Edgar Filing: UNITIL CORP

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Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended September 30, 2012

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 office)		(Zip Code)

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

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

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

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class		Outstanding at October 19, 2012
Common Stock, No par value		13,769,825 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended September 30, 2012

Table of Contents


		Page No.
Part I. Financial Information

Item 1.	Financial Statements - Unaudited

	Consolidated Statements of Earnings - Three and Nine Months Ended September 30, 2012 and 2011	20

	Consolidated Balance Sheets, September 30, 2012, September 30, 2011 and December 31, 2011	21-22

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2012 and 2011	23

	Notes to Consolidated Financial Statements	24-38

Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations	3-19

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38

Item 4.	Controls and Procedures	38

Part II. Other Information

Item 1.	Legal Proceedings	38

Item 1A.	Risk Factors	38

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38

Item 3.	Defaults Upon Senior Securities	Inapplicable

Item 4.	Mine Safety Disclosures	Inapplicable

Item 5.	Other Information	39

Item 6.	Exhibits	40

Signatures		41

Exhibits		42

PART I. FINANCIAL INFORMATION

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

Unitil Corporation (Unitil or the Company) is a public utility holding company headquartered in Hampton, New Hampshire. Unitil is subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005.

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

Unitil Energy Systems, Inc. (Unitil Energy), which provides electric service in the southeastern seacoast and state capital regions of New Hampshire, including the capital city of Concord, New Hampshire;

ii)

Fitchburg Gas and Electric Light Company (Fitchburg), which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts; and

iii)

Northern Utilities, Inc. (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.

Unitil Energy, Fitchburg and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 101,400 electric customers and 71,900 natural gas customers in their service areas.

In addition, Unitil is the parent company of Granite State Gas Transmission, Inc. (Granite State) an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north.

Unitil had an investment in Net Utility Plant of $535.1 million at September 30, 2012. Unitil’s total operating revenue 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 directly affected by changes in the cost of purchased electricity and natural gas. Earnings from Unitil’s utility operations are primarily derived from the return on investment in the utility assets of the three distribution utilities and Granite State.

Unitil also conducts non-regulated operations principally through Usource Inc. and Usource L.L.C. (collectively, Usource), which is wholly-owned by Unitil Resources Inc., a wholly-owned subsidiary of Unitil. Usource provides energy brokering and advisory services to commercial and industrial customers primarily in the northeastern United States. As an energy broker and advisor, Usource assists its clients with the procurement and contracting for electricity and natural gas in competitive energy markets. The Company’s other subsidiaries include Unitil Service Corp., which provides, at cost, a variety of administrative and professional services to Unitil’s affiliated companies, Unitil Realty Corp. (Unitil Realty), which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire and Unitil Power Corp., which formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

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 the 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 areas, at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, Unitil’s customers have the opportunity to purchase their electricity or natural gas supplies from third-party energy supply vendors. Most customers, however, continue to purchase such supplies through the distribution utilities under regulated energy rates and tariffs. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual approved costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

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 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, to which RDM does not apply. The difference between distribution revenue amounts billed to customers and the targeted amounts is recognized as an increase or a decrease 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 13% of Unitil’s total annual electric and natural gas sales volumes, respectively. As a result, the sales margins resulting from those sales are no longer sensitive to weather and economic factors. The Company’s other electric and natural gas distribution utilities are not subject to RDM.

CAUTIONARY STATEMENT

This report and the documents incorporated by reference into this report contain statements that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, included or incorporated by reference into this report, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for the Company’s future operations, are forward-looking statements.

These statements include declarations regarding the Company’s beliefs and current expectations. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue,” or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in Item 1A (Risk Factors) and the following:

•

the Company’s regulatory environment (including regulations relating to climate change, greenhouse gas emissions and other environmental matters), which could affect the rates the Company is able to charge, the Company’s authorized rate of return, the Company’s cost of service 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 counterparties’ 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 and energy used 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.

RESULTS OF OPERATIONS

The following section of Management’s Discussion & Analysis compares the results of operations for each of the two fiscal periods ended September 30, 2012 and September 30, 2011 and should be read in conjunction with the accompanying unaudited Consolidated Financial Statements and the accompanying Notes to unaudited Consolidated Financial Statements included in Part I, Item 1 of this report.

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

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

Earnings Overview

The Company’s Earnings Applicable to Common Shareholders was $0.5 million, or $0.03 per share, for the third quarter of 2012, an improvement of $2.1 million, or $0.18 per share, compared to the third quarter of 2011. For the nine months ended September 30, 2012, the Company reported Earnings of $9.1 million, or $0.74 per share, compared to $6.3 million, or $0.58 per share, for the same period of 2011. Results were positively affected by higher natural gas and electric sales margins due to higher distribution rates and new customer growth, and reflect the effect on sales of fluctuations in seasonal weather conditions year over year. The Company estimates that the mild weather in the winter and early spring of 2012 negatively impacted earnings by about $2.0 million, or $0.17 per share. Additionally, in the third quarter of 2011, in connection with rate cases in Massachusetts, the Company recognized a non-recurring pre-tax charge of $2.0 million, or $0.11 per share, related to accrued carrying charges that were disallowed for rate recovery.

Natural gas sales margins were $11.2 million in the three months ended September 30, 2012, or an increase of $3.0 million compared to the third quarter of 2011, reflecting higher distribution rates from recently completed rate cases, new customer growth and a corresponding increase in gas therm sales of 3.0%. Natural gas sales margins were $51.1 million in the nine month period ended September 30, 2012, or an increase of $8.3 million compared to the same nine month period in 2011, reflecting higher distribution rates from recently completed rate cases and new customer growth, but negatively impacted by lower gas therm sales primarily due to mild winter weather earlier in the year. Based on weather data collected in the Company’s service areas, there were 20% fewer Heating Degree Days in the first nine months of 2012 compared to the same period in 2011. Weather-normalized gas therm sales (excluding decoupled sales) in the three and nine month periods ended September 30, 2012 are estimated to be approximately 5% and 2% higher, respectively, compared to the same periods in 2011. Approximately 13% 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 $19.1 million in the three months ended September 30, 2012, or an increase of $1.3 million compared to the third quarter of 2011, reflecting higher electric distribution rates and an increase in kilowatt hour (kWh) sales primarily driven by new customer growth and an increase in usage during the summer. There were 19% more Cooling Degree Days in the third quarter of 2012 compared to the same period in 2011. In the nine month period ended September 30, 2012, electric sales margins were $52.7 million, or an increase of $2.9 million compared to the same period in 2011, reflecting higher electric distribution rates and new customer growth, but negatively impacted by lower electric kWh sales primarily due to mild winter weather earlier in the year. Weather-normalized electric kWh sales (excluding decoupled sales) in the three and nine month periods ended September 30, 2012 are estimated to be approximately 2% lower and 1% higher, respectively, compared to the same period in 2011. Approximately 27% of electric kWh sales are decoupled and changes in these sales due to the weather do not affect sales margins.

