information, see Note 8 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report.

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 cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its natural gas transmission pipeline company may also recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost tracker rate mechanisms.

As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, Unitil’s customers, with the exception of Northern Utilities’ residential 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 and 2012, the Company completed base rate cases for: Unitil Energy; the electric and gas divisions of Fitchburg; the New Hampshire and Maine divisions 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; and $3.7 million and $8.7 million for the New Hampshire and Maine divisions, respectively, of Northern Utilities. Granite State received approval for an increase of $2.2 million in annual revenue. Additionally, in 2011 and 2012, the Company completed rate filings that resulted in increases in annual revenues, through step adjustments and cost tracker rate mechanisms, of: $1.5 million for Unitil Energy; $0.5 million for the electric division of Fitchburg; and $0.3 million for Granite State.

Also see Regulatory Matters in Part II, Item 7(Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 5 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on rates and regulation.

NATURAL GAS SUPPLY

Unitil manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.

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.

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 of year-round and seasonal transportation and underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and 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 a 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 2012, 75% of Unitil’s largest New Hampshire customers, representing 24% of total New Hampshire electric energy sales, and 90% of Unitil’s largest Massachusetts customers, representing 31% of total Massachusetts electric energy sales, are purchasing their electric power supply in the competitive market. However, most residential and small commercial customers continue to purchase their electric supply through Unitil’s distribution utilities under regulated energy rates and tariffs. We believe that the concentration of the competitive retail market on higher use customers has been a common experience throughout the New England electricity market.

Regulated Electric Power Supply

In order to provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts with various wholesale suppliers.

Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service energy supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential, small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements. On June 13, 2012, the MDPU approved, for a period of one year, Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-NE’s real-time market.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. On July 31, 2012, the NHPUC approved Unitil Energy’s request to modify its Default Service solicitation to a process where 100% of the Default Service requirements are acquired for six months. Unitil Energy is in the process of transitioning to this procurement strategy which will be completed in late 2013. Currently, Unitil Energy has a group of contracts of varying duration and percentage to meet its Default Service supply requirements.

The NHPUC and MDPU regularly review alternatives to their procurement policy, which may lead to future changes in this regulated power supply procurement structure.

Regional Electric Transmission and Power Markets

Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. The ISO-NE tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and support payments associated therewith. The most notable benefits of the ISO-NE are coordinated, reliable power system operation and a supportive business environment for the development of competitive electric markets.

Electric Power Supply Divestiture

In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

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, 2012, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

Protection, which allowed Fitchburg to achieve 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. Additionally, Northern Utilities has entered into a Letter of Intent with an unrelated third-party to redevelop the Portland site as a boat repair facility and to reduce and offset site remediation costs. 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 Environmental Matters in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 5 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on Environmental Matters.

EMPLOYEES

As of December 31, 2012, the Company and its subsidiaries had 467 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of December 31, 2012, 157 of the Company’s employees were represented by labor unions. There are 78 union employees covered by two separate collective bargaining agreements which expire on May 31, 2013 and June 5, 2014. The agreements provide discrete salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.

There are 35 union employees who are covered by a separate collective bargaining agreement which expires on March 31, 2017. The agreement includes discrete salary adjustments, established work practices and uniform benefit packages.

There are 39 union employees who are covered by a separate collective bargaining agreement which expires on May 31, 2018. The agreement includes discrete salary adjustments, established work practices and uniform benefit packages.

In October 2012, the Electric Systems Operators, which is a group of five employees, voted to be represented by a union. The terms have not yet been negotiated for a new collective bargaining agreement covering this group of five employees.

AVAILABLE INFORMATION

The Internet address for the Company’s website is www.unitil.com. On its website, the Company makes available, free of charge, its Securities and Exchange Commission (SEC) fillings, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other reports, as well as amendments to those reports. These reports are made available 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 executive officers as of January 30, 2013:


Name	Age		Position
Robert G. Schoenberger		62	Chairman of the Board, Chief Executive Officer and President
Mark H. Collin		53	Senior Vice President, Chief Financial Officer and Treasurer
Thomas P. Meissner, Jr.		50	Senior Vice President and Chief Operating Officer
Laurence M. Brock		59	Controller and Chief Accounting Officer
Todd R. Black		48	Senior Vice President, External Affairs and Customer Relations, Unitil Service
George E. Long, Jr.		56	Vice President, Administration, Unitil Service
Sandra L. Whitney		49	Corporate Secretary
William D. Adams		65	Director
Dr. Robert V. Antonucci		67	Director
David P. Brownell		69	Director
Lisa Crutchfield		49	Director
Michael J. Dalton		72	Director
Albert H. Elfner, III		68	Director
Edward F. Godfrey		63	Director
Michael B. Green		63	Director
Eben S. Moulton		66	Director
M. Brian O’Shaughnessy		69	Director
Dr. Sarah P. Voll		70	Director
David A. Whiteley		56	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 2015. 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 has also served as chairman and trustee of Exeter Health Resources, Exeter, New Hampshire, from 2012 to present, as well as from 1998 until 2009. Mr. Schoenberger also serves as a Director of the Edison Electric Institute, and as chairman of the Tocqueville Society of the Greater Seacoast (New Hampshire) United Way.

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.

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.

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.

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.

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 the 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 2015. 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.

Lisa Crutchfield has been a member of Unitil’s Board of Directors since December 2012. Ms. Crutchfield will stand for election to the Board of Directors at the Annual Meeting of Shareholders in April 2013. Ms. Crutchfield served as executive vice president of regulation and pricing for National Grid USA (National Grid), an international electric and gas company, in Waltham, Massachusetts, from 2008 to 2011. Prior to joining National Grid, Ms. Crutchfield served as senior vice president for regulatory and external affairs for PECO Energy Company, an Exelon Corporation company, located in Philadelphia, Pennsylvania from 2003 until 2008, and vice president of energy policy and strategy for Duke Energy Corporation in Charlotte, North Carolina from 1997 until 2000. Ms. Crutchfield also served as Vice Chairman of the Pennsylvania Public Utilities Commission from 1993 until 1997. Ms. Crutchfield recently

served as a member of the U.S. Department of Energy Electricity Advisory Committee from 2010 to 2012. She also was a member of the board of trustees for the University of Pennsylvania from 2005 to 2008 and for the University of North Carolina at Charlotte from 2000 to 2003.

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 will retire from the Board of Directors following the Annual Meeting of Shareholders in April 2013 as he has reached the mandatory retirement age of 72. Mr. Dalton retired as President and Chief Operating Officer of Unitil in 2003. Mr. Dalton is a member of the College Advisory Board of the UNH College of Engineering and Physical Science and 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 serves as a director of Main Street America Insurance Company (Main Street), Jacksonville, Florida, as well as chairman of the Main Street finance committee. Mr. Elfner is also a Chartered Financial Analyst.

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 will stand for re-election to the Board of Directors at the Annual Meeting of Shareholders in April 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 is also 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 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 2013. Mr. Moulton will stand for re-election to the Board of Directors at the Annual Meeting of Shareholders in April 2013. Mr. Moulton has been the managing partner of Seacoast Capital Corporation (a private investment company), of Danvers, Massachusetts, 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 of three copper industry trade associations, three manufacturing associations in New York State regarding energy-related issues, the Economic Development Growth Enterprise (EDGE) of the Mohawk Valley and the Coalition for a Prosperous America (CPA). Mr. O’Shaughnessy is the chief co-chair of CPA.

Dr. Sarah P. Voll has been a member of Unitil’s Board of Directors since January 2003, and her current term will expire in 2015. 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.

David A. Whiteley has been a member of Unitil’s Board of Directors since December 2012. Mr. Whiteley will stand for election to the Board of Directors at the Annual Meeting of Shareholders in April 2013. Mr. Whiteley has been the owner of Whiteley BPS Planning Ventures LLC, St. Louis, Missouri, a private consulting firm specializing in utility planning, operations, and management, since 2009. He has also served as the executive director of the Eastern Interconnection Planning Collaborative since 2011. Mr. Whiteley served as an executive vice-president of the North American Electric Reliability Corporation from 2007 to 2009. Prior to that, Mr. Whiteley served as senior vice president—Energy Delivery Services for Ameren Corporation, a multi-state electric and gas utility, headquartered in St. Louis, Missouri from 2005 to 2007 and as senior vice president—Energy Delivery, from 2003 to 2005. Mr. Whiteley started his employment at Ameren Corporation’s predecessor, Union Electric Company, in 1978. Mr. Whiteley is a registered professional engineer in the states of Missouri and Illinois.

INVESTOR INFORMATION

Annual Meeting

The Company’s annual meeting of shareholders is scheduled to be held at the offices of the Company, 6 Liberty Lane West, Hampton, New Hampshire, on Thursday, April 18, 2013, at 10:30 a.m.

Transfer Agent

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

Computershare Investor Services

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

•

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

•

Dividend Reinvestment and Stock Purchase Plan:

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

•

Dividend Direct Deposit Service:

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

•

Direct Registration:

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

Item 1A.

Risk Factors

Risks Relating to Our Business

The Company is subject to comprehensive regulation, which could adversely impact the rates it is able to charge, its authorized rate of return and its ability to recover costs. In addition, certain regulatory authorities have the power to impose financial penalties and other sanctions on the Company, which could adversely affect the Company’s financial condition or results of operations.

The Company is subject to comprehensive regulation by federal regulatory authorities (including the FERC) and state regulatory authorities (including the NHPUC, MDPU and MPUC). These authorities regulate many aspects of the Company’s operations, including the rates that the Company can charge customers, the Company’s authorized rates of return, the Company’s ability to recover costs from its customers, construction and maintenance of the Company’s facilities, the Company’s safety protocols and procedures, the Company’s ability to issue securities, the Company’s accounting matters, and transactions between the Company and its affiliates. The Company is unable to predict the impact on its financial condition or results of operations from the regulatory activities of any of these regulatory authorities. Changes in regulations, the imposition of additional regulations or regulatory decisions particular to the Company could adversely affect the Company’s financial condition or results of operations.

The Company’s ability to obtain rate adjustments to maintain its current authorized rates of return depends upon action by regulatory authorities under applicable statutes, rules and regulations. These regulatory authorities are authorized to leave the Company’s rates unchanged, to grant increases in such rates or to order decreases in such rates. The Company may be unable to obtain favorable rate adjustments or to maintain its current authorized rates of return, which could adversely affect its financial condition or results of operations.

Regulatory authorities also have authority with respect to the Company’s ability to recover its electricity and natural gas supply costs, as incurred by Unitil Power, Unitil Energy, Fitchburg, and Northern Utilities. If the Company is unable to recover a significant amount of these costs, or if the Company’s recovery of these costs is significantly delayed, then the Company’s financial condition or results or operations could be adversely affected.

In addition, certain regulatory authorities have the power to impose financial penalties and other sanctions on the Company if the Company is found to have violated statutes, rules or regulations governing its utility operations. Any such penalties or sanctions could adversely affect the Company’s financial condition or results of operations.

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

The New England region in which the Company operates has been and will likely continue to be struck from time to time by severe weather events, including snow, wind and ice storms. These storms have in the past caused extensive damage to the Company’s utility operations and loss of service to the Company’s customers, and future severe weather events are likely to do so as well. If the Company cannot recover a significant amount of storm costs in its rates, or if the recovery of these costs is significantly delayed, then the Company’s financial condition and results of operations could be adversely affected. Please see the sections entitled Regulatory Matters in Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operation) and Regulatory Matters in Note 5 (Commitments and Contingencies) to the Company’s Consolidated Financial Statements for a more detailed discussion of the effects of severe weather events on the Company’s financial condition and results of operations.

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

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

In connection with the implementation of retail choice, Unitil Power and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next one to two years, is $24.3 million as of December 31, 2012, including $13.3 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet. Unitil’s distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

If the Company is unable to recover a significant amount of such stranded costs in its rates, or if the Company’s recovery of such stranded costs in its rates is significantly delayed, then the Company’s financial condition or results or operations could be adversely affected. Please see the sections entitled Regulatory Matters—Overview in Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Regulatory Matters—Overview in Note 5 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for a more detailed discussion of the effect of various regulatory matters on the Company and its subsidiaries.

The Company’s electric and natural gas sales and revenues are highly correlated with the economy, and national, regional and local economic conditions may adversely affect the Company’s customers and correspondingly the Company’s financial condition or results of operations.

The Company’s business is influenced by the economic activity within its service territory. The level of economic activity in the Company’s electric and natural gas distribution service territory directly affects the Company’s business. As a result, adverse changes in the economy may adversely affect the Company’s financial condition or results or operations.

The Company may not be able to obtain financing, or may not be able to obtain financing on acceptable terms, which could adversely affect the Company’s financial condition or results of operations.

The Company requires capital to fund utility plant additions, working capital and other utility expenditures. While the Company derives the capital necessary to meet these requirements primarily from internally-generated funds, the Company supplements internally generated funds by incurring short-term debt under its current credit facility, as needed. If the lending counterparties under the Company’s current credit facility are unwilling or unable to meet their funding obligations, then the Company may be unable to, or limited in its ability to, incur short-term debt under its credit facility. This could hinder or prevent the Company from meeting its current and future capital needs, which could correspondingly adversely affect the Company’s financial condition or results or operations.

