Edgar Filing: UNITIL CORP

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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 June 30, 2013

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 July 19, 2013
Common Stock, No par value		13,822,660 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended June 30, 2013

Table of Contents


		Page No.
Part I. Financial Information

Item 1.	Financial Statements - Unaudited

	Consolidated Statements of Earnings - Three and Six Months Ended June 30, 2013 and 2012	20

	Consolidated Balance Sheets, June 30, 2013, June 30, 2012 and December 31, 2012	21-22

	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2013 and 2012	23

	Notes to Consolidated Financial Statements	24-42

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	42

Item 4.	Controls and Procedures	42

Part II. Other Information

Item 1.	Legal Proceedings	42

Item 1A.	Risk Factors	42

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43

Item 3.	Defaults Upon Senior Securities	Inapplicable

Item 4.	Mine Safety Disclosures	Inapplicable

Item 5.	Other Information	43

Item 6.	Exhibits	44

Signatures		46

Exhibits		47

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 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 under multi-year energy brokering contracts; and

•

increased competition.

Many of these risks are beyond the Company’s control. Any forward-looking statements speak only as of the date of this report, and the Company undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for the Company to predict all of these factors, nor can the Company assess the impact of any such factor on its business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements.

PART I. 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 101,700 electric customers and 73,700 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 $625.4 million at June 30, 2013. 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

Rate Case Activity

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

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

Northern Utilities – Base Rates Filed – In April 2013, 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, the Company requested an increase of $5.2 million in gas distribution base revenue or approximately 9.4 percent over test year operating revenue. In Maine, the Company requested an increase of $4.6 million in gas distribution base revenue or approximately 6.3 percent over test year operating revenue. Both filings include proposed multi-year rate plans that include cost tracking mechanisms to recover future capital costs associated with Northern Utilities’ infrastructure replacements and safety and reliability improvements to the natural gas distribution system. Northern Utilities has been authorized to implement temporary rates in New Hampshire to collect a $2.5 million increase (annualized) in gas distribution revenue, effective July 1, 2013. These rate case filings are subject to regulatory review and approval with final rate orders expected in the first half of 2014.

Fitchburg – Electric Base Rates Filed – In July 2013, Fitchburg filed a rate case with the Massachusetts Department of Public Utilities (MDPU) requesting approval to increase its electric distribution rates. The Company requested an increase of $6.7 million in electric base revenue or approximately 11.5 percent over test year operating revenue. Included in the amount of this annual increase is approximately $2.1million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to two severe storms in 2011, Tropical Storm Irene and the October snowstorm, and Superstorm Sandy in 2012. The filing includes a proposed modified revenue decoupling mechanism by means of either a capital cost adjustment mechanism or a multi-year rate plan featuring a revenue cap index. The filing also includes a proposed major storm reserve fund to address the costs of future major storms by collecting $2.8 million per year through a reconciling storm recovery adjustment factor beginning January 1, 2015. The rate case filing is subject to regulatory review and approval with final rate orders expected in the second quarter of 2014.

Regulation

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

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

Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, Unitil’s customers, with the exception of Northern Utilities’ residential customers, have the opportunity to purchase their electricity or natural gas supplies from third-party energy supply vendors. Most residential customers and smaller commercial 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.

Fitchburg operates under a revenue decoupling mechanisms (RDM) for the electric and natural gas divisions in accordance with regulatory policy in Massachusetts. 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 has recognized, 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 11% 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.

RESULTS OF OPERATIONS

The following section of Management’s Discussion & Analysis compares the results of operations for each of the two fiscal periods ended June 30, 2013 and June 30, 2012 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 between years 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, including 360,000 shares of common stock pursuant to the underwriters’ option to purchase additional shares of common stock. 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 (Loss) Applicable to Common Shareholders was a net loss of ($0.1) million, or ($0.01) per share, for the second quarter of 2013, an improvement of $0.3 million, or $0.02 per share, compared to the second quarter of 2012. For the six months ended June 30, 2013, the Company reported Earnings of $10.7 million, a 24% increase over the same period in 2012. Earnings Per Share (EPS) for the six months ended June 30, 2013 were $0.78 compared to EPS of $0.74 for the same period of 2012. Results for the second quarter and year-to-date period were driven primarily by increases in natural gas and electric sales margins and lower borrowing costs, partially offset by higher utility operating costs.