Operation and Maintenance (O&M) expenses increased $0.8 million and $4.4 million for the three and nine months ended September 30, 2012, respectively, compared to the same periods in 2011. The increase in the three month period reflects higher utility operating costs of $1.1 million and higher employee compensation and benefit costs of $0.1 million, partially offset by lower professional fees of $0.4 million. The increase in O&M expenses in the first nine months of 2012 compared to the same period in 2011 reflects lower O&M expenses recorded in the first quarter of 2011 due to the receipt of a $1.0 million insurance payment. Other changes in O&M expenses in the nine month period include higher utility operating costs of $2.3 million, higher employee compensation and benefit costs of $1.0 million, and higher professional fees of $0.1 million. Utility operating costs in the three and nine months ended September 30, 2012 include approximately $1.0 million and $2.5 million, respectively, of spending on new vegetation management and electric reliability enhancement programs. These costs are recovered through cost tracker rate mechanisms that result in corresponding increases in revenue.

Depreciation and Amortization expense increased $2.0 million and $3.4 million in the three and nine months ended September 30, 2012, respectively, compared to the same periods in 2011, principally reflecting normal utility plant additions and amortization of regulatory assets.

Local Property and Other Taxes increased $0.3 million and $1.2 million in the three and nine month periods ended September 30, 2012, respectively, compared to the same periods in 2011, reflecting higher local property taxes on higher levels of utility plant in service.

Federal and State Income Taxes increased by $1.4 million and $1.6 million for the three and nine month periods, respectively, due to higher pre-tax earnings in 2012 compared to 2011.

Interest Expense, Net decreased $2.2 million and $2.1 million in the three and nine month periods ended September 30, 2012, respectively, compared to the same periods in 2011, primarily reflecting 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.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $1.5 million and $4.1 million for the three and nine month periods ended September 30, 2012, on par with the same periods in 2011.

In 2011, Unitil’s annual common dividend was $1.38, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January, 2012, March, 2012, June 2012 and September 2012 meetings, the Unitil Board of Directors declared quarterly dividends on the Company’s common stock of $0.345 per share.

A more detailed discussion of the Company’s results of operations for the three and nine months ended September 30, 2012 is presented below.

Gas Sales, Revenues and Margin

Therm Sales – Total natural gas therm sales volumes increased 3.0% in the three month period ended September 30, 2012 compared to the same period in 2011, reflecting increased usage by C&I customers in their operations. In the nine months ended September 30, 2012, gas therm sales decreased 8.0% compared to the same period in 2011. The decrease in gas therm sales in the Company’s utility service areas reflects the effect of milder weather in the first nine months of 2012 compared to 2011. Based on weather data collected in the Company’s service areas, there were 20% fewer Heating Degree Days in the first nine months of 2012 compared to the same period in 2011. Weather-normalized gas therm sales (excluding decoupled sales) in the three and nine month periods ended September 30, 2012 are estimated to be approximately 5% and 2% higher, respectively, compared to the same periods in 2011. Approximately 13% 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.

The following table details total firm therm sales for the three and nine months ended September 30, 2012 and 2011, by major customer class:


Therm Sales (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2012		2011		Change			% Change			2012		2011		Change			% Change
Residential		2.5		2.6		(0.1	)		(3.8	%)		26.0		30.5		(4.5	)		(14.8	%)
Commercial / Industrial		21.3		20.5		0.8			3.9	%		107.0		114.1		(7.1	)		(6.2	%)

Total		23.8		23.1		0.7			3.0	%		133.0		144.6		(11.6	)		(8.0	%)

Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and Sales Margin for the three and nine months ended September 30, 2012 and 2011:


Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2012		2011		$ Change			% Change⁽¹⁾			2012		2011		$ Change			% Change⁽¹⁾
Gas Operating Revenue:
Residential	$	7.4	$	8.0	$	(0.6	)		(2.8	%)	$	44.3	$	46.8	$	(2.5	)		(2.2	%)
Commercial / Industrial		12.9		13.2		(0.3	)		(1.4	%)		62.9		65.5		(2.6	)		(2.3	%)

Total Gas Operating Revenue	$	20.3	$	21.2	$	(0.9	)		(4.2	%)	$	107.2	$	112.3	$	(5.1	)		(4.5	%)

Cost of Gas Sales:
Purchased Gas	$	8.6	$	12.5	$	(3.9	)		(18.4	%)	$	54.5	$	68.0	$	(13.5	)		(12.0	%)
Conservation & Load Management		0.5		0.5		—			—			1.6		1.5		0.1			0.1	%

Total Cost of Gas Sales	$	9.1	$	13.0	$	(3.9	)		(18.4	%)	$	56.1	$	69.5	$	(13.4	)		(11.9	%)

Gas Sales Margin	$	11.2	$	8.2	$	3.0			14.2	%	$	51.1	$	42.8	$	8.3			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 since 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.

The decrease in Total Gas Operating Revenues of $0.9 million in the third quarter of 2012 reflects lower costs of sales of $3.9 million, which are tracked costs that are passed through directly to customers. These lower costs of sales were partially offset by higher gas base revenues of $3.0 million.

The decrease in Total Gas Operating Revenues of $5.1 million in the nine months ended September 30, 2012 reflects lower costs of sales of $13.4 million, including lower Purchased Gas costs of $13.5 million and higher C&LM costs of $0.1 million, which are tracked costs that are passed through directly to customers. These lower costs of sales were partially offset by higher gas base revenues of $8.3 million.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Total kWh sales increased 0.5% in the three month period ended September 30, 2012 compared to the same period in 2011, reflecting warmer summer weather in 2012 compared to 2011 and customer growth. There were 19% more Cooling Degree Days in the third quarter of 2012 compared to the same period in 2011. Total kWh sales decreased 2.3% in the nine months ended September 30, 2012 compared to the same period in 2011. The decreases in kWh sales in the nine month period primarily reflect the effect of milder weather in the first nine months of 2012 compared to 2011. As discussed above, there were 20% fewer Heating Degree Days in the first nine months of 2012 compared to the same period in 2011. Weather-normalized kWh sales (excluding decoupled sales) in the three and nine month periods ended September 30, 2012 are estimated to be approximately 2% lower and 1% higher, respectively, compared to the same periods in 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.

The following table details total kWh sales for the three and nine months ended September 30, 2012 and 2011 by major customer class:


kWh Sales (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2012		2011		Change			% Change			2012		2011		Change			% Change
Residential		198.2		190.2		8.0			4.2	%		522.8		530.1		(7.3	)		(1.4	%)
Commercial / Industrial		270.7		276.5		(5.8	)		(2.1	%)		744.1		766.2		(22.1	)		(2.9	%)

Total		468.9		466.7		2.2			0.5	%		1,266.9		1,296.3		(29.4	)		(2.3	%)

Electric Operating Revenues and Sales Margin – The following table details total Electric Operating Revenues and Sales Margin for the three and nine month periods ended September 30, 2012 and 2011:


Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2012		2011		$ Change			% Change⁽¹⁾			2012		2011		$ Change			% Change⁽¹⁾
Electric Operating Revenue:
Residential	$	27.4	$	27.2	$	0.2			0.4	%	$	78.5	$	76.1	$	2.4			1.7	%
Commercial / Industrial		22.1		23.3		(1.2	)		(2.4	%)		64.5		65.5		(1.0	)		(0.7	%)

Total Electric Operating Revenue	$	49.5	$	50.5	$	(1.0	)		(2.0	%)	$	143.0	$	141.6	$	1.4			1.0	%

Cost of Electric Sales:
Purchased Electricity	$	28.3	$	31.0	$	(2.7	)		(5.4	%)	$	85.1	$	88.0	$	(2.9	)		(2.0	%)
Conservation & Load Management		2.1		1.7		0.4			0.8	%		5.2		3.8		1.4			1.0	%

Total Cost of Electric Sales	$	30.4	$	32.7	$	(2.3	)		(4.6	%)	$	90.3	$	91.8	$	(1.5	)		(1.0	%)

Electric Sales Margin	$	19.1	$	17.8	$	1.3			2.6	%	$	52.7	$	49.8	$	2.9			2.0	%

⁽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 since 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.