Also, from time to time, the Company repays portions of its short-term debt with the proceeds it receives from long-term debt financings or equity financings. General economic conditions, conditions in the capital and credit markets and the Company’s operating and financial performance could negatively affect the Company’s ability to obtain such financings or the terms of such financings, which could correspondingly adversely affect the Company’s financial condition or results or operations.

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

The amount of cash contributions the Company is required to make in respect of its pension obligations is dependent upon the valuation of the capital markets. Adverse changes in the valuation of the capital markets could result in the Company being required to make substantial cash contributions in respect of its pension obligations. These cash contributions could have an adverse effect on the Company’s financial condition and results of operations if the Company is unable to recover a such costs in rates or if such recovery is significantly delayed. Please see the section entitled Critical Accounting Policies—Pension Benefit Obligations in Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 9 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements for a more detailed discussion of the Company’ pension obligations.

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

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

The Company’s short-term debt revolving credit facility typically has variable interest rates. Therefore, an increase or decrease in interest rates will increase or decrease the Company’s interest expense associated with its revolving credit facility. An increase in the Company’s interest expense could adversely affect the Company’s financial condition or results of operations. As of December 31, 2012, the Company had approximately $49.4 million in short-term debt outstanding under its revolving credit facility.

The Company’s long-term debt typically has fixed interest rates. Therefore, changes in interest rates will not affect the Company’s interest expense associated with its presently outstanding fixed rate long-term debt. However, an increase or decrease in interest rates may increase or decrease the Company’s interest expense associated with any new fixed rate long-term debt issued by the Company, which could adversely affect the Company’s financial condition or results of operations. See the sections entitled Liquidity, Commitments and Capital Requirements in Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 3 (Long-Term Debt, Credit Arrangements, Leases and Guarantees) to the accompanying Consolidated Financial Statements for a more detailed discussion of the effects of changes in interest rates on the Company.

In addition, the Company may need to use a significant portion of its cash flow to repay its short-term debt and long-term debt, which would limit the amount of cash it has available for working capital, capital expenditures and other general corporate purposes and could adversely affect its financial condition or results of operations.

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

The terms of the Company’s and its subsidiaries’ indebtedness impose various restrictions on the Company’s business operations, including the ability of the Company and its subsidiaries to incur additional indebtedness. These restrictions could adversely affect the Company’s financial condition or results of operations. See the sections entitled Liquidity, Commitments and Capital Requirements in Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 3 (Long-Term Debt, Credit Arrangements, Leases and Guarantees) to the accompanying Consolidated Financial Statements for a more detailed discussion of these restrictions.

A significant amount of the Company’s sales are temperature sensitive. Because of this, mild winter and summer temperatures could decrease the Company’s sales, which could adversely affect the Company’s financial condition or results of operations. Also, the Company’s sales may vary from year to year depending on weather conditions, and the Company’s results of operations generally reflect seasonality.

The Company estimates that approximately 60% of its annual natural gas sales are temperature sensitive. Therefore, mild winter temperatures could decrease the amount of natural gas sold by the Company, which could adversely affect the Company’s financial condition or results of operations. The Company’s electric sales also are temperature sensitive, but less so than its natural gas sales. The highest usage of electricity typically occurs in the summer months (due to air conditioning demand) and the winter months (due to heating-related and lighting requirements). Therefore, mild summer temperatures and mild winter temperatures could decrease the amount of electricity sold by the Company, which could adversely affect the Company’s financial condition and results of operations. Also, because of this temperature sensitivity, sales by the Company’s distribution utilities vary from year to year, depending on weather conditions.

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

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

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

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

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

Unitil is a public utility holding company and has no operating income of its own. The Company’s ability to pay dividends on its common stock is dependent on dividends and other payments received from its subsidiaries and on factors directly affecting Unitil, the parent corporation. The Company cannot assure that its current annual dividend will be paid in the future.

The ability of the Company’s subsidiaries to pay dividends or make distributions to Unitil depends on, among other things:

•

the actual and projected earnings and cash flow, capital requirements and general financial condition of the Company’s subsidiaries;

•

the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by the Company’s subsidiaries;

•

the restrictions on the payment of dividends contained in the existing loan agreements of the Company’s subsidiaries and that may be contained in future debt agreements of the Company’s subsidiaries, if any; and

•

limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory agencies.

In addition, before the Company can pay dividends on its common stock, it has to satisfy its debt obligations and comply with any statutory or contractual limitations.

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

The Company’s electric and natural gas distribution activities (including storing natural gas and supplemental gas supplies) involve numerous hazards and operating risks that may result in accidents and other operating risks and costs. Any such accident or costs could adversely affect the Company’s financial position and results of operations.

Inherent in the Company’s electric and natural gas distribution activities are a variety of hazards and operating risks, including leaks, explosions, electrocutions and mechanical problems. These hazards and risks could result in loss of human life, significant damage to property, environmental pollution, damage to natural resources and impairment of the Company’s operations, which could adversely affect the Company’s financial position and results of operations.

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

The Company’s business is subject to environmental regulation in all jurisdictions in which it operates and its costs of compliance are significant. New, or changes to existing, environmental regulation, including those related to climate change or greenhouse gas emissions, and the incurrence of environmental liabilities could adversely affect the Company’s financial condition or results of operations.

The Company’s utility operations are generally subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources, and the health and safety of the Company’s employees. The Company’s utility operations also may be subject to new and emerging federal, state and local legislative and regulatory initiatives related to climate change or greenhouse gas emissions including the U.S. Environmental Protection Agency’s mandatory greenhouse gas reporting rule. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties and other sanctions; imposition of remedial requirements; and issuance of injunctions to ensure future compliance. Liability under certain environmental laws and regulations is strict, joint and several in nature. Although the Company believes it is in material compliance with all applicable environmental and safety laws and regulations, we cannot assure you that the Company will not incur significant costs and liabilities in the future. Moreover, it is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations, including those related to climate change or greenhouse gas emissions, could result in increased environmental compliance costs.

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

The electric and natural gas utility industries are from time to time affected by catastrophic events, such as unusually severe weather and significant and widespread failures of plant and equipment. Other catastrophic occurrences, such as terrorist attacks on utility facilities, may occur in the future. Such events could inhibit the Company’s ability to provide electric or natural gas distribution services to its customers for an extended period, which could adversely affect the Company’s financial condition and results of operations.

The Company’s operational and information systems on which it relies to conduct its business and serve customers could fail to function properly due to technological problems, a cyber-attack, acts of terrorism, severe weather, a solar event, an electromagnetic event, a natural disaster, the age and condition of information technology assets, human error, or other reasons, that could disrupt the Company’s operations and cause the Company to incur unanticipated losses and expense.

The operation of the Company’s extensive electricity and natural gas systems rely on evolving information technology systems and network infrastructures that are likely to become more complex as new technologies and systems are developed to establish a “Smart Grid” to monitor and manage the nation’s interconnected electric transmission grids. The Company’s business is highly dependent on its ability to process and monitor, on a daily basis, a very large number of transactions, many of which are highly complex. The failure of these information systems and networks could significantly disrupt operations; result in outages and/or damages to the Company’s assets or operations or those of third parties on which it relies; and subject the Company to claims by customers or third parties, any of which could have a material effect on the Company’s financial condition, results of operations, and cash flows.

The Company’s information systems, including its financial information, operational systems, metering, and billing systems, require constant maintenance, modification, and updating, which can be costly and increases the risk of errors and malfunction. Any disruptions or deficiencies in existing information systems, or disruptions, delays or deficiencies in the modification or implementation of new information systems, could result in increased costs, the inability to track or collect revenues, the diversion of management’s and employees’ attention and resources, and could negatively impact the effectiveness of the Company’s control environment, and/or the Company’s ability to timely file required regulatory reports. Despite implementation of security and mitigation measures, all of the Company’s technology systems are vulnerable to impairment or failure due to cyber-attacks, viruses, human errors, acts of war or terrorism and other reasons. If the Company’s information technology systems were to fail or be materially impaired, the Company might be unable to fulfill critical business functions and serve its customers, which could have a material effect on the Company’s financial conditions, results of operations, and cash flows.

In addition, in the ordinary course of its business, the Company collects and retains sensitive information including personal identification information about customers and employees, customer energy usage, and other confidential information. The theft, damage, or improper disclosure of sensitive electronic data could subject the Company to penalties for violation of applicable privacy laws or claims from third parties and could harm the Company’s reputation.

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

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

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

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

The Company’s energy brokering customers may default in their performance under multi-year energy brokering contracts, which could adversely affect the Company’s financial condition and results of operations.

The Company’s non-regulated energy brokering business provides energy brokering and consulting services to a national client base of large commercial and industrial customers. Revenues from this business are primarily derived from brokering fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts. The Company’s customers may default in their performance under multi-year energy brokering contracts, which could adversely affect the Company’s financial condition and results of operations.

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

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

Item 1B.

Unresolved Staff Comments

None.

Item 2.

Properties

As of December 31, 2012, Unitil owned, through its electric distribution utilities, three utility operation centers, approximately 1,702 primary pole miles of local transmission and distribution overhead electric lines and 263 conduit bank miles of underground electric distribution lines, along with 49 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 1,299 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 33 electric distribution substations, including a 5,000 kilovolt ampere (kVA) and a 10,500 kVA mobile substation, constitute 215,400 kVA of capacity, which excludes capacity of spare transformers, for the transformation of electric power from the 34.5 kilovolt 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 1,263 primary pole miles of local transmission and distribution overhead electric lines and a total of 204 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 439 primary pole miles of local transmission and distribution overhead electric lines, 59 conduit bank miles of underground electric distribution lines and 16 transmission and distribution stations, including two mobile electric substations. The capacity of these substations totals 441,700 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, express 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 270 miles of underground steel, cast iron and plastic gas mains and 10,863 active gas services. The gas mains are primarily made up of steel (50%), polyethylene plastic (25%), and cast iron (25%).

Northern Utilities’ distribution system is comprised of 1,029 miles of gas mains and 40,254 service pipes. The gas mains are primarily made up of polyethylene plastic (72%), coated and wrapped cathodically protected steel (18%), cast/wrought iron (6%), and unprotected bare and coated steel (4%).

Northern Utilities’ New Hampshire division serving 21 communities has 502 miles of distribution gas mains and 21,502 service pipes. Northern Utilities’ Maine division serving 23 communities has 527 miles of distribution gas main and 18,752 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, that the ultimate resolution of these claims will not have a material impact on the Company’s financial position.

In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (“Fitchburg”), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December, 2008. The Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Superior Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit will now continue with only the twelve named plaintiffs seeking damages. Future proceedings may include an appeal of this decision or a trial on the claims of the twelve named plaintiffs. The Company continues to believe the suit is without merit and will continue to defend itself vigorously.

Item 4.

Mine Safety Disclosures.

Not applicable.

PART II

Item 5.

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

Our common stock is listed on the New York Stock Exchange under the symbol “UTL.” As of December 31, 2012, there were 1,534 shareholders of record of our common stock.

Common Stock Data


Dividends per Common Share	2012		2011
1st Quarter	$	0.345	$	0.345
2nd Quarter		0.345		0.345
3rd Quarter		0.345		0.345
4th Quarter		0.345		0.345

Total for Year	$	1.38	$	1.38

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

2012

2011

Price Range of Common Stock

High/Ask

Low/Bid

High/Ask

Low/Bid

1st Quarter

29.00

26.25

23.94

21.84

2nd Quarter

27.40

24.76

26.82

23.12

3rd Quarter

27.98

26.23

26.82

24.53

4th Quarter

27.51

24.15

28.60

24.58

Information regarding securities authorized for issuance under our equity compensation plans, as of December 31, 2012, is set forth in the table below.

Equity Compensation Plan Information

(a)

(b)

(c)

Plan Category

Number of securities
to be issued upon exercise
of outstanding options,
warrants and rights

Weighted-average
exercise price of
outstanding options,
warrants and rights

Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))

Equity compensation plans approved by security holders

Second Amended and Restated 2003 Stock Plan⁽¹⁾

N/A

513,676

Equity compensation plans not approved by security holders

N/A

N/A

Total

N/A

513,676

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

⁽¹⁾

The Second Amended and Restated 2003 Stock Plan, formerly known as the Restricted Stock Plan (the Plan), was approved by shareholders in April 2003, and a total of 677,500 shares of our common stock were reserved for issuance pursuant to awards under the Plan. A total of 165,845 shares of restricted stock have been awarded to Plan participants through December 31, 2012, of which 2,021 were forfeited and once again became available for issuance under the Plan.

Stock Performance Graph

The following graph compares Unitil Corporation’s cumulative stockholder return since December 31, 2007 with the Peer Group index, comprised of the S&P 500 Utilities Index, and the S&P 500 index. The graph assumes that the value of the investment in the Company’s common stock and each index (including reinvestment of dividends) was $100 on December 31, 2007.