Natural gas sales margins were $13.4 million and $43.9 million in the three and six months ended June 30, 2013, respectively, resulting in increases of $0.8 million and $4.0 million, respectively, compared to the same periods in 2012. Natural gas sales margins in the 2013 periods were positively affected by higher therm unit sales, a growing customer base and higher base distribution rates. Therm sales of natural gas increased 12.2% and 12.3% in the three and six month periods ended June 30, 2013, respectively, compared to the same periods in 2012, driven by the effect of colder winter weather in 2013 compared to 2012 coupled with the strong growth in the number of new residential as well as new commercial and industrial (C&I) customers. Based on weather data collected in the Company’s service areas, there were 15% more Heating Degree Days in the first six months of 2013 compared to the same period in 2012. Weather-normalized gas therm sales (excluding decoupled sales) in the three and six month periods ended June 30, 2013 are estimated to be up about 3% and 5%, respectively, compared to the same periods in 2012. Approximately 11% of the Company’s total therm sales of natural gas are decoupled and changes in these sales do not affect sales margins.

Electric sales margins were $17.9 million and $36.3 million in the three and six months ended June 30, 2013, respectively, resulting in increases of $0.4 million and $2.7 million, respectively, compared to the same periods in 2012. The increases in electric sales margins reflect higher electric kilowatt-hour (kWh) sales and higher base distribution rates. Electric sales margin in the six months ended June 30, 2013 also reflects higher recovery of $0.8 million of vegetation management and electric reliability enhancement expenditures as well as an increase of $0.4 million in the recovery of major storm restoration costs, which are offset by a corresponding increase in expenses, discussed below. Electric kWh sales increased 1.7% and 2.2% in the three and six month periods ended June 30, 2013, respectively, compared to the same periods in 2012, principally driven by the effect of colder winter weather in 2013 compared to 2012 and the addition of new residential and C&I customers. Weather-normalized kWh sales (excluding decoupled sales) in the three and six month periods ended June 30, 2013 are estimated to be essentially flat and 1% higher, respectively, compared to the same periods in 2012. Approximately 27% of total electric kWh sales are decoupled and changes in these sales do not affect sales margins.

Operation and Maintenance (O&M) expenses increased $0.5 million and $2.4 million for the three and six months ended June 30, 2013, respectively, compared to the same periods in 2012. The increase in the three month period of $0.5 million primarily reflects higher gas system maintenance costs. The increase in O&M expenses in the six month period of $2.4 million reflects higher vegetation management and electric reliability enhancement program costs of $0.8 million, higher gas and electric system maintenance costs of $0.8 million, higher professional fees and insurance claims expenses of $1.0 million and a decrease in all other O&M expenses, net of $0.2 million. The increase of $0.8 million in new spending on vegetation management and electric reliability enhancement programs in the first six months of 2013 compared to same period in 2012 is recovered through cost tracker rate mechanisms that result in a corresponding and offsetting increase in revenue and margin in the period.

Depreciation and Amortization expense increased $0.5 million and $1.6 million in the three and six months ended June 30, 2013, respectively, compared to the same periods in 2012. The increase in the three month period reflects higher depreciation on normal utility plant additions of $0.3 million, higher amortization of major storm restoration costs of $0.1 million and an increase in all other amortization of $0.1 million. The increase in the six month period reflects higher depreciation on normal utility plant additions of $0.9 million, higher amortization of major storm restoration costs of $0.4 million and an increase in all other amortization of $0.3 million.

Local Property and Other Taxes increased $0.1 million and $0.2 million in the three and six month periods ended June 30, 2013, respectively, compared to the same periods in 2012, reflecting higher local property taxes on higher levels of utility plant in service.

Federal and State Income Taxes increased by $1.0 million for the six months ended June 30, 2013 compared to the same period in 2012, due to higher pre-tax earnings in 2013 compared to 2012.

In the three months ended June 30, 2013, Interest Expense, Net was relatively unchanged compared to the same period in 2012. Interest Expense, Net decreased $0.3 million in the six months ended June 30, 2013 compared to the same period in 2012, reflecting lower average rates and lower short-term borrowings.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $1.4 million and $2.9 million in the three and six month periods ended June 30, 2013, respectively, resulting in increases of $0.1 million and $0.3 million, respectively, compared to the same three and six-month periods in 2012. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

In 2012, Unitil’s annual common dividend was $1.38, continuing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January 2013, March 2013 and June 2013 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 six months ended June 30, 2013 is presented below.

Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas increased 12.2% and 12.3% in the three and six month periods ended June 30, 2013, respectively, compared to the same periods in 2012. Sales to residential customers increased 21.5% and 16.2%, respectively, in the three and six months ended June 30, 2013 compared to the same periods in 2012. Sales to C&I customers increased 10.2% and 11.2%, respectively, in the three and six months ended June 30, 2013 compared to the same periods in 2012. The increase in gas therm sales in the Company’s utility service areas was driven by the effect of colder winter weather in 2013 compared to 2012 coupled with strong growth in the number of new residential and C&I customers. Based on weather data collected in the Company’s service areas, there were 15% more Heating Degree Days in the first six months of 2013 compared to the same period in 2012. Weather-normalized gas therm sales (excluding decoupled sales) in the three and six month periods ended June 30, 2013 are estimated to be up about 3% and 5%, respectively, compared to the same periods in 2012. Approximately 11% of the Company’s total therm sales of natural gas are decoupled and changes in these sales do not affect sales margins. Under revenue decoupling for Fitchburg, distribution revenues, which are included in sales margin, have been recognized in the Company’s Consolidated Statements of Earnings from August 1, 2011 forward, on established revenue targets and are no longer dependent on sales volumes.

The following table details total firm therm sales for the three and six months ended June 30, 2013 and 2012, by major customer class:


Therm Sales (millions)
	Three Months Ended June 30,									Six Months Ended June 30,
	2013		2012		Change		% Change			2013		2012		Change		% Change
Residential		7.9		6.5		1.4		21.5	%		27.3		23.5		3.8		16.2	%
Commercial / Industrial		33.4		30.3		3.1		10.2	%		95.3		85.7		9.6		11.2	%

Total		41.3		36.8		4.5		12.2	%		122.6		109.2		13.4		12.3	%

Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and Sales Margin for the three and six months ended June 30, 2013 and 2012:


Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2013		2012		$ Change			% Change⁽¹⁾			2013		2012		$ Change		% Change⁽¹⁾
Gas Operating Revenue:
Residential	$	9.4	$	9.6	$	(0.2	)		(0.9	%)	$	38.8	$	36.9	$	1.9		2.2	%
Commercial / Industrial		12.7		13.1		(0.4	)		(1.7	%)		54.1		50.0		4.1		4.7	%

Total Gas Operating Revenue	$	22.1	$	22.7	$	(0.6	)		(2.6	%)	$	92.9	$	86.9	$	6.0		6.9	%

Cost of Gas Sales:
Purchased Gas	$	8.1	$	9.4	$	(1.3	)		(5.7	%)	$	47.8	$	45.9	$	1.9		2.2	%
Conservation & Load Management		0.6		0.7		(0.1	)		(0.4	%)		1.2		1.1		0.1		0.1	%

Total Cost of Gas Sales	$	8.7	$	10.1	$	(1.4	)		(6.1	%)	$	49.0	$	47.0	$	2.0		2.3	%

Gas Sales Margin	$	13.4	$	12.6	$	0.8			3.5	%	$	43.9	$	39.9	$	4.0		4.6	%

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

Unitil 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. Unitil 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 $0.6 million in the second quarter of 2013 reflects lower costs of sales of $1.4 million, including lower Purchased Gas costs of $1.3 million and lower 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 sales margin of $0.8 million.

The increase in Total Gas Operating Revenues of $6.0 million in the six months ended June 30, 2013 reflects higher gas sales margin of $4.0 million and higher costs of sales of $2.0 million, including higher Purchased Gas costs of $1.9 million and higher C&LM costs of $0.1 million, which are tracked costs that are passed through directly to customers.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Unitil’s total electric kWh sales increased 1.7% and 2.2% in the three and six month periods ended June 30, 2013, respectively, compared to the same periods in 2012. Sales to residential customers increased 4.4% and 4.7%, respectively, in the three and six months ended June 30, 2013 compared to the same periods in 2012. Sales to C&I customers in the second quarter of 2013 were relatively unchanged with the same period in 2012 while increasing 0.4% in the six months ended June 30, 2013 compared to the same period in 2012. The increase in kWh sales in the Company’s utility service areas was driven by the effect of colder winter weather in 2013 compared to 2012 coupled with the addition of new residential and C&I customers. Based on weather data collected in the Company’s service areas, there were 15% more Heating Degree Days in the first six months of 2013 compared to the same period in 2012. Weather-normalized kWh sales (excluding decoupled sales) in the three and six month periods ended June 30, 2013 are estimated to be essentially flat and 1% higher, respectively, compared to the same periods in 2012. Approximately 27% of total electric kWh sales are decoupled and changes in these sales do not affect sales margins. Under revenue decoupling for Fitchburg, distribution revenues, which are included in sales margin, have been recognized in the Company’s Consolidated Statements of Earnings from August 1, 2011 forward, on established revenue targets and are no longer dependent on sales volumes.