The decrease in Total Electric Operating Revenues of $1.0 million in the third quarter of 2012 reflects lower cost of sales of $2.3 million, including lower Purchased Electricity costs of $2.7 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 base revenues of $1.3 million.

The increase in Total Electric Operating Revenues of $1.4 million in the nine months ended September 30, 2012 reflects higher electric base revenues of $2.9 million. These higher electric base revenues were partially offset by lower cost of sales of $1.5 million, including lower Purchased Electricity costs of $2.9 million and higher C&LM costs of $1.4 million, which are tracked costs that are passed through directly to customers.

Operating Revenue - Other

The following table details total Other Revenue for the three and nine months ended September 30, 2012 and 2011:


Other Revenue (000’s)
	Three Months Ended September 30,								Nine Months Ended September 30,
	2012		2011		$ Change		% Change		2012		2011		$ Change			% Change
Other	$	1.5	$	1.5	$	—		—	$	4.1	$	4.2	$	(0.1	)		(2.4	%)

Total Other Revenue	$	1.5	$	1.5	$	—		—	$	4.1	$	4.2	$	(0.1	)		(2.4	%)

Total Other Operating Revenue is comprised of revenues from the Company’s non-regulated energy brokering business, Usource. For the three months ended September 30, 2012 Usource’s revenues were on par with same period in 2011. Usource’s revenues decreased $0.1 million in the nine month period ended September 30, 2012 compared to the same period in 2011. 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.

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 $3.9 million, or 31.2%, and $13.5 million, or 19.9%, in the three and nine month periods ended September 30, 2012, respectively, compared to the same periods in 2011. These decreases reflect lower wholesale natural gas prices and a decline in sales of natural gas compared to the prior period. The Company recovers the approved costs of Purchased Gas through reconciling rate mechanisms which track costs and revenues for recovery on a pass-through basis and therefore changes in approved expenses do not affect earnings.

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 $2.7 million, or 8.7%, and $2.9 million, or 3.3%, in the three and nine month periods ended September 30, 2012, respectively, compared to the same periods in 2011. The decreases reflect an increase in the amount of electricity purchased by customers directly from third-party suppliers and lower kWh sales for the year-to-date period. The Company recovers the approved costs of Purchased Electricity through reconciling rate mechanisms which track costs and revenues for recovery on a pass-through basis and therefore changes in approved expenses do not affect earnings.

Operation and Maintenance (O&M) – O&M expense includes electric and gas utility operating costs, and the operating cost of the Company’s unregulated business activities. Total O&M expenses increased $0.8 million and $4.4 million for the three and nine months ended September 30, 2012, respectively, compared to the same periods in 2011. The increase in the three month period reflects higher utility operating costs of $1.1 million and higher employee compensation and benefit costs of $0.1 million, partially offset by lower professional fees of $0.4 million. The increase in O&M expenses in the first nine months of 2012 compared to the same period in 2011 reflects lower O&M expenses recorded in the first quarter of 2011 due to the receipt of a $1.0 million insurance payment. Other changes in O&M expenses in the nine month period include higher utility operating costs of $2.3 million, higher employee compensation and benefit costs of $1.0 million, and higher professional fees of $0.1 million. Utility operating costs in the three and nine months ended September 30, 2012 include approximately $1.0 million and $2.5 million, respectively, of spending on new vegetation management and electric reliability enhancement programs. These costs 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. In the third quarter of 2012, approximately 80% of these costs were related to electric operations and 20% to gas operations.

Total C&LM expenses increased $0.4 million, or 18.2% and $1.5 million, or 28.3%, in the three and nine month periods ended September 30, 2012 compared to the same periods in 2011. These approved costs are collected from customers on a pass through basis and therefore, fluctuations in program costs do not affect earnings.

Depreciation, Amortization and Taxes

Depreciation and Amortization – Depreciation and Amortization expense increased $2.0 million, or 29.0%, and $3.4 million, or 15.1%, in the three and nine months ended September 30, 2012, respectively, compared to the same periods in 2011, principally reflecting normal utility plant additions and amortization of regulatory assets.

Local Property and Other Taxes – Local Property and Other Taxes increased $0.3 million and $1.2 million in the three and nine month periods ended September 30, 2012, respectively, compared to the same periods in 2011, reflecting higher local property taxes on higher levels of utility plant in service.

Federal and State Income Taxes – Federal and State Income Taxes increased by $1.4 million and $1.6 million for the three and nine month periods, respectively, due to higher pre-tax earnings in 2012 compared to 2011.

Other Non-Operating Expenses (Income)

Other Non-Operating Expenses decreased $0.1 million and $0.2 million in the three and nine month periods ended September 30, 2012 compared to the same periods in 2011.

Interest Expense, Net

Interest expense is presented in the consolidated financial statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and short-term borrowings. 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.


Interest Expense, Net (Millions)	Three Months Ended September 30,									Nine Months Ended September 30,
	2012			2011			Change			2012			2011			Change
Interest Expense
Long-term Debt	$	5.1		$	5.1		$	—		$	15.2		$	15.2		$	—
Short-term Debt		0.2			0.4			(0.2	)		1.2			1.2			—
Regulatory Liabilities		—			0.1			(0.1	)		0.2			0.2			—

Subtotal Interest Expense		5.3			5.6			(0.3	)		16.6			16.6			—

Interest (Income)
Regulatory Assets		(0.7	)		1.2			(1.9	)		(2.1	)		(0.2	)		(1.9	)
AFUDC⁽¹⁾ and Other		(0.2	)		(0.2	)		—			(0.6	)		(0.4	)		(0.2	)

Subtotal Interest (Income)		(0.9	)		1.0			(1.9	)		(2.7	)		(0.6	)		(2.1	)

Total Interest Expense, Net	$	4.4		$	6.6		$	(2.2	)	$	13.9		$	16.0		$	(2.1	)

⁽¹⁾	AFUDC – Allowance for Funds Used During Construction.

CAPITAL REQUIREMENTS

Sources of Capital

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent and future periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities. The Company initially supplements internally generated funds through bank borrowings, as needed, under its unsecured short-term revolving credit facility. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term nature of its utility assets. Additionally, 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 were approximately $65.7 million and were used to make equity capital contributions to the Company’s regulated utility subsidiaries, repay short-term debt and for general corporate purposes.