Comparative Five-Year Total Returns

LOGO

NOTE:

⁽¹⁾	The graph above assumes $100 invested on December 31, 2007, in each category and the reinvestment of all dividends during the five-year period. The Peer Group is comprised of the S&P 500 Utilities Index.

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, 2012.

Issuer Purchases of Equity Securities

Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on March 22, 2012, the Company will periodically repurchase shares of its Common Stock on the open market related to Employee Length of Service Awards and the stock portion of the Directors’ annual retainer. There is no pool or maximum number of shares related to these purchases; however, the trading plan will terminate when $200,800 in value of shares have been purchased or, if sooner, on March 22, 2013.

The Company may suspend or terminate this trading plan at any time, so long as the suspension or termination is made in good faith and not as part of a plan or scheme to evade the prohibitions of Rule 10b-5 under the Exchange Act, or other applicable securities laws.

The following table shows information regarding repurchases by the Company of shares of its common stock for each month in the quarter ended December 31, 2012.


	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
10/1/12 – 10/31/12		5,469	$	27.42		5,469	$	38,549
11/1/12 – 11/30/12		—		—		—	$	38,549
12/1/12 – 12/31/12		205	$	25.81		205	$	33,258

Total		5,674	$	27.36		5,674

Item 6.

Selected Financial Data


For the Years Ended December 31,	2012			2011			2010			2009			2008

(all data in millions except shares, %, per share data and customers served)⁽¹⁾
Consolidated Statements of Earnings:

Operating Revenue	$	353.1		$	352.8		$	358.4		$	367.0		$	288.2

Operating Income		36.5			37.2			28.0			26.1			20.5

Other Non-operating Expense		0.2			0.4			0.3			0.3			0.3


Income Before Interest Expense		36.3			36.8			27.7			25.8			20.2

Interest Expense, net		18.1			20.4			18.1			15.8			10.5


Net Income		18.2			16.4			9.6			10.0			9.7

Dividends on Preferred Stock		0.1			0.1			0.1			0.1			0.1


Earnings Applicable to Common Shareholders	$	18.1		$	16.3		$	9.5		$	9.9		$	9.6


Balance Sheet Data (as of December 31,):

Utility Plant (Original Cost)	$	831.6		$	773.7		$	728.4		$	682.7		$	641.4

Total Assets	$	886.6		$	846.7		$	800.4		$	762.4		$	767.1

Capitalization:

Common Stock Equity	$	260.4		$	191.7		$	189.0		$	193.1		$	139.5

Preferred Stock		0.2			2.0			2.0			2.0			2.0

Long-Term Debt, less current portion		287.3			287.8			288.3			248.9			249.3


Total Capitalization	$	547.9		$	481.5		$	479.3		$	444.0		$	390.8


Current Portion of Long-Term Debt	$	0.5		$	0.5		$	0.5		$	0.4		$	0.4

Short-Term Debt	$	49.4		$	87.9		$	66.8		$	64.5		$	74.1

Capital Structure Ratios (as of December 31,):

Common Stock Equity		47	%		40	%		39	%		43	%		36	%

Preferred Stock		1	%		1	%		1	%		1	%		1	%

Long-Term Debt		52	%		59	%		60	%		56	%		63	%

Earnings Per Share Data:

Earnings Per Average Share	$	1.43		$	1.50		$	0.88		$	1.03		$	1.65

Common Stock Data:

Shares of Common Stock—(Diluted Weighted Average Outstanding, 000’s)		12,672			10,883			10,824			9,647			5,830

Dividends Paid Per Share	$	1.38		$	1.38		$	1.38		$	1.38		$	1.38

Book Value Per Share (Year-End)	$	18.90		$	17.50		$	17.35		$	17.83		$	17.90

Electric and Gas Sales:

Electric Distribution Sales (Millions kWh)		1,653.8			1,682.1			1,691.1			1,618.8			1,695.9

Firm Natural Gas Distribution Sales (Millions Therms)		181.3			186.9			172.9			178.7			47.2

Customers Served (Year-End):

Electric:

Residential		87,062			86,780			86,344			86,055			85,948

Commercial & Industrial		14,612			14,574			14,514			14,443			14,376


Total Electric		101,674			101,354			100,858			100,498			100,324


Natural Gas:

Residential		56,745			55,663			54,944			54,208			53,564

Commercial & Industrial		16,977			16,232			15,807			15,763			15,714


Total Natural Gas		73,722			71,895			70,751			69,971			69,278

⁽¹⁾

As a result of the acquisitions of Northern Utilities and Granite State on December 1, 2008, consolidated results for the Company in the years ended December 31, 2012, 2011, 2010 and 2009 may not be directly comparable to the results for the year ended December 31, 2008, insofar as most of that year did not include the results for Northern Utilities and Granite State.

Item 7.

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

OVERVIEW

Unitil is a public utility holding company headquartered in Hampton, New Hampshire. Unitil is subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005.

Unitil’s principal business is the local distribution of electricity and natural gas to approximately 175,400 customers throughout its service territory in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities:

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 101,700 electric customers and 73,700 natural gas customers in their service territory.

In addition, Unitil is the parent company of Granite State, a natural gas transmission pipeline, regulated by the FERC, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to North American pipeline supplies.

The distribution utilities are local “pipes and wires” operating companies, and Unitil had an investment in Net Utility Plant of $601.2 million at December 31, 2012. Unitil’s total revenue was $353.1 million in 2012, 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 2012. 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’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its natural gas transmission pipeline company may also recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost tracker rate mechanisms.

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

RESULTS OF OPERATIONS

The following discussion of the Company’s financial condition and results of operations should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.

On May 16, 2012, the Company sold 2,760,000 shares of its common stock at a price of $25.25 per share in a registered public offering. The Company used the net proceeds of approximately $65.7 million

from this offering to make equity capital contributions to its regulated utility subsidiaries, repay short-term debt and for general corporate purposes. Overall, the results of operations and Earnings reflect the higher number of average shares outstanding year over year.

Net Income and EPS Overview

2012 Compared to 2011—The Company’s Earnings Applicable to Common Shareholders (Earnings) were $18.1 million for the year ended December 31, 2012, an increase of $1.8 million, or 11%, over the $16.3 million the Company earned in 2011. Earnings per common share (EPS) were $1.43 for 2012 compared to $1.50 per share in 2011. As discussed above, the 2012 EPS reflect the higher number of average shares outstanding year over year.

The results for 2012 were positively affected by higher natural gas and electric sales margins due to higher distribution rates and new customer growth. Margins were negatively affected in 2012 by the effect on sales of fluctuations in seasonal weather conditions year over year. The Company estimates that the mild weather in 2012 negatively impacted earnings for the gas division by about $1.6 million, or $0.13 per share, and the electric division by about $0.1 million, or $0.01 per share. According to the National Oceanic and Atmospheric Administration, 2012 was the warmest year on record for the northeast region of the United States, in which the Company’s service areas are located.

The Company’s Earnings were $9.0 million, or $0.66 per share, for the fourth quarter of 2012, compared to Earnings of $10.0 million, or $0.92 per share, in the fourth quarter of 2011. Earnings for 2011 include a non-recurring pre-tax credit of $4.7 million recorded in the fourth quarter of that year 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.

Natural gas sales margins were $76.2 million in 2012, or an increase of $8.3 million compared to 2011, reflecting higher gas distribution rates and new customer growth, partially offset by lower gas therm sales, principally in the first quarter of 2012, due to mild winter weather. Also, gas margins in 2011 include the one-time recovery of $4.5 million in Purchased Gas costs that had been charged off in a prior period. Based on weather data collected in the Company’s service areas, there were 11% and 16% fewer Heating Degree Days in 2012 compared to 2011 and normal, respectively. Weather-normalized gas therm sales (excluding decoupled sales) in 2012 are estimated to be 3.3% higher compared to 2011. Approximately 11% of natural gas therm sales are decoupled and changes in these sales due to the weather do not affect sales margins.

Electric sales margins were $71.9 million in 2012, or an increase of $4.3 million compared to 2011, reflecting higher electric distribution rates and new customer growth, partially offset by lower electric kilowatt hour (kWh) sales, principally in the first quarter of 2012, due to mild winter weather. Weather-normalized electric kWh sales (excluding decoupled sales) in 2012 are estimated to be about the same compared to 2011. Approximately 27% of electric kWh sales are decoupled and changes in these sales due to the weather do not affect sales margins.

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

Depreciation and Amortization expense increased $5.8 million in 2012 compared to 2011 principally reflecting normal utility plant additions and amortization of regulatory assets.

Local Property and Other Taxes increased $1.0 million in 2012 compared to 2011, reflecting higher local property taxes on higher levels of utility plant in service.

Federal and State Income Taxes increased $1.0 million in 2012 due to higher pre-tax earnings in 2012 compared to 2011.

Other Non-operating Expenses decreased $0.2 million in 2012 compared to 2011.

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

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $5.5 million in 2012, on par with 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. The Company will also realize future fees estimated at the end of December 2012 of $8.2 million from executed energy supply term contracts running from 2013 through 2017.

In 2012, 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 2013 meeting, the Unitil Board of Directors declared a quarterly dividend on the Company’s common stock of $0.345 per share.

2011 Compared to 2010—The Company’s Earnings Applicable to Common Shareholders were $16.3 million, or $1.50 per share, for 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 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. The results for 2011 also include 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 rate case and a credit of $1.0 million, recorded in the first quarter, for the proceeds from insurance related settlements.

A more detailed discussion of the Company’s 2012 and 2011 results of operations and a year-to-year comparison of changes in financial position are presented below.

Gas Sales, Revenues and Margin

Therm Sales—Unitil’s total therm sales of natural gas decreased 3.0% in 2012 compared to 2011. The decrease in gas therm sales in the Company’s utility service areas reflects the effect of milder winter weather in 2012 compared to 2011. Based on weather data collected in the Company’s service areas, there were 11% and 16% fewer Heating Degree Days in 2012 compared to 2011 and normal, respectively. Weather-normalized gas therm sales (excluding decoupled sales) in 2012 are estimated to be 3.3% higher compared to 2011. The increase in weather-normalized gas therm sales reflects the addition of new Residential and C&I business customers during the year. Approximately 11% of natural gas therm sales are decoupled and changes in these sales due to the weather do not affect sales margins. As discussed above, under revenue decoupling for 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.

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. Weather-normalized gas therm sales (excluding decoupled sales) in 2011 are estimated to be 8% higher compared to 2010.

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


Therm Sales (millions)							Change
							2012 vs. 2011						2011 vs. 2010
	2012		2011		2010		Therms			%			Therms		%
Residential		34.8		37.7		35.1		(2.9	)		(7.7%	)		2.6		7.4	%
Commercial / Industrial		146.5		149.2		137.8		(2.7	)		(1.8%	)		11.4		8.3	%

Total Therm Sales		181.3		186.9		172.9		(5.6	)		(3.0%	)		14.0		8.1	%

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
							2012 vs. 2011						2011 vs. 2010
	2012		2011		2010		$			%⁽¹⁾			$			%⁽¹⁾
Gas Operating Revenue:
Residential	$	65.3	$	65.1	$	61.5	$	0.2			0.1	%	$	3.6			2.4	%
Commercial / Industrial		95.3		94.1		88.6		1.2			0.8	%		5.5			3.7	%

Total Gas Operating Revenue	$	160.6	$	159.2	$	150.1	$	1.4			0.9	%	$	9.1			6.1	%

Cost of Gas Sales:
Purchased Gas	$	81.9	$	89.1	$	90.5	$	(7.2	)		(4.5	%)	$	(1.4	)		(0.9	%)
Conservation & Load Management		2.5		2.2		2.8		0.3			0.2	%		(0.6	)		(0.4	%)

Total Cost of Gas Sales	$	84.4	$	91.3	$	93.3	$	(6.9	)		(4.3	%)	$	(2.0	)		(1.3	%)

Gas Sales Margin	$	76.2	$	67.9	$	56.8	$	8.3			5.2	%	$	11.1			7.4	%

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

The Company analyzes operating results using Gas Sales Margin. Gas Sales Margin is calculated as Total Gas Operating Revenues less the associated cost of sales, which are recorded as Purchased Gas and Conservation & Load Management (C&LM) in Operating Expenses. The Company believes Gas Sales Margin is a better measure to analyze profitability than Total Gas Operating Revenues because the approved cost of sales are tracked costs that are passed through directly to the customer, resulting in an equal and offsetting amount reflected in Total Gas Operating Revenues.

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

The increase in Total Gas Operating Revenues of $1.4 million, or 0.9%, in 2012 compared to 2011 reflects higher gas sales margins of $8.3 million. These higher gas sales margins were partially offset by lower costs of sales of $6.9 million, including lower Purchased Gas costs of $7.2 million and higher C&LM costs of $0.3 million, which are tracked costs that are passed through directly to customers.

Natural gas sales margins were $67.9 million in 2011, or an increase of $11.1 million 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 been charged off in a prior period, as discussed above.