The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (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 September 30, 2012, September 30, 2011 and December 31, 2011, all of the Company’s subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

Unitil has a revolving credit facility with a group of banks that extends to October 8, 2013. 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 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 September 30, 2012, September 30, 2011 and December 31, 2011:


	September 30,				December 31,
Revolving Credit Facility (millions)	2012		2011		2011
Limit	$	60.0	$	80.0	$	115.0
Outstanding	$	24.1	$	65.4	$	87.9
Available	$	35.9	$	14.6	$	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 September 30, 2012, September 30, 2011 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.

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 September 30, 2012, there were approximately $20.6 million of guarantees outstanding and the longest term guarantee extends through February 2014.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There were obligations of $10.6 million, $13.0 million and $14.9 million outstanding at September 30, 2012, September 30, 2011 and December 31, 2011, respectively, related to these asset management agreements. There were no amounts of natural gas inventory released in September 2012 and payable in October 2012 that were recorded in Accounts Payable at September 30, 2012. There were no amounts of natural gas inventory released in September 2011 and payable in October 2011 that were recorded in Accounts Payable at September 30, 2011. 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 September 30, 2012, the principal amount outstanding for the 8% Unitil Realty notes was $3.0 million, and the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

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.

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 the nine months ended September 30, 2012 compared to the same period in 2011.


	Nine Months Ended September 30,
	2012		2011
Cash Provided by Operating Activities	$	61.9	$	49.8

Cash Provided by Operating Activities – Cash Provided by Operating Activities was $61.9 million in 2012, an increase of $12.1 million compared to 2011. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes, was $40.0 million in 2012 compared to $31.4 million in 2011, representing an increase of $8.6 million. Working capital changes in Current Assets and Liabilities resulted in a $26.4 million net source of cash in 2012 compared to a $14.9 million net source of cash in 2011, representing an increase of $11.5 million. Deferred Regulatory and Other Charges resulted in a $3.6 million source of cash in 2012 compared to an $8.8 million source of cash in 2011. All Other, net operating activities resulted in a use of cash of ($8.1) million in 2012 compared to a use of cash of ($5.3) million in 2011.


	Nine Months Ended September 30,
	2012			2011
Cash (Used in) Investing Activities	$	(47.4	)	$	(42.7	)

Cash (Used in) Investing Activities – Cash Used in Investing Activities was ($47.4) million for 2012 compared to ($42.7) million in 2011. The capital spending in both periods is representative of normal distribution utility capital expenditures reflecting normal electric and gas utility system additions.


	Nine Months Ended September 30,
	2012			2011
Cash (Used in) Financing Activities	$	(12.5	)	$	(8.1	)

Cash (Used in) Financing Activities – Cash Used in Financing Activities was ($12.5) million in 2012 compared to ($8.1) million in 2011. Sources of cash in 2012 are from the issuance of common stock of $66.5 million, including the Company’s equity offering in May 2012 and common stock issued in connection with its Dividend Reinvestment and Stock Purchase Plan and its 401(k) Plan. In 2012, uses of cash included net repayment of short-term debt of ($63.8) million, a decrease in net gas inventory financing of ($1.8) million, regular quarterly dividend payments on common and preferred stock of ($12.4) million and repayment of long-term debt of ($0.3) million. All other financing activities resulted in a net use of cash of ($0.7) million.

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 Note 1 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 1, 2012.

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 (FASB) Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

Regulatory Assets consist of the following (millions)


	September 30,				December 31,
	2012		2011		2011
Energy Supply Contract Obligations	$	6.4	$	14.9	$	12.9
Deferred Restructuring Costs		20.2		22.0		21.8

Subtotal – Restructuring Related Items		26.6		36.9		34.7
Retirement Benefit Obligations		55.2		47.0		55.3
Income Taxes		10.6		12.1		10.9
Environmental Obligations		16.7		17.9		17.5
Deferred Storm Charges		25.4		18.5		22.4
Other		14.6		15.0		17.8

Total Regulatory Assets	$	149.1	$	147.4	$	158.6
Less: Current Portion of Regulatory Assets⁽¹⁾		12.2		16.5		18.8

Regulatory Assets – noncurrent	$	136.9	$	130.9	$	139.8

⁽¹⁾	Reflects amounts included in Accrued Revenue on the Company’s unaudited 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.

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

On August 1, 2011, the MDPU issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of 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, to which RDM does not apply. The difference between distribution revenue amounts billed to customers and the targeted amounts is recognized as an increase or a decrease 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 year ended December 31, 2011, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $325,000 in the Net Periodic Benefit Cost for the Pension Plan. For the year ended December 31, 2011, a 1.0% increase in the assumption of health care cost trend rates would have resulted in an increase in the Net Periodic Benefit Cost for the PBOP Plan of $909,000. Similarly, a 1.0% decrease in the assumption of health care cost trend rates for 2011 would have resulted in a decrease in the Net Periodic Benefit Cost for the PBOP Plan of $705,000. (See Note 9 to the accompanying unaudited 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 unaudited 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 unaudited consolidated statements of earnings.

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. Periodically, the Company assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.

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

Commitments and Contingencies – The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of September 30, 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 unaudited consolidated financial statements below. Refer to “Recently Issued Pronouncements in Note 1 of the Notes of unaudited Consolidated Financial Statements for information regarding recently issued accounting standards.

LABOR RELATIONS

As of September 30, 2012, the Company and its subsidiaries had 464 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of September 30, 2012, 153 of the Company’s employees were represented by labor unions. There are 79 union employees covered by two separate collective bargaining agreements which expire on May 31, 2013 and June 5, 2014. The agreements provide discreet salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.

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

There are 39 union employees who were covered by a separate collective bargaining agreement which expired on May 31, 2012. The Company and the relevant labor union have prepared a Memorandum of Understanding outlining the terms of a new collective bargaining agreement, which will expire on May 31, 2018, and the labor union has approved such terms. Such terms include discreet salary adjustments, established work practices and uniform benefit packages. The Company expects to execute the final agreement in the fourth quarter of 2012.

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 rates on the Company’s short-term borrowings for the three months ended September 30, 2012 and September 30, 2011 were 2.02% and 2.24%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 2012 and September 30, 2011 were 2.03% and 2.26%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2011 was 2.2%.

COMMODITY PRICE RISK

Although Unitil’s three distribution utilities are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for the reconciliation and collection of approved Purchased Electric and Purchased Gas costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making. Additionally, as discussed above and below in Regulatory Matters, the Company has divested its commodity-related contracts and therefore, further reduced its exposure to commodity risk.

REGULATORY MATTERS

Please refer to Note 6 to the Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Regulatory Matters.

ENVIRONMENTAL MATTERS

Please refer to Note 7 to the Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Environmental Matters.

Item 1.