The increase in Total Gas Operating Revenues of $9.1 million, or 6.1%, in 2011 compared to 2010 reflects higher gas sales margins of $11.1 million, partially offset by lower costs of sales of $2.0 million, including lower Purchased Gas costs of $1.4 million and lower C&LM costs of $0.6 million.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales—Unitil’s total electric kWh sales decreased 1.7% in 2012 compared to 2011, primarily reflecting the effect of milder winter weather in 2012 compared to 2011. As discussed above, there were 11% and 16% fewer Heating Degree Days in 2012 compared to 2011 and normal, respectively. Weather-normalized kWh sales (excluding decoupled sales) in 2012 are estimated to be about the same compared to 2011. Approximately 27% of total electric kWh sales are decoupled and changes in these sales do not affect sales margins. As discussed above, under revenue decoupling for 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.

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 summer weather in 2011 compared to 2010. There were 14.6% fewer Cooling Degree Days in 2011 compared to 2010. Weather-normalized kWh sales (excluding decoupled sales) in 2011 are estimated to be about the same compared to 2010.

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


kWh Sales (millions)							Change
							2012 vs. 2011						2011 vs. 2010
	2012		2011		2010		kWh			%			kWh			%
Residential		677.7		682.8		681.2		(5.1	)		(0.7%	)		1.6			0.2	%
Commercial / Industrial		976.1		999.3		1,009.9		(23.2	)		(2.3%	)		(10.6	)		(1.0	%)

Total kWh Sales		1,653.8		1,682.1		1,691.1		(28.3	)		(1.7%	)		(9.0	)		(0.5	%)

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
							2012 vs. 2011						2011 vs. 2010
	2012		2011		2010		$			%⁽¹⁾			$			%⁽¹⁾
Electric Operating Revenue:
Residential	$	102.2	$	100.8	$	108.5	$	1.4			0.7	%	$	(7.7	)		(3.8	%)
Commercial / Industrial		84.8		87.3		95.2		(2.5	)		(1.3	%)		(7.9	)		(3.9	%)

Total Electric Operating Revenue	$	187.0	$	188.1	$	203.7	$	(1.1	)		(0.6	%)	$	(15.6	)		(7.7	%)

Cost of Electric Sales:
Purchased Electricity	$	108.4	$	114.2	$	137.7	$	(5.8	)		(3.1	%)	$	(23.5	)		(11.5	%)
Conservation & Load Management		6.7		6.3		6.0		0.4			0.2	%		0.3			0.1	%

Total Cost of Electric Sales	$	115.1	$	120.5	$	143.7	$	(5.4	)		(2.9	%)	$	(23.2	)		(11.4	%)

Electric Sales Margin	$	71.9	$	67.6	$	60.0	$	4.3			2.3	%	$	7.6			3.7	%

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

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

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

The decrease in Total Electric Operating Revenues of $1.1 million, or 0.6%, in 2012 compared to 2011 reflects lower costs of sales of $5.4 million, including lower Purchased Electricity costs of $5.8 million and higher C&LM costs of $0.4 million, which are tracked costs that are passed through directly to customers. These lower costs of sales were partially offset by higher electric sales margins of $4.3 million.

Electric sales margins were $67.6 million in 2011, or an increase of $7.6 million compared 2010, reflecting higher electric distribution rates of $7.8 million, partially offset by reduced margins on lower unit sales of ($0.2 million).

The decrease in Total Electric Operating Revenues of $15.6 million, or 7.7%, in 2011 compared to 2010 reflects lower costs of sales of $23.2 million, including lower Purchased Electricity costs of $23.5 million and higher C&LM costs of $0.3 million. These lower costs of sales were partially offset by higher electric sales margins of $7.6 million.

Operating Revenue—Other

Total Other Operating Revenue is comprised of revenues from the Company’s non-regulated energy brokering business, Usource. Usource’s revenues in 2012 were on par with 2011 at $5.5 million. Usource’s revenues increased $0.9 million in 2011 compared to 2010. As an energy broker and advisor, Usource assists business customers with the procurement and contracting for electricity and natural gas in competitive energy markets. Usource does not take title to the energy but solicits energy bids from qualified competitive energy suppliers on behalf of its clients. Usource’s revenues reflect fees that it charges for its services, which are paid by the transacting supplier, typically over the term of the energy contract. The Company will also realize future fees estimated at the end of December 2012 of $8.2 million from executed energy supply term contracts running from 2013 through 2017.

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


Other Revenue (millions)
							Change
							2012 vs. 2011				2011 vs. 2010
	2012		2011		2010		$		%		$		%
Usource	$	5.5	$	5.5	$	4.6	$	—		—	$	0.9		19.6	%

Total Other Revenue	$	5.5	$	5.5	$	4.6	$	—		—	$	0.9		19.6	%

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 $7.2 million, or 8.1%, in 2012 compared to 2011. This decrease reflects lower wholesale natural gas prices, a decline in sales of natural gas compared to the prior period and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. These factors were partially offset by a credit recorded in 2011 of $4.5 million for the recovery of Purchased Gas costs that had previously been charged off in a prior period, discussed above. 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 2011, Purchased Gas decreased $1.4 million, or 1.6%, 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 wholesale natural gas prices 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 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 $5.8 million, or 5.1%, in 2012 compared to 2011. This decrease reflects an increase in the amount of electricity purchased by customers directly from third-party suppliers and lower kWh sales. 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 2011, Purchased Electricity expenses decreased $23.5 million, or 17.1%, compared to 2010. This decrease primarily reflects lower electric commodity costs and an increase in the amount of electricity purchased by customers directly from third-party suppliers.

Operation and Maintenance—O&M expense includes electric and gas utility operating costs, and the operating costs of the Company’s non-regulated business activities. Total O&M expenses increased

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

In 2011, total O&M expense increased $2.7 million, or 5.5%, compared to 2010, reflecting 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 which are recovered through cost tracker rate mechanisms that result in corresponding increases in revenue.

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 increased $0.7 million, in 2012 compared to 2011. 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 decreased $0.3 million in 2011 compared to 2010.

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

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

Local Property and Other Taxes—Local Property and Other Taxes increased $1.0 million, or 7.7%, in 2012 compared to 2011, reflecting higher local property taxes on higher levels of utility plant in service.

In 2011, Local Property and Other Taxes increased $1.8 million, or 16.1%, 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—Federal and State Income Taxes increased $1.0 million in 2012 compared to 2011 due to higher pre-tax earnings in 2012 compared to 2011 (See Note 7 to the accompanying Consolidated Financial Statements).

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

Other Non-operating Expenses (Income)—Other Non-operating Expenses (Income) decreased $0.2 million in 2012 compared to 2011 and increased $0.1 million in 2011 compared to 2010.

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).

In 2011, Interest Expense, net increased $2.3 million 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 to charge-off previously accrued carrying costs that were disallowed for rate recovery. Interest expense also reflects the issuance of $40 million of long-term notes by two of the Company’s operating utilities, Unitil Energy and Northern Utilities, in March 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 periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities. The Company initially supplements internally generated funds through bank borrowings, as needed, under its unsecured short-term revolving credit facility. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term nature of its utility assets. Additionally, from time to time, the Company has accessed the public capital markets through public offerings of equity securities. The Company’s utility operations are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The amount, type and timing of any future financing will vary from year to year based on capital needs and maturity or redemptions of securities.

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

The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (the Cash Pool). The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool allows for an efficient exchange of cash among the Company and its subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on actual interest costs from lenders under the Company’s revolving credit facility. At December 31, 2012 and December 31, 2011, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

Unitil has an unsecured revolving credit facility with a group of banks that extends to October 8, 2013. Effective July 24, 2012, Unitil reduced the borrowing limit under its revolving credit facility from $115 million to $60 million, which the Company believes will be sufficient until its expected renewal. The new $60 million borrowing limit reflects reduced borrowing needs as a result of the recent repayment of short-term debt with the net proceeds of the Company’s public equity offering in May 2012.

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as of December 31, 2012 and December 31, 2011:


Revolving Credit Facility (millions)
	December 31,
	2012		2011
Limit	$	60.0	$	115.0
Outstanding	$	49.4	$	87.9
Available	$	10.6	$	27.1

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, 2012 and December 31, 2011, the Company was in compliance with the financial covenants contained in the revolving credit agreement. (See also “Credit Arrangements” in Note 4.)

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, 2012.


			Payments Due by Period
Significant Contractual Obligations (millions) as of December 31, 2012	Total		2013		2014- 2015		2016- 2017		2018 & Beyond
Long-Term Debt	$	287.8	$	0.5	$	6.5	$	34.6	$	246.2
Interest on Long-Term Debt		244.1		19.9		39.6		37.5		147.1
Gas Supply Contracts		215.0		43.7		77.4		69.4		24.5
Electric Supply Contracts		4.2		0.9		1.4		0.7		1.2
Other (Including Capital and Operating Lease Obligations)		4.2		1.6		1.8		0.7		0.1

Total Contractual Cash Obligations	$	755.3	$	66.6	$	126.7	$	142.9	$	419.1

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, 2012, there were approximately $12.3 million of guarantees outstanding and the longest term guarantee extends through February 2014.

Northern Utilities enters into asset management agreements under which it 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 $10.7 million and $14.9 million of natural gas storage inventory obligations at December 31, 2012 and 2011, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2012, which was

payable in January 2013, is $2.1 million and recorded in Accounts Payable at December 31, 2012. The 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 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, 2012, the principal amount outstanding for the 8% Unitil Realty notes was $2.8 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 $9.4 million and $8.8 million in 2012 and 2011, respectively. The Company, along with its subsidiaries, contributed $2.2 million to Voluntary Employee Benefit Trusts (VEBTs) in 2012. 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 2013 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 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements.

Off-Balance Sheet Arrangements

The Company and its subsidiaries do not currently use, and are not dependent on the use of, off-balance sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. Unitil’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. See Note 3 (Long-Term Debt, Credit Arrangements, Leases and Guarantees) 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 2012 and 2011.


	2012		2011
Cash Provided by Operating Activities	$	66.7	$	45.9

Cash Provided by Operating Activities—Cash Provided by Operating Activities was $66.7 million in 2012, an increase of $20.8 million over 2011. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes, was $64.1 million in 2012 compared to $54.4 million in 2011, representing an increase of $9.7 million. Working capital changes in Current Assets and Liabilities resulted in a $2.4 million net source of cash in 2012 compared to a ($7.4) million net use of cash in 2011. Deferred Regulatory and Other Charges resulted in a $3.6 million source of cash in 2012, compared to a $1.1 million source of cash in 2011. All Other, net operating activities resulted in a use of cash of ($3.4) million in 2012 compared to a use of cash of ($2.2) million in 2011.


	2012			2011
Cash (Used in) Investing Activities	$	(68.5	)	$	(57.1	)

Cash (Used in) Investing Activities—Cash Used in Investing Activities was ($68.5) million for 2012 compared to ($57.1) million in 2011. The capital spending in both periods is representative of normal distribution utility capital expenditures reflecting electric and gas utility system additions. The increase in capital spending in 2012 compared to 2011 primarily reflects plant additions to connect new gas customers

to the Company’s gas distribution system. Capital expenditures are projected to be approximately ($83) million in 2013 reflecting a higher level of capital spending on information system and utility facility projects and planned increases in gas customer additions.


	2012		2011
Cash Provided by Financing Activities	$	4.1	$	9.8

Cash Provided by Financing Activities—Cash Provided by Financing Activities was $4.1 million in 2012 compared to $9.8 million in 2011. In 2012, sources of cash from financing activities included proceeds from issuance of common stock of $66.8 million. Uses of cash from financing activities included payment of short-term debt of ($38.5) million, payment of long-term debt of ($0.5) million, a decrease in gas inventory financing of ($3.8) million, retirement of Preferred Stock of ($1.8) million and regular quarterly dividend payments on common and preferred stock of ($17.2) million. All other financing activities resulted in a use of ($0.9) million.

FINANCIAL COVENANTS AND RESTRICTIONS

The agreements under which the Company and its subsidiaries issue long-term debt contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions, business combinations and covenants restricting the ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity or (iv) sell, lease or otherwise dispose of all or substantially all assets. See Note 3 (Long-Term Debt, Credit Arrangements, Leases and Guarantees) to the accompanying Consolidated Financial Statements.

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

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 2012, 2011 and 2010. 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 2013 meeting, the Unitil Board of Directors declared a quarterly dividend on the Company’s common stock of $0.345 per share. The amount and timing of all dividend payments are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. In addition, the ability of the Company’s subsidiaries to pay dividends or make distributions to Unitil, and, therefore, Unitil’s ability to pay dividends, depends on, among other things:

•

the actual and projected earnings and cash flow, capital requirements and general financial condition of the Company’s subsidiaries;

•

the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by the Company’s subsidiaries;

•

limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory agencies.

In addition, before the Company can pay dividends on its common stock, it has to satisfy its debt obligations and comply with any statutory or contractual limitations. See Financial Covenants and Restrictions, above, as well as Note 3 (Long-Term Debt, Credit Arrangements, Lease and Guarantees) to the accompanying Consolidated Financial Statements.

LEGAL PROCEEDINGS

REGULATORY MATTERS

Overview—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms. As a result of the restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers have the opportunity to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted.

In connection with the implementation of retail choice, Unitil Power and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next one to two years, is $24.3 million as of December 31, 2012 including $13.3 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—Base Rates—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.

Granite State—Base Rates—Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file a limited Section 4 rate case that includes incremental annual rate adjustments to recover the revenue requirements for certain specified future capital cost additions to transmission plant projects totaling up to $11.4 million. Of the $11.4 million, $4.0 million of capital spending is being recovered in current rates. On June 29, 2012, Granite State submitted to the FERC an incremental annual rate adjustment filing of $0.3 million due to capital costs additions of $2.4 million, with rates effective August 1, 2012. On July 27, 2012, the FERC accepted the tariffs as proposed.

Unitil Energy—Base Rates—On April 26, 2011, the NHPUC approved a rate settlement with a permanent increase of $5.2 million in annual revenue effective July 1, 2010, and an additional increase of $5.0 million in annual revenue effective May 1, 2011. The settlement extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with 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. Unitil Energy filed its first step adjustment filing for $1.5 million for implementation on May 1, 2012, to recover increased spending for its vegetation management program and reliability enhancement program. The adjustment filing was approved by the NHPUC with minor modifications.

Northern Utilities—Base Rates—Maine—On November 29, 2011, the MPUC approved 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 precludes Northern Utilities from filing for a new base rate increase with an effective date prior to January 1, 2014.

Northern Utilities—Base Rates—New Hampshire—On April 24, 2012, the NHPUC approved a settlement agreement providing for a $3.7 million permanent increase in annual distribution revenues for Northern Utilities’ New Hampshire operations, effective May 1, 2012. The permanent rate increase was reconciled back to August 1, 2011, the effective date of temporary rates.

Major Storms—Fitchburg and Unitil Energy

Superstorm Sandy—On October 29-30, 2012, a severe storm struck the Eastern seaboard of the United States, causing extensive damage to electric facilities and loss of service to significant numbers of customers of several utilities. Based on its preliminary assessment, Fitchburg and Unitil Energy incurred approximately $1.1 million and $2.6 million, respectively, in costs for the repair and replacement of electric distribution systems damaged during the storm. The amount and timing of the cost recovery of these storm restoration expenditures will be determined in future regulatory proceedings. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations. This matter remains pending.

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 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, including capitalized amounts, it incurred $1.5 million in costs for Tropical Storm Irene and $3.3 million in costs for the October 2011 snow storm. The Company has requested approval to defer and

accrue carrying charges on approximately $4.3 million of the storm costs that were not capitalized into utility plant. On May 1, 2012 the MDPU approved the request to defer the storm costs and ordered that the issue of carrying charges would be addressed in the Company’s next base rate proceeding.

Unitil Energy—2011 Storm Costs—On December 16, 2011, Unitil Energy filed a petition with the NHPUC to increase its storm recovery adjustment factor effective May 1, 2012, to recover the approximately $4.4 million of costs of repairing damage to its electrical system resulting from the August 2011 Tropical Storm Irene and the October 2011 snow storm. On April 24, 2012, the NHPUC issued an order approving recovery of the costs over a five year period with a carrying cost rate of 4.52%, subject to reconciliation.

Fitchburg—Electric Operations—On November 30, 2012, 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 Factor, 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, 2013, subject to reconciliation pending investigation by the MDPU. This matter remains pending.

Fitchburg—Gas Operations—On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an MDPU order issued on November 2, 2009 which had ordered Fitchburg to refund natural gas costs, 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 SJC’s decision, the Regulatory Liability was adjusted and the Company recognized a pre-tax credit to earnings of $4.7 million in the fourth quarter of 2011 as a $4.5 million reduction in Purchased Gas expense and a reduction of $0.2 million in Interest Expense, net.

The Company began the recoupment of the amounts previously refunded, with interest, effective January 1, 2012. In order to minimize the rate impact on customers, the recoupment is scheduled to occur over three consecutive heating seasons, beginning January 1, 2012.

Fitchburg—Service Quality—On March 1, 2012, Fitchburg submitted its 2011 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. The 2010 Service Quality report for Fitchburg’s electric division remains pending.

On December 11, 2012, the MDPU opened an investigation into the service quality provided by the gas and electric distribution companies in Massachusetts and the Service Quality guidelines currently in effect. The MDPU investigation will review existing and potential new reliability, safety, and customer satisfaction metrics; potential penalties for downed wire response; potential clean energy metrics; penalty provisions, including penalty offsets for superior performance in other metrics for poor performance on a different metric; and review of historic data for use in establishing service quality benchmarks. Fitchburg will be an active participant in this docket, which 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 MDPU has opened a docket to address the amounts collected by Fitchburg between the time the MDPU first approved dollar for dollar collection of the Company’s bad debt, and the rate decisions in 2006 and 2007. The MDPU has set a procedural schedule providing for the filing of testimony, issuance of discovery and an evidentiary hearing in May 2013. This matter remains pending before the MDPU.

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

On August 3, 2012, the Governor of Massachusetts signed into law “An Act Relative to Competitively Priced Electricity in the Commonwealth”, which both increases electric distribution companies’ obligations to purchase renewable energy resources and the availability of net metering. This act also includes changes to the MDPU’s ratemaking procedures and authority for reviewing mergers and acquisition for electric and gas distribution companies. With these changes, electric distribution companies are required to file rate schedules every five years, and gas distribution companies every ten years. The MDPU has also opened a proceeding, as mandated by the act, to establish a cost-based rate design for costs that are currently recovered from distribution customers through a reconciling factor.

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

Unitil Energy—Annual Rate Reconciliation Filing—On June 15, 2012, Unitil Energy filed its annual reconciliation and rate filing, for rates effective August 1, 2012, including reconciliation of prior year costs and revenues. This filing was approved by the NHPUC on July 20, 2012 with minor modifications.

Unitil Energy—Billing Adjustment—In August 2011, Unitil Energy and one of its larger customers in New Hampshire entered into an agreement 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. As a result of the agreement, 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 related to this agreement and filed with the NHPUC for recovery of the remaining amount of the reimbursement to this customer for reconciling electric supply related charges.

As a result of this metering issue, which was discovered in February 2011, certain other customers in the Company’s service areas were under-billed from October 2004 through January 2011 for reconciling supply-related charges. Accordingly, the Company requested authorization from the NHPUC to adjust reconciling account balances and process the billing correction. A settlement agreement between Unitil Energy, the Office of Consumer Advocate and the NHPUC Staff was filed with the NHPUC, providing for recovery by the Company from its under-billed customers of approximately $1.4 million of the amount it had reimbursed the large customer. On January 25, 2013, the NHPUC approved the settlement agreement.

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 is proceeding with a comprehensive upgrade and replacement 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.

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 in the first quarter of 2013.

ENVIRONMENTAL MATTERS

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 proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection, which allowed Fitchburg to achieve 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.

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. Additionally, Northern Utilities has executed a Letter of Intent with New Yard, LLC to redevelop the Portland site as a boat repair facility with lease proceeds being used to offset remediation costs. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs until all remedial activities are completed.

Also, see Note 5 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on Environmental Matters.

EMPLOYEES AND EMPLOYEE RELATIONS

As of December 31, 2012, the Company and its subsidiaries had 467 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

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.

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, the amount of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are estimated. These unbilled revenues are estimated each month based on estimated customer usage by class and applicable customer rates.

On August 1, 2011, the Massachusetts Department of Public Utilities (MDPU) issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of 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 corporate bond interest rate indices and pension yield curves. For the years ended December 31, 2012 and 2011, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $367,000 and $325,000, respectively, in the Net Periodic Benefit Cost for the Pension Plan. For the years ended December 31, 2012 and 2011, 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 $981,000 and $909,000, 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 $756,000 and $705,000, 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.

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, 2012, the Company is not aware of any material commitments or contingencies other than those disclosed in the Significant Contractual Obligations table in the Contractual Obligations section above and the Commitments and Contingencies footnote to the Company’s consolidated financial statements below.

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

For further information regarding the foregoing matters, see Note 1 (Summary of Significant Accounting Policies), Note 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”.

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 2.0%, 2.2%, and 2.3% during 2012, 2011, and 2010, 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 in the section entitled Rates and Regulation in Part I, Item 1 (Business) and in Note 5 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements, the Company has divested its commodity-related contracts and therefore, further reduced its exposure to commodity risk.

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, 2012 and 2011, and the related consolidated statements of earnings, cash flows and changes in common stock equity for each of the years in the three-year period ended December 31, 2012. We also have audited Unitil Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2012, 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, 2012 and 2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2012, 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, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ McGladrey LLP

Boston, Massachusetts

January 30, 2013

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CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except common shares and per share data)


Year Ended December 31,	2012		2011		2010

Operating Revenues:

Gas	$	160.6	$	159.2	$	150.1

Electric		187.0		188.1		203.7

Other		5.5		5.5		4.6



Total Operating Revenues		353.1		352.8		358.4



Operating Expenses:

Purchased Gas		81.9		89.1		90.5

Purchased Electricity		108.4		114.2		137.7

Operation and Maintenance		57.0		51.5		48.8

Conservation & Load Management		9.2		8.5		8.8

Depreciation and Amortization		35.1		29.3		28.9

Provisions for Taxes:

Local Property and Other		14.0		13.0		11.2

Federal and State Income		11.0		10.0		4.5



Total Operating Expenses		316.6		315.6		330.4



Operating Income		36.5		37.2		28.0

Other Non-Operating Expenses		0.2		0.4		0.3



Income Before Interest Expense		36.3		36.8		27.7

Interest Expense, net		18.1		20.4		18.1



Net Income		18.2		16.4		9.6

Less Dividends on Preferred Stock		0.1		0.1		0.1



Earnings Applicable to Common Shareholders	$	18.1	$	16.3	$	9.5



Average Common Shares Outstanding (000’s)—Basic		12,669		10,880		10,823

Average Common Shares Outstanding (000’s)—Diluted		12,672		10,883		10,824


Earnings per Common Share—Basic and Diluted	$	1.43	$	1.50	$	0.88

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

CONSOLIDATED BALANCE SHEETS (Millions)

ASSETS


December 31,	2012		2011

Utility Plant:

Electric	$	356.9	$	333.3

Gas		424.4		382.3

Common		30.9		29.8

Construction Work in Progress		19.4		28.3



Utility Plant		831.6		773.7

Less: Accumulated Depreciation		230.4		216.5



Net Utility Plant		601.2		557.2



Current Assets:

Cash		9.8		7.5

Accounts Receivable, net		45.9		44.2

Accrued Revenue		58.1		54.2

Gas Inventory		10.5		14.8

Material and Supplies		4.1		3.6

Prepayments and Other		4.2		4.5



Total Current Assets		132.6		128.8



Noncurrent Assets:

Regulatory Assets		136.0		142.2

Other Noncurrent Assets		16.8		18.5



Total Noncurrent Assets		152.8		160.7



TOTAL ASSETS	$	886.6	$	846.7

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

CONSOLIDATED BALANCE SHEETS (cont.) (Millions)

CAPITALIZATION AND LIABILITIES


December 31,	2012		2011

Capitalization:

Common Stock Equity	$	260.4	$	191.7

Preferred Stock		0.2		2.0

Long-Term Debt, Less Current Portion		287.3		287.8



Total Capitalization		547.9		481.5



Current Liabilities:

Long-Term Debt, Current Portion		0.5		0.5

Accounts Payable		30.9		26.4

Short-Term Debt		49.4		87.9

Energy Supply Obligations		13.8		24.5

Current Deferred Income Taxes		13.4		9.0

Taxes Payable		0.7		1.0

Other Current Liabilities		16.7		17.5



Total Current Liabilities		125.4		166.8



Noncurrent Liabilities:

Energy Supply Obligations		3.3		4.2

Noncurrent Deferred Income Taxes		38.7		37.3

Cost of Removal Obligations		51.4		46.5

Retirement Benefit Obligations		103.7		91.2

Environmental Obligations		13.8		14.5

Other Noncurrent Liabilities		2.4		4.7



Total Noncurrent Liabilities		213.3		198.4



TOTAL CAPITALIZATION AND LIABILITIES	$	886.6	$	846.7

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

CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions)


Year Ended December 31,	2012			2011			2010

Operating Activities:

Net Income	$	18.2		$	16.4		$	9.6

Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:

Depreciation and Amortization		35.1			29.3			28.9

Deferred Taxes Provision		10.8			8.7			10.5

Changes in Working Capital Items:

Accounts Receivable		(1.7	)		(7.3	)		(3.4	)

Accrued Revenue		(3.9	)		(4.8	)		(3.5	)

Taxes Refundable / Payable		(0.3	)		8.5			(5.8	)

Gas Inventory		4.3			(4.2	)		3.7

Accounts Payable		4.5			(0.1	)		1.4

Other Changes in Working Capital Items		(0.5	)		0.5			(4.6	)

Deferred Regulatory and Other Charges		3.6			1.1			(4.3	)

Other, net		(3.4	)		(2.2	)		(6.6	)


Cash Provided by Operating Activities		66.7			45.9			25.9


Investing Activities:

Property, Plant and Equipment Additions		(68.5	)		(57.1	)		(49.6	)