Financial Statements—Unaudited

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions except common shares and per share data)

(UNAUDITED)


	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
Operating Revenues
Gas	$	20.3	$	21.2		$	107.2	$	112.3
Electric		49.5		50.5			143.0		141.6
Other		1.5		1.5			4.1		4.2

Total Operating Revenues		71.3		73.2			254.3		258.1

Operating Expenses
Purchased Gas		8.6		12.5			54.5		68.0
Purchased Electricity		28.3		31.0			85.1		88.0
Operation and Maintenance		14.4		13.6			42.7		38.3
Conservation & Load Management		2.6		2.2			6.8		5.3
Depreciation and Amortization		8.9		6.9			25.9		22.5
Provisions (Benefit) for Taxes:
Local Property and Other		3.5		3.2			10.7		9.5
Federal and State Income		—		(1.4	)		5.3		3.7

Total Operating Expenses		66.3		68.0			231.0		235.3

Operating Income		5.0		5.2			23.3		22.8
Non-Operating Expenses		0.1		0.2			0.2		0.4

Income Before Interest Expense		4.9		5.0			23.1		22.4
Interest Expense, Net		4.4		6.6			13.9		16.0

Net Income (Loss)		0.5		(1.6	)		9.2		6.4
Less: Dividends on Preferred Stock		—		—			0.1		0.1

Earnings (Loss) Applicable to Common Shareholders	$	0.5	$	(1.6	)	$	9.1	$	6.3


Weighted Average Common Shares Outstanding – Basic (000’s)		13,707		10,887			12,318		10,875
Weighted Average Common Shares Outstanding – Diluted (000’s)		13,709		10,887			12,321		10,877
Earnings Per Common Share (Basic and Diluted)	$	0.03	$	(0.15	)	$	0.74	$	0.58
Dividends Declared Per Share of Common Stock	$	0.345	$	0.345		$	1.38	$	1.38

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)


	September 30,				December 31,
	2012		2011		2011
ASSETS:

Utility Plant:
Electric	$	348.2	$	326.6	$	333.3
Gas		398.4		363.9		382.3
Common		30.6		30.4		29.8
Construction Work in Progress		35.8		41.4		28.3

Total Utility Plant		813.0		762.3		773.7
Less: Accumulated Depreciation		277.9		262.5		263.0

Net Utility Plant		535.1		499.8		510.7

Current Assets:
Cash		9.5		7.9		7.5
Accounts Receivable, net		30.7		30.4		44.2
Accrued Revenue		34.6		35.2		56.6
Gas Inventory		12.3		15.6		14.8
Materials and Supplies		3.6		3.8		3.6
Prepayments and Other		4.3		4.5		4.5

Total Current Assets		95.0		97.4		131.2

Noncurrent Assets:
Regulatory Assets		136.9		130.9		139.8
Other Noncurrent Assets		17.0		20.6		18.5

Total Noncurrent Assets		153.9		151.5		158.3

TOTAL ASSETS	$	784.0	$	748.7	$	800.2

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions)

(UNAUDITED)


	September 30,				December 31,
	2012		2011		2011
CAPITALIZATION AND LIABILITIES:

Capitalization:
Common Stock Equity	$	250.9	$	181.2	$	191.7
Preferred Stock		2.0		2.0		2.0
Long-Term Debt, Less Current Portion		287.5		288.0		287.8

Total Capitalization		540.4		471.2		481.5

Current Liabilities:
Long-Term Debt, Current Portion		0.5		0.5		0.5
Accounts Payable		17.1		16.0		26.4
Short-Term Debt		24.1		65.4		87.9
Energy Supply Contract Obligations		13.4		21.8		21.1
Taxes Payable		0.5		0.6		1.0
Other Current Liabilities		21.4		22.5		17.5

Total Current Liabilities		77.0		126.8		154.4

Deferred Income Taxes		51.7		46.7		46.3

Noncurrent Liabilities:
Energy Supply Contract Obligations		3.6		6.1		4.2
Retirement Benefit Obligations		88.9		74.1		91.2
Environmental Obligations		14.5		14.4		14.5
Other Noncurrent Liabilities		7.9		9.4		8.1

Total Noncurrent Liabilities		114.9		104.0		118.0

TOTAL CAPITALIZATION AND LIABILITIES	$	784.0	$	748.7	$	800.2

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)


	Nine Months Ended September 30,
	2012			2011
Operating Activities:
Net Income	$	9.2		$	6.4
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		25.9			22.5
Deferred Tax Provision		4.9			2.5
Changes in Working Capital Items:
Accounts Receivable		13.5			6.5
Accrued Revenue		22.0			11.5
Gas Inventory		2.5			(5.0	)
Accounts Payable		(9.3	)		(10.5	)
Taxes Refundable / Payable		(0.5	)		8.1
Other Changes in Working Capital Items		(1.8	)		4.3
Deferred Regulatory and Other Charges		3.6			8.8
Other, net		(8.1	)		(5.3	)

Cash Provided by Operating Activities		61.9			49.8

Investing Activities:
Property, Plant and Equipment Additions		(47.4	)		(42.7	)

Cash (Used in) Investing Activities		(47.4	)		(42.7	)

Financing Activities:
Repayment of Short-Term Debt, net		(63.8	)		(1.4	)
Repayment of Long-Term Debt, net		(0.3	)		(0.3	)
Net Increase (Decrease) in Gas Inventory Financing		(1.8	)		5.1
Dividends Paid		(12.4	)		(11.4	)
Proceeds from Issuance of Common Stock, net		66.5			0.7
Other, net		(0.7	)		(0.8	)

Cash (Used in) Financing Activities		(12.5	)		(8.1	)

Net Increase (Decrease) in Cash		2.0			(1.0	)
Cash at Beginning of Period		7.5			8.9

Cash at End of Period	$	9.5		$	7.9

Supplemental Cash Flow Information:
Interest Paid	$	13.5		$	13.8
Income Taxes Paid (Refunded)	$	0.7		$	(7.3	)

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 subsidiaries of Unitil Resources.

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 and central Maine 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 a natural gas transportation pipeline, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to major natural gas pipelines and access to domestic 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 large commercial and industrial customers in the northeastern United States.

Basis of Presentation – The accompanying unaudited consolidated financial statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. The results of operations for the three and nine months ended September 30, 2012 are not necessarily indicative of results to be expected for the year ending December 31, 2012. For further information, please refer to Note 1 of Part II

to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form 10-K for the year ended December 31, 2011, as filed with the Securities and Exchange Commission (SEC) on February 1, 2012, for a description of the Company’s Basis of Presentation.

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 available in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are directly observable, and inputs derived principally from market data), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Purchased Gas when the gains and losses are passed through to customers in accordance with rate reconciling mechanisms.

As of September 30, 2012, September 30, 2011 and December 31, 2011, the Company had 2.1 billion, 1.7 billion and 1.6 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program.

The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments, under FASB ASC 815-20. As discussed above, the change in fair

value related to these derivatives is recorded initially as a Regulatory Asset then reclassified to Purchased Gas in accordance with the recovery mechanism. The tables below include disclosure of the Regulatory Asset and reclassifications from the Regulatory Asset into Purchased Gas.


Fair Value Amount Offset in Regulatory Assets⁽¹⁾, as of:
		Fair Value
(millions) Description	Balance Sheet Location	September 30, 2012		September 30, 2011		December 31, 2011
Natural Gas Futures Contracts	Other Current Liabilities	$	1.0	$	1.2	$	1.7

Natural Gas Futures Contracts	Other Noncurrent Liabilities		0.2		0.3		0.6

Total		$	1.2	$	1.5	$	2.3

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


	Three Months Ended September 30,					Nine Months Ended September 30,
(millions)	2012			2011		2012		2011
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	(0.3	)	$	0.9	$	1.1	$	1.5
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings⁽²⁾:
Purchased Gas	$	—		$	—	$	2.2	$	1.0

⁽²⁾	These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

The Allowance for Doubtful Accounts as of September 30, 2012, September 30, 2011 and December 31, 2011, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows:


	September 30,				December 31,
	2012		2011		2011
Allowance for Doubtful Accounts	$	2.7	$	2.5	$	2.3

Subsequent Events – The Company has evaluated all events or transactions through the date of this filing. During this period, the Company did not have any material subsequent events that impacted its consolidated financial statements.

Recently Issued Pronouncements – There are no recently issued pronouncements applicable to the Company that have not already been adopted.

NOTE 2 – COMMON DIVIDENDS DECLARED PER SHARE

Declaration

Date

Date Paid

(Payable)

Shareholder of

Record Date

Dividend

Amount

9/19/12

11/15/12

11/01/12

0.345

6/6/12

08/15/12

08/01/12

0.345

03/22/12

05/15/12

05/01/12

0.345

01/17/12

02/15/12

02/01/12

0.345

09/21/11

11/15/11

11/01/11

0.345

06/16/11

08/15/11

08/01/11

0.345

03/24/11

05/16/11

05/02/11

0.345

01/18/11

02/15/11

02/01/11

0.345

As of September 30, 2012, September 30, 2011 and December 31, 2011, the Company had $4.8 million, $3.8 million and $0.0 million, respectively, of common dividends payable recorded in Other Current Liabilities on its unaudited Consolidated Balance Sheets.

NOTE 3 – COMMON STOCK AND PREFERRED STOCK

Common Stock

The Company’s common stock trades under the symbol “UTL”.

The Company had 13,769,376, 10,944,675 and 10,954,065 of common shares outstanding at September 30, 2012, September 30, 2011 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 were approximately $65.7 million and were used to make equity capital contributions to the Company’s regulated utility subsidiaries, repay short-term debt and for general corporate purposes.

Dividend Reinvestment and Stock Purchase Plan – During the first nine months of 2012, the Company sold 30,490 shares of its common stock, at an average price of $26.70 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) Plan resulting in net proceeds of approximately $814,200. 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.

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 from the Company’s, its subsidiaries’ and its affiliates’ employees, directors and consultants to receive an award of shares of Company common stock, including restricted shares (RS), or of restricted stock units (RSU). 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.

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. The maximum number of shares of restricted stock available for awards to participants under the Stock Plan is 677,500. The maximum aggregate number of shares or restricted stock units 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.

On February 3, 2012, 25,600 restricted shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of $720,896. There were 53,942 and 52,362 non-vested shares under the Stock Plan as of September 30, 2012 and 2011, respectively. The weighted average grant date fair value of these shares was $24.67 and $22.21, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.1 million and $0.5 million for the nine months ended September 30, 2012 and 2011, respectively. At September 30, 2012, there was approximately $0.8 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.6 years. There were 779 restricted shares forfeited and there were no cancellations under the Stock Plan during the nine months ended September 30, 2012.

There were no RSUs issued under the Stock Plan during the nine months ended September 30, 2012. On October 1, 2012, there were 5,470 fully-vested RSUs issued to members of the Company’s Board of Directors. These restricted stock units will 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.

Preferred Stock

Details on preferred stock at September 30, 2012, September 30, 2011 and December 31, 2011 are shown below:


	September 30,				December 31,
	2012		2011		2011
Preferred Stock
Unitil Energy Preferred Stock, Non-Redeemable, Non-Cumulative:
6.00% Series, $100 Par Value,	$	0.2	$	0.2	$	0.2
Fitchburg Preferred Stock, Redeemable, Cumulative:
5.125% Series, $100 Par Value		0.8		0.8		0.8
8.00% Series, $100 Par Value		1.0		1.0		1.0

Total Preferred Stock	$	2.0	$	2.0	$	2.0

Shares Outstanding

September 30,

December 31,

2012

2011

Preferred Stock

Unitil Energy Preferred Stock, Non-Redeemable, Non-Cumulative:

6.00% Series, $100 Par Value,

2,250

2,250

Fitchburg Preferred Stock, Redeemable, Cumulative:

5.125% Series, $100 Par Value

7,823

7,861

8.00% Series, $100 Par Value

9,654

9,696

There were $0.1 million and $0.1 million of total dividends declared on Preferred Stock in the nine months ended September 30, 2012 and September 30, 2011, respectively.

NOTE 4 – LONG-TERM DEBT, CREDIT ARRANGEMENTS AND GUARANTEES

Long-Term Debt

Details on long-term debt at September 30, 2012, September 30, 2011 and December 31, 2011 are shown below ($ Millions):


	September 30,				December 31,
	2012		2011		2011
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0

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

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

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

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

Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due Through August 1, 2017		3.0		3.5		3.3

Total Long-Term Debt		288.0		288.5		288.3
Less: Current Portion		0.5		0.5		0.5

Total Long-term Debt, Less Current Portion	$	287.5	$	288.0	$	287.8

Fair Value of Long-Term Debt – Currently, the Company believes that there is no active market in the Company’s debt securities, which have all been sold through private placements. If there were an active market for the Company’s debt securities, the fair value of the Company’s long-term debt would be estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. The fair value of the Company’s long-term debt is estimated using Level 2 inputs (valuations based on quoted prices available in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in inactive markets,

inputs other than quoted prices that are directly observable, and inputs derived principally from market data.) In estimating the fair value of the Company’s long-term debt, the assumed market yield reflects the Moody’s Baa Utility Bond Average Yield. Costs, including prepayment costs, associated with the early settlement of long-term debt are not taken into consideration in determining fair value.


(Millions)	September 30,				December 31,
	2012		2011		2011
Estimated Fair Value of Long-Term Debt	$	343.6	$	338.0	$	338.7

Credit Arrangements

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as of September 30, 2012, September 30, 2011 and December 31, 2011:


	September 30,				December 31,
Revolving Credit Facility (millions)	2012		2011		2011
Limit	$	60.0	$	80.0	$	115.0
Outstanding	$	24.1	$	65.4	$	87.9
Available	$	35.9	$	14.6	$	27.1

Guarantees

The Company also 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 September 30, 2012, there were approximately $20.6 million of guarantees outstanding and the longest term guarantee extends through February 2014.

NOTE 5 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and nine months ended September 30, 2012 and September 30, 2011 (Millions):


Three Months Ended September 30, 2012	Electric		Gas			Other			Non-Regulated		Total
Revenues	$	49.5	$	20.3		$	—		$	1.5	$	71.3
Segment Profit (Loss)		2.5		(2.4	)		—			0.4		0.5
Capital Expenditures		6.1		16.8			0.6			—		23.5

Three Months Ended September 30, 2011
Revenues	$	50.5	$	21.2		$	—		$	1.5	$	73.2
Segment Profit (Loss)		2.3		(4.2	)		(0.1	)		0.4		(1.6	)
Capital Expenditures		6.7		9.9			1.0			—		17.6

Nine Months Ended September 30, 2012
Revenues	$	143.0	$	107.2		$	—		$	4.1	$	254.3
Segment Profit		5.1		3.0			—			1.0		9.1
Capital Expenditures		15.5		29.9			2.0			—		47.4
Segment Assets		377.9		394.1			5.8			6.2		784.0

Nine Months Ended September 30, 2011
Revenues	$	141.6	$	112.3		$	—		$	4.2	$	258.1
Segment Profit (Loss)		5.6		(0.4	)		(0.2	)		1.3		6.3
Capital Expenditures		16.5		23.9			2.3			—		42.7
Segment Assets		368.9		367.5			6.4			5.9		748.7

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 5 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2011 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2012.