Cash (Used In) Investing Activities		(68.5	)		(57.1	)		(49.6	)


Financing Activities:

Proceeds from (Repayment of) Short-Term Debt, net		(38.5	)		21.1			2.3

Proceeds from Issuance of Long-Term Debt		—			—			40.0

Repayment of Long-Term Debt		(0.5	)		(0.5	)		(0.5	)

Net Increase (Decrease) in Gas Inventory Financing		(3.8	)		4.6			(2.2	)

Dividends Paid		(17.2	)		(15.2	)		(15.0	)

Retirement of Preferred Stock		(1.8	)		—			—

Proceeds from Issuance of Common Stock		66.8			1.0			0.9

Other, net		(0.9	)		(1.2	)		(0.6	)


Cash Provided by Financing Activities		4.1			9.8			24.9


Net Increase (Decrease) in Cash		2.3			(1.4	)		1.2

Cash at Beginning of Year		7.5			8.9			7.7


Cash at End of Year	$	9.8		$	7.5		$	8.9


Supplemental Information:

Interest Paid	$	21.2		$	21.2		$	20.5

Income Taxes (Refunded) Paid	$	0.7		$	(7.3	)	$	2.3

Non-cash Investing Activity:

Capital Expenditures Included in Accounts Payable	$	1.9		$	2.6		$	1.5

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

CONSOLIDATED STATEMENTS OF

CHANGES IN COMMON STOCK EQUITY (Millions)


	Common Equity		Retained Earnings			Total

Balance at January 1, 2010	$	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

Net Income for 2012				18.2			18.2

Dividends				(17.2	)		(17.2	)

Shares Issued Under Stock Plans		0.9					0.9

Issuance of 41,752 Common Shares		1.1					1.1

Issuance of 2,760,000 Common Shares (See Note 2)		65.7					65.7



Balance at December 31, 2012	$	230.0	$	30.4		$	260.4

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

Note 1: Summary of Significant Accounting Policies

Nature of Operations—Unitil Corporation (Unitil or the Company) is a public utility holding company. Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources). Usource, Inc. and Usource L.L.C. are wholly-owned subsidiaries of Unitil Resources.

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

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the “distribution utilities”).

Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers.

Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly- owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to a national client base of large commercial and industrial customers.

Basis of Presentation

Principles of Consolidation—The Company’s consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation.

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)	2012		2011
Energy Supply Obligations	$	8.5	$	16.2
Deferred Restructuring Costs		20.1		21.8
Retirement Benefit Obligations		62.5		55.3
Income Taxes		10.2		10.9
Environmental Obligations		16.8		17.5
Deferred Storm Charges		27.8		28.6
Regulatory Tracker Mechanisms		24.7		23.5
Other		12.0		12.0

Total Regulatory Assets	$	182.6	$	185.8
Less: Current Portion of Regulatory Assets⁽¹⁾		46.6		43.6

Regulatory Assets—noncurrent	$	136.0	$	142.2

⁽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, 2012 and 2011, the Unitil affiliates had deposited $5.4 million and $4.6 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, 2012 and 2011, there was $1.2 million and $2.6 million, respectively, deposited for this purpose.

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” above and unbilled revenues (see Utility Revenue Recognition below.) The following table shows the components of Accrued Revenue as of December 31, 2012 and 2011.


Accrued Revenue (millions)	December 31,
Accrued Revenue (millions)	2012		2011
Regulatory Assets—Current	$	46.6	$	43.6
Unbilled Revenues		11.5		10.6

Total Accrued Revenue	$	58.1	$	54.2

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 2.04%, 2.28% and 2.25% in 2012, 2011 and 2010, respectively. The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At December 31, 2012 and 2011, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $51.4 million and $46.5 million, respectively. Prior to December 31, 2012, the cost of removal amounts had been recorded in Accumulated Depreciation on the Consolidated Balance Sheets. The prior period amounts have been reclassified to Cost of Removal Obligations on the Consolidated Balance Sheets to conform to current year presentation.

Goodwill and Intangible Assets—As a result of the acquisitions of Northern Utilities and Granite State, the Company recognized a bargain purchase adjustment as a reduction to Utility Plant, to be amortized over a ten year period, beginning with the date of the Acquisitions, as authorized by regulators. As of December 31, 2012, the unamortized balance of the bargain purchase adjustment is $14.7 million, to be amortized over the next six years.

Off-Balance Sheet Arrangements—As of December 31, 2012, 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).

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


Level 1—		Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—		Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.

Level 3—		Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the

Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.

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

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 in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Purchased Gas when the gains and losses are passed through to customers in accordance with rate reconciling mechanisms.

As of December 31, 2012 and December 31, 2011, the Company had 1.9 billion cubic feet (BCF) and 1.6 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, 2012		December 31, 2011
Natural Gas Futures Contracts	Other Current Liabilities	$	0.7	$	1.7
Natural Gas Futures Contracts	Other Noncurrent Liabilities		—		0.6

Total		$	0.7	$	2.3

⁽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)	2012		2011
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	1.0	$	2.9

Amount of Loss Reclassified into Consolidated Statements of Earnings⁽²⁾:
Purchased Gas	$	2.6	$	1.6

⁽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.

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, the amount of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are estimated. These unbilled revenues are estimated each month based on estimated customer usage by class and applicable customer rates.

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.

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).

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

Gas Inventory Obligation—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. The gas inventory related to these agreements is recorded in Gas Inventory on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations.

Power Supply Contract Divestitures—As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. The obligations related to these divestitures are recorded in Energy Supply Obligations on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion).

Renewable Energy Portfolio Standards—Renewable Energy Portfolio Standards (RPS) require retail electricity suppliers, including public utilities, to demonstrate that required percentages of their sales are met with power generated from certain types of resources or technologies. Compliance is demonstrated by purchasing and retiring Renewable Energy Certificates (REC) generated by facilities approved by the state as qualifying for REC treatment. Unitil Energy and Fitchburg purchase RECs in compliance with RPS legislation in New Hampshire and Massachusetts for supply provided to default service customers. RPS compliance costs are a supply cost that is recovered in customer default service rates. Unitil Energy and Fitchburg collect RPS compliance costs from customers throughout the year and demonstrate compliance for each calendar year on the following July 1. Due to timing differences between collection of revenue from customers and payment of REC costs to suppliers, Unitil Energy and Fitchburg typically maintain accrued revenue for RPS compliance which is recorded in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.


	December 31,
Energy Supply Obligations consist of the following: (millions)	2012		2011
Current:
Gas Inventory Obligation	$	8.7	$	12.4
Power Supply Contract Divestitures		0.9		8.7
Renewable Energy Portfolio Standards		4.2		3.4

Total Energy Supply Obligations—Current	$	13.8	$	24.5

Long-Term:
Power Supply Contract Divestitures	$	3.3	$	4.2

Total Energy Supply Obligations	$	17.1	$	28.7

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.

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, 2012, 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).

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: 2012 – 3.60%, 2011 – 3.43% and 2010 – 3.99%.

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, 2012, 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.

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known. Deferred income taxes are reflected as Current and Noncurrent Deferred Income Taxes on the Consolidated Balance Sheets based on the nature of the underlying timing item. Prior to December 31, 2012, deferred income taxes were reflected as a single amount on the Consolidated Balance Sheets. The prior period amount of current deferred income taxes, $9.0 million, has been reclassified to conform to current year presentation.

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, 2012, 2011 and 2010, the Company paid quarterly dividends of $0.345 per share, resulting in an annual dividend 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 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 adopted ASU 2011-04 and it did not have any impact on the Company’s Consolidated Financial Statements.

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

Reclassifications—Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. Most significant has been the reclassification of cost of removal costs associated with asset retirements from Accumulated Depreciation to Cost of Removal Obligations and the segregation of Deferred Income Taxes to current and noncurrent amounts on the Company’s Consolidated Balance Sheets, as discussed above in Utility Plant and Income Taxes, respectively.

Note 2: Equity

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

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”. On April 21, 2011, the Company’s shareholders approved an increase in the authorized shares of the Company’s common stock. Shareholders approved an amendment to the Company’s Articles of Incorporation to increase the authorized number of shares of the Company’s common stock, from 16,000,000 shares to 25,000,000 shares in the aggregate. The Company had 13,780,601, and 10,954,065 shares of common stock outstanding at December 31, 2012 and December 31, 2011, respectively.

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

Dividend Reinvestment and Stock Purchase Plan—During 2012, the Company sold 41,752 shares of its common stock, at an average price of $26.37 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.1 million. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock. During 2011 and 2010, the Company raised $1.0 million and $0.9 million, respectively, through the issuance of 39,473 and 41,455 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common Shares Repurchased, Cancelled and Retired—Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on March 22, 2012, 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 2012, 2011 and 2010, the Company repurchased 6,368, 8,765 and 3,225 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, $0.2 million and $0.1 million in 2012, 2011 and 2010, respectively.

During 2012, 2011 and 2010, the Company did not cancel or retire any of its common stock.

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

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

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

Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a participant’s account. Awards may be grossed up to offset the participant’s tax obligations in connection with the award. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death.

Restricted Shares issued for 2010 – 2012 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
2/5/10	12,520	$0.3
2/9/11	24,330	$0.6
2/3/12	25,600	$0.7

The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $1.3 million, $0.7 million and $0.5 million in 2012, 2011 and 2010, respectively. There were 53,932 and 52,362 non-vested shares under the Stock Plan as of December 31, 2012 and 2011, respectively. The weighted average grant date fair value of these shares was $24.67 per share and $22.21 per share, respectively. At December 31, 2012, there was approximately $0.7 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.5 years. There were 816 restricted shares forfeited and there were no cancellations under the Stock Plan during 2012.

There were no Restricted Stock Units issued in conjunction with the Stock Plan during 2010 and 2011. On October 1, 2012, there were 5,470 fully-vested Restricted Stock Units issued to members of the Company’s Board of Directors. These Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an

amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. Restricted Stock Units issued during 2012 in conjunction with the Stock Plan during 2012 are presented in the following table:


Equity RSUs	2012
	Equity RSUs		Weighted Average Stock Price
Beginning Equity Restricted Stock Units		—
Equity Restricted Stock Units Granted		3,829	$	27.43
Dividend Equivalents Earned—Prior Years		—
Dividend Equivalents Earned—Current Year		54	$	24.62
Equity Restricted Stock Units Settled		—

Ending Equity Restricted Stock Units		3,883	$	27.39

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

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 2012, 2011 and 2010. 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 or will be made under this plan since it was terminated by the Board of Directors in 2003. As of December 31, 2012, 2011 and 2010, there was no aggregate intrinsic value of the options exercisable. As of December 31, 2011, all options under this plan have expired.


	2011					2010
	Number of Shares			Average Exercise Price		Number of Shares			Average Exercise Price
Beginning Options Outstanding		33,000		$	25.88		63,500		$	28.90
Options Granted		—			—		—			—
Options Exercised		—			—		—			—
Options Forfeited / Expired		(33,000	)	$	25.88		(30,500	)	$	32.17

Ending Options Outstanding		—		$	—		33,000		$	25.88

Options Vested and Exercisable- end of year		—		$	—		33,000		$	25.88

Preferred Stock

One of Unitil’s distribution utility companies, Unitil Energy, has an aggregate of $0.2 million of 6.00% Series Non-Redeemable, Non-Cumulative Preferred Stock outstanding at December 31, 2012.

On December 1, 2012, Fitchburg redeemed and retired the two outstanding issues of its Redeemable, Cumulative Preferred Stock. The 8.00% Series was redeemed at par (aggregate par value of $965,400). The 5.125% Series was redeemed at par plus a premium of 1.28% (aggregate value of $792,313). Fitchburg used operating cash to effect this transaction.

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

The aggregate purchases of Redeemable, Cumulative Preferred Stock during 2012, 2011 and 2010 related to the annual redemption offer were $8,000, $8,600 and $25,000, respectively.

Earnings Per Share

The following table reconciles basic and diluted earnings per share.


(Millions except shares and per share data)	2012		2011		2010
Earnings Available to Common Shareholders	$	18.1	$	16.3	$	9.5

Weighted Average Common Shares Outstanding—Basic (000’s)		12,669		10,880		10,823
Plus: Diluted Effect of Incremental Shares (000’s)		3		3		1

Weighted Average Common Shares Outstanding—Diluted (000’s)		12,672		10,883		10,824

Earnings per Share—Basic and Diluted	$	1.43	$	1.50	$	0.88

Weighted average options to purchase 33,000 shares of common stock were outstanding during 2010 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, 24,325, 1,642 and 6,164 weighted average non-vested restricted shares for 2012, 2011 and 2010, 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 long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under its present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of Unitil Energy and Fitchburg or certain other actions against Unitil subsidiaries.

Substantially all of the property of Unitil Energy is subject to liens of indenture under which First Mortgage Bonds (FMB) have been issued. In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met; including that Unitil Energy have sufficient available net bondable plant to issue the securities and earnings available for interest charges equal to at least two times the annual interest requirement. The Unitil Energy agreements further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB. The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.

All of the long-term debt of Fitchburg, Northern Utilities and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt.

Accordingly, in order for Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term agreements of that subsidiary must be satisfied, including that the subsidiary have total funded indebtedness less than 65% of total capitalization. Additionally, to issue new long-term debt, Fitchburg must maintain earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State long-term debt agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary’s long-term debt agreements. None of the Fitchburg, Northern Utilities and Granite State default provisions are triggered by the actions or defaults of Unitil or any of its other subsidiaries.

The Unitil, Unitil Energy, Fitchburg, Northern Utilities and Granite State long-term debt instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets. The Granite State notes are guaranteed by Unitil for the payment of principal, interest and other amounts payable. This guarantee will terminate if Granite State is reorganized and merges with and into Northern Utilities.

At December 31, 2012, 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 $500,405, $462,055, and $426,643 in 2012, 2011, and 2010, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2012 is: 2013 – $541,938; 2014 – $2,486,919; 2015 – $4,035,633; 2016 – $17,421,724; and 2017 – $17,160,985, respectively.

Fair Value of Long-Term Debt—Currently, the Company believes that there is no active market in the Company’s debt securities, which have all been sold through private placements. If there were an active market for the Company’s debt securities, the fair value of the Company’s long-term debt would be estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. The fair value of the Company’s long-term debt is estimated using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly and indirectly.) In estimating the fair value of the Company’s long-term debt, the assumed market yield reflects the Moody’s Baa Utility Bond Average Yield. Costs, including prepayment costs, associated with the early settlement of long-term debt are not taken into consideration in determining fair value.


(millions)	December 31,
	2012		2011
Estimated Fair Value of Long- Term Debt	$	349.7	$	338.7

Details on long-term debt at December 31, 2012 and 2011 are shown below:


	December 31,
Long-Term Debt (millions)	2012		2011
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0

Unitil Energy First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0
8.49% Series, Due October 14, 2024		15.0		15.0
6.96% Series, Due September 1, 2028		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0

Fitchburg Long-Term Notes:
6.75% Notes, Due November 30, 2023		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0

Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0
7.72% Senior Notes, Series B, Due December 3, 2038		50.0		50.0

Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0

Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		2.8		3.3

Total Long-Term Debt		287.8		288.3
Less: Current Portion		0.5		0.5

Total Long-Term Debt, Less Current Portion	$	287.3	$	287.8

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

Unitil’s utility subsidiaries operate a number of reconciling rate mechanisms to recover specifically identified costs on a pass through basis. These reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense. Consistent with regulatory precedent, interest income is recorded on an under-collection of costs, which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset.

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


Interest Expense, net (millions)
	2012			2011			2010
Interest Expense
Long-term Debt	$	20.3		$	20.3		$	20.0
Short-term Debt		1.5			1.7			1.7
Regulatory Liabilities		0.5			—			0.3

Subtotal Interest Expense		22.3			22.0			22.0

Interest Income
Regulatory Assets		(3.4	)		(1.1	)		(3.5	)
AFUDC⁽¹⁾ and Other		(0.8	)		(0.5	)		(0.4	)

Subtotal Interest Income		(4.2	)		(1.6	)		(3.9	)

Total Interest Expense, net	$	18.1		$	20.4		$	18.1

⁽¹⁾

AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

Unitil has an unsecured revolving credit facility with a group of banks that extends to October 8, 2013. Effective July 24, 2012, Unitil reduced the borrowing limit under its revolving credit facility from $115 million to $60 million. The new $60 million borrowing limit reflects reduced borrowing needs as a result of the recent repayment of short-term debt with the net proceeds of the Company’s public equity offering in May 2012.

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as of December 31, 2012 and December 31, 2011:


Revolving Credit Facility (millions)
	December 31,
	2012		2011
Limit	$	60.0	$	115.0
Outstanding	$	49.4	$	87.9
Available	$	10.6	$	27.1

The weighted average interest rates on all short-term borrowings were 2.0%, 2.2%, and 2.3% during 2012, 2011, and 2010, 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 $10.7 million and $14.9 million of natural gas storage inventory obligations at December 31, 2012 and 2011, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2012, which was payable in January 2013, is $2.1 million and recorded in Accounts Payable at December 31, 2012. The 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.

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, 2012, 2011 and 2010 amounted to $1.3 million, $1.4 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. Fitchburg intends to purchase this facility at its fair market value at the end of this lease term.

The following is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2012:


Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2013	$	997	$	628
2014		804		300
2015		668		82
2016		479		—
2017		198		—
2018 – 2022		50		—

Total Payments	$	3,196	$	1,010

Guarantees

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 commercial and industrial (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.

Regulated Natural Gas Supply

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 Independent System Operator New England, Inc. (ISO-NE) markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s customers.

Regulated Electric Power Supply

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

Electric Power Supply Divestiture

Note 5: Commitments and Contingencies

Regulatory Matters

Overview—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms. As a result of the restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers have the opportunity to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted.

In connection with the implementation of retail choice, Unitil Power and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next one to two years, is $24.3 million as of December 31, 2012 including $13.3 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.

Major Storms—Fitchburg and Unitil Energy

occurred on August 28, 2011, and a severe snow storm, which occurred on October 29-30, 2011. Fitchburg estimates that, including capitalized amounts, it incurred $1.5 million in costs for Tropical Storm Irene and $3.3 million in costs for the October 2011 snow storm. The Company has requested approval to defer and accrue carrying charges on approximately $4.3 million of the storm costs that were not capitalized into utility plant. On May 1, 2012 the MDPU approved the request to defer the storm costs and ordered that the issue of carrying charges would be addressed in the Company’s next base rate proceeding.

approved dollar for dollar collection of the Company’s bad debt, and the rate decisions in 2006 and 2007. The MDPU has set a procedural schedule providing for the filing of testimony, issuance of discovery and an evidentiary hearing in May 2013. This matter remains pending before the MDPU.

proceeding with a comprehensive upgrade and replacement 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.

Legal Proceedings

Environmental Matters

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, 2012 and 2011 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. Additionally, Northern Utilities has executed a Letter of Intent with New Yard, LLC to redevelop the Portland site as a boat repair facility with lease proceeds being used to offset remediation costs. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs until all remedial activities are completed.

Included in the Company’s Consolidated Balance Sheets at December 31, 2012 and 2011 are current and non-current accrued liabilities totaling $2.8 million and $2.7 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.

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 2012 and 2011.

ENVIRONMENTAL OBLIGATIONS


(Millions)	December 31,
	2012		2011
Total Environmental Obligations—Balance at Beginning of Period	$	14.7	$	14.6
Changes in Estimates		0.1		0.1
Liabilities Assumed		—		—
Less: Payments / Reductions		—		—

Total Environmental Obligations—Balance at End of Period		14.8		14.7
Less: Current Portion⁽¹⁾		1.0		0.2

Environmental Obligations—noncurrent—Balance at End of Period	$	13.8	$	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 2012, 2011 and 2010, the Company recorded provisions for the energy commodity portion of bad debts of $1.9 million, $1.8 million and $1.4 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 2010 – 2012 ($ millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2012
Electric	$	1.7	$	1.4	$	0.3	$	2.3	$	1.1
Gas		0.5		2.2		0.3		2.3		0.7
Other		0.1		—		—		—		0.1

	$	2.3	$	3.6	$	0.6	$	4.6	$	1.9

Year Ended December 31, 2011
Electric	$	1.8	$	2.1	$	0.2	$	2.4	$	1.7
Gas		0.7		2.2		0.3		2.7		0.5
Other		0.1		—		—		—		0.1

	$	2.6	$	4.3	$	0.5	$	5.1	$	2.3

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

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, 2012, 2011 and 2010 are shown in the table below:


	($000’s)
	2012			2011			2010
Current Federal Tax Provision (Benefit)
Current Benefit of Operating Loss Carrybacks	$	—		$	—		$	(6,026	)

Total Current Federal Tax Provision (Benefit)		—			—			(6,026	)

Deferred Federal Tax Provision (Benefit)
Utility Plant Differences		6,019			13,002			11,821
Net Operating Loss Carryforwards		2,835			(4,844	)		(5,520	)
Regulatory Assets and Liabilities		472			513			3,338
Other, net		(241	)		(695	)		(480	)

Total Deferred Federal Tax Provision (Benefit)		9,085			7,976			9,159

Total Federal Tax Provision		9,085			7,976			3,133

State
Current		132			1,358			28
Deferred		1,759			691			1,303

Total State Tax Provision		1,891			2,049			1,331

Total Provision for Federal and State Income Taxes	$	10,976		$	10,025		$	4,464

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:


	2012			2011			2010
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, Net		5			5			6
Utility Plant Differences		(2	)		(1	)		(7	)
Other, Net		1			—			(1	)

Effective Income Tax Rate		38	%		38	%		32	%

Temporary differences which gave rise to current deferred tax assets and liabilities in 2012 and 2011, are shown below:


Current Deferred Income Taxes (000’s)	2012			2011
Accrued Revenue, Current Portion	$	13,568		$	9,358
Other, net		(168	)		(366	)

Total Current Deferred Income Tax Liabilities	$	13,400		$	8,992

Temporary differences which gave rise to noncurrent deferred tax assets and liabilities in 2012 and 2011 are shown below:


Noncurrent Deferred Income Taxes (000’s)	2012			2011
Utility Plant Differences	$	66,907		$	57,809
Net Operating Loss Carryforwards		(8,521	)		(11,656	)
AMT Tax Credit Carryforwards		(1,538	)		(1,366	)
Regulatory Assets and Liabilities		17,872			23,269
Retirement Benefit Obligations		(38,644	)		(33,591	)
Other, net		2,606			2,829

Total Noncurrent Deferred Income Tax Liabilities	$	38,682		$	37,294

The Company is subject to federal and state income taxes as well as various other business taxes. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. Periodically, the Company assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.

The Company filed its tax returns for the year ended December 31, 2011 with the Internal Revenue Service (IRS) in September 2012. As of December 31, 2012, the Company had recorded cumulative federal and state net operating loss (NOL) carryforward assets of $8.5 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, 2012, the Company had $1.5 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

According to Internal Revenue Code rules, Federal Income Tax 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 has performed all fieldwork procedures and the Company and the IRS entered into a settlement agreement for certain timing items, originally reported in 2009, to be deducted in future periods. The result of the settlement agreement did not have a material impact on the Company’s consolidated financial position or results of operations. On January 22, 2013 the Company received notice of approval from the Joint Committee regarding the settlement agreement.

The Company evaluated its tax positions at December 31, 2012 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, 2009; December 31, 2010; and December 31, 2011.

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.

Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transmission services provided to Northern Utilities and, to a lesser extent, third-party marketers.

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

Unitil Realty, Unitil Service and the holding company are included in the “Other” column of the table below. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use.

The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies. Intersegment sales take place at cost and the effects of all intersegment and/or intercompany transactions are eliminated in the consolidated financial statements. Segment profit or loss is based on profit or loss from operations after income taxes and preferred stock dividends. Expenses used to determine operating income before taxes are charged directly to each segment or are allocated based on cost allocation factors included in rate applications approved by the NHPUC, MDPU, and MPUC. Assets allocated to each segment are based upon specific identification of such assets provided by Company records.

The following table provides significant segment financial data for the years ended December 31, 2012, 2011 and 2010 (Millions):


Year Ended December 31, 2012	Electric		Gas			Other			Non- Regulated		Total

Revenues	$	187.0	$	160.6		$	—		$	5.5	$	353.1

Interest Income		2.4		0.8			0.4			0.1		3.7

Interest Expense		9.0		11.1			1.7			—		21.8

Depreciation & Amortization Expense		18.0		15.7			1.4			—		35.1

Income Tax Expense (Benefit)		4.8		5.8			(0.5	)		0.9		11.0

Segment Profit (Loss)		7.6		8.9			0.3			1.3		18.1

Segment Assets		403.7		471.6			5.6			5.7		886.6

Capital Expenditures		21.2		43.9			3.4			—		68.5

Year Ended December 31, 2011

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		393.8		440.9			6.5			5.5		846.7

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		3.7		(0.7	)		0.5			1.0		4.5

Segment Profit		8.0		1.4			(1.4	)		1.5		9.5

Segment Assets		388.2		401.1			5.7			5.4		800.4

Capital Expenditures		19.8		27.4			2.4			—		49.6

Note 9: Retirement Benefit Plans

The Company sponsors the following retirement benefit plans to provide certain pension and post-retirement benefits for its retirees and current employees as follows:

•

The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan. Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service.

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.

•

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:


	2012			2011			2010
Used to Determine Plan costs for years ended December 31:
Discount Rate		4.60	%		5.35	%		5.75	%
Rate of Compensation Increase		3.00	%		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		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)	$	981		$	909		$	728
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(756	)	$	(705	)	$	(565	)


Used to Determine Benefit Obligations at December 31:
Discount Rate		4.00	%		4.60	%		5.35	%
Rate of Compensation Increase		3.00	%		3.00	%		3.50	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		6.50	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health care Cost Trend Rate is reached		2017			2017			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	11,808		$	9,109		$	7,530
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(9,291	)	$	(7,217	)	$	(5,997	)

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 2012, 2011 and 2010, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $367,000, $325,000 and $300,000, respectively, in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2012, 2011 and 2010 was 3.00%, 3.50% and 3.50%, based on the expected long-term increase in compensation costs for personnel covered by the plans.