Regulatory Matters

Fitchburg – Increase in Base Rates Approved – On August 1, 2011, the Massachusetts Department of Public Utilities (MDPU) issued an order approving increases of $3.3 million and $3.7 million in annual distribution revenues for Fitchburg’s electric and gas divisions, respectively. The MDPU also approved revenue decoupling mechanisms and a return on equity of 9.2% for both the electric and gas divisions of Fitchburg. The rate increase for Fitchburg’s electric division included the recovery of $11.4 million of

previously deferred emergency storm restoration costs associated with the December 2008 ice storm, which costs are to be amortized and recovered over seven (7) years without carrying costs. The order provides resolution to the open regulatory matters concerning the ratemaking treatment and cost recovery related to the December 2008 ice storm event.

Granite State – Increase in Base Rates Filed – Granite State has in place a FERC approved rate settlement agreement under which it is permitted to file incremental annual rate adjustment filings 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, $1.6 million has been expended and is being recovered in the 2011 approved 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 the FERC accepted the tariffs as proposed.

Unitil Energy – Increase in Base Rates Approved – On April 26, 2011, the New Hampshire Public Utilities Commission (NHPUC) approved a final rate settlement which makes permanent a temporary increase of $5.2 million in annual revenue effective July 1, 2010, and provided for an additional increase of $5.0 million in annual revenue effective May 1, 2011.

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

Unitil Energy filed its first step adjustment filing for $1.47 million on February 29, 2012 for implementation on May 1, 2012, which included rate increases to recover the increased spending for its vegetation management program and reliability enhancement program. The adjustment filing was approved by the NHPUC with minor modifications.

Northern Utilities – Increase in Base Rates Approved, Settlement Reached – In May 2011, Northern Utilities filed two separate rate cases with the NHPUC and Maine Public Utilities Commission (MPUC) requesting approval to increase its natural gas distribution base rates in New Hampshire and Maine, respectively. The Maine rate case was settled with the Office of Public Advocate and approved by the MPUC in November 2011. It provided for a $7.8 million permanent increase in annual distribution revenue for Northern Utilities’ Maine operations, effective January 1, 2012, and an additional permanent increase in annual distribution revenue of $0.85 million to recover the costs of 2011 cast iron pipe replacement capital spending effective May 1, 2012. The settlement precludes Northern Utilities from filing for a new base rate increase with an effective date prior to January 1, 2014.

On March 22, 2012, Northern Utilities, the Staff of the NHPUC and the Office of Consumer Advocate agreed to a settlement agreement providing for a $3.7 million permanent increase in annual revenues, effective May 1, 2012. The NHPUC issued an order approving the settlement agreement on April 24, 2012. Permanent rates were reconciled back to August 1, 2011.

Fitchburg – Electric Operations – On November 30, 2011, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing includes the reconciliation of costs and revenues for a number of surcharges and cost factors which are under individual review in separate proceedings before the MDPU, including the Pension/PBOP Adjustment, Residential Assistance Adjustment Factor, Net Metering Recovery Surcharge, Attorney General Consultant Expense Factor and Revenue Decoupling Adjustment Factor. The rates were approved effective January 1, 2012, subject to reconciliation pending investigation by the MDPU. This matter, as well as Fitchburg’s 2009 and 2010 annual reconciliation filings, was approved by Order on April 25, 2012.

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 $4.6 million of natural gas costs, plus interest. The SJC ordered instead, a $0.2 million refund, plus interest. The Company had previously recorded a pre-tax charge to earnings and recognized a Regulatory Liability of $4.9 million in the fourth quarter of 2009 based on the MDPU’s original order. As a result of the decision, the Regulatory Liability was adjusted and the Company recognized a credit of $4.7 million in the fourth quarter of 2011.

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 – Storm Cost Deferral Petition – On December 16, 2011, Fitchburg filed a request with the MDPU for authorization to defer, for future recovery in rates, the costs incurred to perform storm-related emergency repairs on its electric distribution system as a result of two recent storms, Tropical Storm Irene, which occurred on August 28, 2011, and a severe snow storm, which occurred on October 29-30, 2011. Fitchburg estimates that, 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.

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.

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. The increase would allow the Company 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. The NHPUC Staff audited the costs and filed a memorandum with the NHPUC recommending that the costs be recovered by the Company over a five year period with carrying costs of 4.52%, subject to a full reconciliation of all costs recovered. The Company accepted the Staff recommendation. On April 24, 2012, the NHPUC issued an order approving the recommendation of the Staff.

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 settlement, Unitil Energy reimbursed the customer $1.8 million plus $0.3 million of interest. The Company recognized a non-recurring charge of $0.4 million for distribution charges plus interest in 2011.

As a result of this metering issue, which was discovered in February 2011, certain other customers in the Company’s service areas were under-billed from October 2004 through January 2011 for 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 has been filed with the NHPUC. The settlement provides for recovery by the Company from its under-billed customers of approximately $1.4 million of the amount it had reimbursed the large customer. The settlement is pending approval before the NHPUC.

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.

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

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 fourth quarter of 2012.

Legal Proceedings

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

A putative class action complaint was filed against Fitchburg on January 7, 2009 in Worcester Superior Court in Worcester, Massachusetts, captioned Bellerman v. Fitchburg Gas and Electric Light Company. On April 1, 2009, an Amended Complaint was filed in Worcester Superior Court and served on Fitchburg. The Amended Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service areas in December, 2008. The Amended Complaint includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Superior Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. The Company anticipates that the court will decide whether the lawsuit is appropriate for class action treatment in late 2012. The Company continues to believe the suit is without merit and will defend itself vigorously.

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 5 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2011 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2012.

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations including laws and regulations related to pipeline safety. The Company believes it is in substantial compliance with applicable environmental, health and safety laws and regulations, and the Company believes that as of September 30, 2012, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increased stringent federal, state or local environmental health and safety laws and regulations, could result in increased compliance costs that we cannot currently quantify and that affect our operations.

Fitchburg is in the process of developing long-range plans for a feasible permanent remediation solution of a former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts, including alternatives for re-use of the site. Included in Environmental Obligations on the Company’s unaudited Consolidated Balance Sheet at September 30, 2012 are accrued liabilities totaling $12.0 million related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, without carrying costs. 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.

Also included in Environmental Obligations on the Company’s Consolidated Balance Sheet at September 30, 2012 are accrued liabilities totaling $2.5 million associated with Northern Utilities’ environmental remediation obligations for former MGP sites. In addition to the amounts noted above, there are $0.3 million of accrued liabilities in Other Current Liabilities on the Company’s Consolidated Balance Sheet at September 30, 2012 associated with Northern Utilities’ environmental remediation obligations for former MGP sites. Corresponding Regulatory Assets were recorded to reflect that the future recovery of these environmental remediation costs is expected based on regulatory precedent and established practices.

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. It is possible that other developments, such as increased stringent federal, state or local environmental health and safety laws and regulations, could result in increased compliance costs that we cannot currently quantify.

NOTE 8: INCOME TAXES

The Company bills its customers for 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 unaudited Consolidated Statements of Earnings.

The Company filed its tax returns for the year ended December 31, 2011 with the Internal Revenue Service (IRS) in September 2012 in which it recognized a net operating loss (NOL) of $12.4 million for income tax purposes principally due to bonus depreciation deductions allowed in the period. In total for tax periods ended before December 31, 2011, the Company has generated federal and state NOL carryforward assets for income tax purposes of $9.3 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, for periods ended before December 31, 2011, the Company had $1.5 million of Alternative Minimum Tax (AMT) credit carryforwards to offset future taxes payable indefinitely.

According to Internal Revenue Code rules, NOL refunds in excess of $2.0 million fall under the jurisdiction of the Joint Committee of Congress (Joint Committee) and are subject to review by the IRS and attorneys of the Joint Committee. As a result, the Company, on April 1, 2011, received notice that its federal income tax return filing for the year ended December 31, 2009 would be under examination by the IRS. The IRS has performed all fieldwork procedures and the Company and the IRS have entered into a settlement, pending approval of the Joint Committee, 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. The settlement has been submitted to the Joint Committee where approval is pending.

The Company evaluated its tax positions at December 31, 2011 and for the current interim reporting period ended September 30, 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 9: RETIREMENT BENEFIT OBLIGATIONS

The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation Supplemental Executive Retirement Plan (SERP) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2011 as filed with the SEC on February 1, 2012 for additional information regarding these plans.

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


	2012			2011
Used to Determine Plan Costs
Discount Rate		4.60	%		5.35	%
Rate of Compensation Increase		3.00	%		3.50	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		6.50	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2017			2017

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


	Pension Plan						PBOP Plan						SERP
Three Months Ended September 30,	2012			2011			2012			2011			2012		2011
Service Cost	$	807		$	735		$	517		$	479		$	72	$	71
Interest Cost		1,158			1,171			576			570			53		57
Expected Return on Plan Assets		(1,347	)		(1,210	)		(174	)		(204	)		—		—
Prior Service Cost Amortization		47			62			432			432			3		3
Transition Obligation Amortization		—			—			5			5			—		—
Actuarial Loss Amortization		904			783			32			—			16		19

Sub-total		1,569			1,541			1,388			1,282			144		150
Amounts Capitalized and Deferred		(703	)		(874	)		(571	)		(683	)		—		—

Net Periodic Benefit Cost Recognized	$	866		$	667		$	817		$	599		$	144	$	150


	Pension Plan						PBOP Plan						SERP
Nine Months Ended September 30,	2012			2011			2012			2011			2012		2011
Service Cost	$	2,420		$	2,206		$	1,550		$	1,438		$	217	$	214
Interest Cost		3,475			3,513			1,727			1,709			158		170
Expected Return on Plan Assets		(4,042	)		(3,630	)		(521	)		(613	)		—		—
Prior Service Cost Amortization		141			187			1,296			1,296			9		8
Transition Obligation Amortization		—			—			16			16			—		—
Actuarial Loss Amortization		2,712			2,349			97			—			47		59

Sub-total		4,706			4,625			4,165			3,846			431		451
Amounts Capitalized and Deferred		(1,984	)		(2,055	)		(1,551	)		(1,317	)		—		—

Net Periodic Benefit Cost Recognized	$	2,722		$	2,570		$	2,614		$	2,529		$	431	$	451

Employer Contributions

As of September 30, 2012, the Company had made $9.4 million of contributions to its Pension Plan in 2012. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2012 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension Plan costs.

As of September 30, 2012, the Company had made $2.2 million and $40,000 of contributions to the PBOP Plan and the SERP, respectively, in 2012. The Company presently anticipates contributing an additional $13,000 to the SERP in 2012.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Reference is made to the “Interest Rate Risk” and “Market Risk” sections of Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (above).

Item 4.

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, carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of September 30, 2012. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of September 30, 2012 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) are effective.

There have been no changes in the Company’s internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f) during the fiscal quarter covered by this Form 10-Q that have affected, or are reasonably likely to affect, the Company’s internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. Certain specific matters are discussed in Notes 6 and 7 to the Consolidated Financial Statements. In the opinion of Management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company’s financial position.

Item 1A.

Risk Factors

There have been no material changes to the risk factors disclosed in the Company’s Form 10-K for the year-ended December 31, 2011 as filed with the SEC on February 1, 2012.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Recent Sales of Unregistered Securities

There were no sales of unregistered equity securities by the Company during the fiscal quarter ended September 30, 2012.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table shows purchases made by or on behalf of the Company or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act)) of shares of the Company’s common stock during the fiscal quarter ended September 30, 2012.


	Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share ⁽¹⁾		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ⁽¹⁾		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs ⁽²⁾
7/1/12 – 7/31/12		—		—		—	$	194,520
8/1/12 – 8/31/12		—		—		—	$	194,520
9/1/12 – 9/30/12		228	$	26.27		228	$	188,531

Total		228				228

⁽¹⁾	All purchases were made pursuant to the Company’s 2012 Trading Plan (as defined below).

⁽²⁾

On March 22, 2012, the Company adopted a written trading plan under Rule 10b5-1 (the 2012 Trading Plan) under the Exchange Act to facilitate the repurchase of shares of its common stock on the open market in connection with its Employee Length of Service Awards and the stock portion of its Directors’ annual retainer. On March 26, 2012, the Company filed a Current Report on Form 8-K announcing that it had adopted the 2012 Trading Plan. The 2012 Trading Plan provides for the repurchase of up to $200,800 worth of shares of the Company’s common stock during its term. The 2012 Trading Plan became effective on March 22, 2012 and will terminate on March 22, 2013. The Company may suspend or terminate the 2012 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.

Item 5.

Other Information

On October 24, 2012, the Company issued a press release announcing its results of operations for the three- and nine-month periods ended September 30, 2012. The press release is furnished with this Quarterly Report on Form 10-Q as Exhibit 99.1.

Item 6.

Exhibits

(a) Exhibits


Exhibit No.	Description of Exhibit	Reference
10.1	Employment Agreement between Unitil Corporation and Robert G. Schoenberger	Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated September 19, 2012.

11	Computation in Support of Earnings Per Weighted Average Common Share	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 October 24, 2012 Announcing Earnings For the Quarter Ended September 30, 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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		UNITIL CORPORATION
		(Registrant)

Date: October 24, 2012		/s/ Mark H. Collin
		Mark H. Collin
		Chief Financial Officer

Date: October 24, 2012		/s/ Laurence M. Brock
		Laurence M. Brock
		Chief Accounting Officer

EXHIBIT INDEX


Exhibit No.	Description of Exhibit	Reference
10.1	Employment Agreement between Unitil Corporation and Robert G. Schoenberger	Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated September 19, 2012.

11	Computation in Support of Earnings Per Weighted Average Common Share	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 October 24, 2012 Announcing Earnings For the Quarter Ended September 30, 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