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


	Pension Plan									PBOP Plan									SERP
	2012			2011			2010			2012			2011			2010			2012		2011		2010

Service Cost	$	3,227		$	2,941		$	2,608		$	2,066		$	1,918		$	1,466		$	289	$	285	$	285

Interest Cost		4,633			4,684			4,457			2,303			2,279			2,016			211		227		227

Expected Return on Plan Assets		(5,390	)		(4,840	)		(4,181	)		(695	)		(818	)		(599	)		—		—		—

Prior Service Cost Amortization		188			249			253			1,729			1,729			1,579			11		11		2

Transition Obligation Amortization		—			—			—			21			21			21			—		—		—

Curtailment Loss		—			—			41			—			—			—			—		—		—

Actuarial Loss Amortization		3,617			3,132			2,406			129			—			—			64		78		133


Sub-total		6,275			6,166			5,584			5,553			5,129			4,483			575		601		647

Amounts Capitalized and Deferred		(2,726	)		(2,590	)		(2,240	)		(2,127	)		(1,622	)		(1,183	)		—		—		—

NPBC Recognized	$	3,549		$	3,576		$	3,344		$	3,426		$	3,507		$	3,300		$	575	$	601	$	647

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 $4.4 million, $2.5 million and $0.2 million for the Pension, PBOP and SERP plans, respectively.

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. The Company’s pension expense for the years 2012, 2011 and 2010 before capitalization and deferral was $6.3 million, $6.2 million and $5.6 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2012, 2011 and 2010 would have been $6.7 million, $5.7 million and $6.2 million respectively.

The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status ($000’s):


	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2012			2011			2012			2011			2012			2011

Plan Assets at Beginning of Year	$	59,700		$	54,100		$	7,339		$	8,862		$	—		$	—

Actual Return on Plan Assets		7,780			225			837			108			—			—

Employer Contributions		9,387			8,813			2,190			—			53			53

Participant Contributions		—			—			18			13			—			—

Acquired Plan Assets		—			—			—			—			—			—

Benefits Paid		(4,456	)		(3,438	)		(2,083	)		(1,644	)		(53	)		(53	)

Plan Assets at End of Year	$	72,411		$	59,700		$	8,301		$	7,339		$	—		$	—


Change in PBO:

PBO at Beginning of Year	$	102,719		$	89,393		$	50,930		$	43,344		$	4,615		$	4,263

Service Cost		3,227			2,941			2,066			1,918			289			285

Interest Cost		4,633			4,684			2,303			2,279			211			227

Participant Contributions		—			—			18			13			—			—

Plan Amendments		617			—			(318	)		—			—			—

Curtailment Gain		—			—			—			—			—			—

Benefits Paid		(4,456	)		(3,438	)		(2,083	)		(1,644	)		(53	)		(53	)

Actuarial (Gain) or Loss		9,752			9,139			9,176			5,020			1,145			(107	)

PBO at End of Year	$	116,492		$	102,719		$	62,092		$	50,930		$	6,207		$	4,615

Funded Status: Assets vs PBO	$	(44,081	)	$	(43,019	)	$	(53,791	)	$	(43,591	)	$	(6,207	)	$	(4,615	)

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets of $62.5 million and $55.3 million at December 31, 2012 and 2011, respectively, to account for the future collection of these plan obligations in electric and gas rates.

The Accumulated Benefit Obligation (ABO) is required to be disclosed for all plans where the ABO is in excess of plan assets. The difference between the PBO and the ABO is that the PBO includes projected compensation increases. The ABO for the Pension Plan was $103.4 million and $91.3 million as of December 31, 2012 and 2011, respectively. The ABO for the SERP was $4.8 million and $0.5 million as of December 31, 2012 and 2011, respectively. For the PBOP Plan, the ABO and PBO are the same.

On August 17, 2006, the Pension Protection Act of 2006 (PPA) was signed into law. Included in the PPA were new minimum funding rules which went into effect for plan years beginning in 2008. The funding target was 100% of a plan’s liability (as determined under the PPA) with any shortfall amortized over seven years, with lower (92% – 100%) funding targets available to well-funded plans during the transition period. Due to the significant declines in the valuation of capital markets during 2008, the Worker, Retiree, and Employer Recovery Act of 2008 (Recovery Act) was signed into law on December 23, 2008. Included in the Recovery Act are temporary modifications to the minimum funding rules set forth in the PPA such that all plans, except those that were subject to deficit reduction contribution requirements in 2007, are allowed to amortize any shortfall from the lower funding targets, rather than the 100% target, for the 2008—2010 plan years. The Company’s Pension Plan was 80% funded under the requirements of the

Employee Retirement Income Security Act of 1974 (ERISA) as of January 1, 2010, which resulted in a shortfall of $10.2 million. This shortfall was being amortized over seven years with annual payments of $1.7 million, beginning in 2010. The $1.7 million 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 evaluated the two alternative shortfall amortization periods under the Relief Act and made the decision to continue with the seven year amortization period.

On July 6, 2012, the Moving Ahead for Progress in the 21st Century Act (MAP-21) was signed into law. MAP-21 increased the interest rates used to determine pension liability. The Company elected to apply the provisions of MAP-21 for purposes of determining pension liability for minimum funding purposes for the 2012 plan year. As part of this decision, the Company contributed $3.1 million in additional contributions in 2012 for the 2011 plan year to achieve 100% funding on the MAP-21 basis as of January 1, 2012. This eliminated the amortization payments created in prior years, discussed above. In addition, the minimum required contribution for the 2012 plan year decreased from $6.1 million to $1.0 million. Of the $9.4 million contributed during 2012, $8.3 million was attributed to the 2011 plan year and $1.1 million was attributed to the 2012 plan year.

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2013 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
	2012		2011		2010		2012		2011		2010		2012		2011		2010
Employer Contributions	$	9,387	$	8,813	$	4,302	$	2,190	$	—	$	3,482	$	53	$	53	$	53
Participant Contributions	$	—	$	—	$	—	$	18	$	13	$	—	$	—	$	—	$	—
Benefit Payments	$	4,456	$	3,438	$	3,185	$	2,083	$	1,644	$	1,848	$	53	$	53	$	53

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


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2013	$	4,698	$	1,811	$	357
2014		4,448		1,960		353
2015		4,567		2,083		349
2016		4,908		2,156		344
2017		5,121		2,284		339
2018 - 2022	$	30,278	$	13,535	$	1,767

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 2013			Actual Allocation at December 31,
	Target Allocation 2013			2012			2011			2010
Equity Funds		48	%		48	%		49	%		58	%
Debt Funds		47	%		47	%		46	%		42	%
Asset Allocation Fund⁽¹⁾		5	%		5	%		5	%		0	%

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 2013			Actual Allocation at December 31,
PBOP Plan	Target Allocation 2013			2012			2011			2010
Equity Funds		55	%		56	%		55	%		56	%
Debt Funds		45	%		44	%		45	%		44	%

Total					100	%		100	%		100	%

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

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2012 and 2011 are as follows ($000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31, 2012		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	$	34,742	$	34,742	$	—	$	—
Fixed Income Funds		34,251		34,251		—		—
Asset Allocation Fund		3,418		3,418		—		—

Total Assets	$	72,411	$	72,411	$	—	$	—


	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	$	—	$	—

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2012 and 2011 are as follows ($000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31, 2012		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	$	3,670	$	3,670	$	—	$	—
Index Funds		3,357		3,357
Equity Funds		1,274		1,274

Total Assets	$	8,301	$	8,301	$	—	$	—


	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	$	—	$	—

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

The Company’s contributions to the 401(k) Plan were $1,387,000, $1,190,000 and $980,000 for the years ended December 31, 2012, 2011, and 2010, 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,
	2012		2011		2012			2011			2012		2011			2012		2011
Total Operating Revenues	$	114.2	$	115.4	$	68.8		$	69.5		$	71.3	$	73.2		$	98.8	$	94.7
Operating Income	$	14.0	$	13.4	$	4.3		$	4.2		$	5.0	$	5.2		$	13.2	$	14.4
Net Income (Loss) Applicable to Common	$	9.0	$	8.7	$	(0.4	)	$	(0.8	)	$	0.5	$	(1.6	)	$	9.0	$	10.0

	Per Share Data:
Earnings Per Common Share	$	0.83	$	0.81	$	(0.03	)	$	(0.08	)	$	0.03	$	(0.15	)	$	0.66	$	0.92
Dividends Paid Per Common Share	$	0.345	$	0.345	$	0.345		$	0.345		$	0.345	$	0.345		$	0.345	$	0.345

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, 2012. Based on this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of December 31, 2012 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, 2012, 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, 2012.

McGladrey LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2012, 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, 2012 that have materially affected, or are reasonably likely to materially affect, Unitil’s internal control over financial reporting.

Item 9B.

Other Information

None.

PART III

Item 10.

Directors, Executive Officers 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 18, 2013. 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 18, 2013. 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 18, 2013.

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 18, 2013.

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 18, 2013, as well as the Equity Compensation Plan Information table in Part II, Item 5 of this Form 10-K.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

Information required by this Item is set forth in the “Transactions with Related Persons” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 18, 2013.

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 18, 2013.

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, 2012 and 2011

•

Consolidated Statements of Earnings for the years ended December 31, 2012, 2011, and 2010

•

Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011, and 2010

•

Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2012, 2011, and 2010

•

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	Second Amended and Restated By-Laws of the Company.	Exhibit 3.1 to Form 8-K/A dated December 13, 2012

	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


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


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***	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

	10.8	Entitlement Sale and Administrative Service Agreement with Select Energy.	Exhibit 10.14 to Form 10-K for 1999

	10.9	Unitil Corporation Second Amended and Restated 2003 Stock Plan	Exhibit 10.1 to Form 8-K dated April 19, 2012

	10.10	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

	10.11	Unitil Corporation Tax Deferred Savings and Investment Plan—Trust Agreement.	Exhibit 10.1 to Form 10-Q for September 30, 2004

	10.12***	Amended and Restated Employment Agreement effective as of November 1, 2012 by and between Unitil Corporation and Robert G. Schoenberger.	Exhibit 10.1 to Form 8-K dated September 19, 2012

	10.13	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

	10.14	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

	10.15	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

	10.16	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

	10.17	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

	10.18	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

	10.19	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

	10.20	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

	10.21***	Unitil Corporation—Compensation of Directors.	Filed herewith

	11.1	Statement Re: Computation in Support of Earnings per Share for the Company.	Filed herewith


Exhibit Number		Description of Exhibit	Reference*
	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

	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 30, 2013 Announcing Earnings For the Quarter and Year Ended December 31, 2012	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.

SIGNATURES

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


	UNITIL CORPORATION

Date January 30, 2013	By	/s/ ROBERT G. SCHOENBERGER
		Robert G. Schoenberger
		Chairman of the Board of Directors, Chief Executive Officer and President

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


Signature	Capacity	Date

/S/ ROBERT G. SCHOENBERGER Robert G. Schoenberger	Principal Executive Officer; Director	January 30, 2013

/S/ MARK H. COLLIN Mark H. Collin	Principal Financial Officer	January 30, 2013

/S/ LAURENCE M. BROCK Laurence M. Brock	Principal Accounting Officer	January 30, 2013

/S/ MICHAEL J. DALTON Michael J. Dalton	Director	January 30, 2013

/S/ ALBERT H. ELFNER, III Albert H. Elfner, III	Director	January 30, 2013

/S/ M. BRIAN O’SHAUGHNESSY M. Brian O’Shaughnessy	Director	January 30, 2013

/S/ WILLIAM D. ADAMS William D. Adams	Director	January 30, 2013

/S/ DR. SARAH P. VOLL Dr. Sarah P. Voll	Director	January 30, 2013

/S/ EBEN S. MOULTON Eben S. Moulton	Director	January 30, 2013

/S/ DAVID P. BROWNELL David P. Brownell	Director	January 30, 2013

/S/ EDWARD F. GODFREY Edward F. Godfrey	Director	January 30, 2013

/S/ MICHAEL B. GREEN Michael B. Green	Director	January 30, 2013

/S/ DR. ROBERT V. ANTONUCCI Dr. Robert V. Antonucci	Director	January 30, 2013

/S/ LISA CRUTCHFIELD Lisa Crutchfield	Director	January 30, 2013

/S/ DAVID A. WHITELEY David A. Whiteley	Director	January 30, 2013

EXHIBIT INDEX


Exhibit No.		Description
	10.21	Unitil Corporation—Compensation of Directors.

	11.1	Statement Re: Computation in Support of Earnings per Share of the Company.

	12.1	Statement Re: Computation in Support of Ratio of Earnings to Fixed Charges for the Company.

	21.1	Statement Re: Subsidiaries of Registrant.

	23.1	Consent of Independent Registered Public Accounting Firm.

	31.1-31.3	Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1	Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	99.1	Unitil Corporation Press Release Dated January 30, 2013 Announcing Earnings For the Quarter and Year Ended December 31, 2012.

	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.