The following table details total kWh sales for the three and six months ended June 30, 2013 and 2012 by major customer class:


kWh Sales (millions)
	Three Months Ended June 30,									Six Months Ended June 30,
	2013		2012		Change		% Change			2013		2012		Change		% Change
Residential		151.6		145.2		6.4		4.4	%		340.0		324.6		15.4		4.7	%
Commercial / Industrial		238.1		238.1		—		—			475.4		473.4		2.0		0.4	%

Total		389.7		383.3		6.4		1.7	%		815.4		798.0		17.4		2.2	%

Electric Operating Revenues and Sales Margin – The following table details total Electric Operating Revenues and Sales Margin for the three and six month periods ended June 30, 2013 and 2012:


Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2013		2012		$ Change			% Change⁽¹⁾			2013		2012		$ Change			% Change⁽¹⁾
Electric Operating Revenue:
Residential	$	22.5	$	23.4	$	(0.9	)		(2.0	%)	$	48.7	$	51.1	$	(2.4	)		(2.5	%)
Commercial / Industrial		20.4		21.4		(1.0	)		(2.2	%)		40.1		42.4		(2.3	)		(2.5	%)

Total Electric Operating Revenue	$	42.9	$	44.8	$	(1.9	)		(4.2	%)	$	88.8	$	93.5	$	(4.7	)		(5.0	%)

Cost of Electric Sales:
Purchased Electricity	$	23.4	$	25.7	$	(2.3	)		(5.1	%)	$	49.7	$	56.8	$	(7.1	)		(7.6	%)
Conservation & Load Management		1.6		1.6		—			—			2.8		3.1		(0.3	)		(0.3	%)

Total Cost of Electric Sales	$	25.0	$	27.3	$	(2.3	)		(5.1	%)	$	52.5	$	59.9	$	(7.4	)		(7.9	%)

Electric Sales Margin	$	17.9	$	17.5	$	0.4			0.9	%	$	36.3	$	33.6	$	2.7			2.9	%

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

Unitil 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. Unitil 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 $1.9 million in the second quarter of 2013 reflects higher electric sales margin of $0.4 million offset by lower cost of sales of $2.3 million, including lower Purchased Electricity costs of $2.3 million, which are tracked costs that are passed through directly to customers.

The decrease in Total Electric Operating Revenues of $4.7 million in the six months ended June 30, 2013 reflects higher electric sales margin of $2.7 million offset by lower cost of sales of $7.4 million, including lower Purchased Electricity costs of $7.1 million and lower C&LM costs of $0.3 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 six months ended June 30, 2013 and 2012:


Other Revenue (000’s)
	Three Months Ended June 30,									Six Months Ended June 30,
	2013		2012		$ Change		% Change			2013		2012		$ Change		% Change
Other	$	1.4	$	1.3	$	0.1		7.7	%	$	2.9	$	2.6	$	0.3		11.5	%

Total Other Revenue	$	1.4	$	1.3	$	0.1		7.7	%	$	2.9	$	2.6	$	0.3		11.5	%

Total Other Operating Revenue is comprised of revenues from the Company’s non-regulated energy brokering business, Usource. Usource’s revenues increased $0.1 million and $0.3 million in the three and six month periods ended June 30, 2013, respectively, compared to the same periods in 2012. 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 $1.3 million, or 13.8%, in the three month period ended June 30, 2013, respectively, compared to the same period in 2012, reflecting lower wholesale natural gas prices and an increase in the amount of natural gas purchased by customers directly from third-party suppliers, partially offset by an increase in therm sales of natural gas compared to the prior period. Purchased Gas increased $1.9 million, or 4.1%, in the six month period ended June 30, 2013, respectively, compared to the same period in 2012, reflecting higher therm sales of natural gas partially offset by lower wholesale natural gas prices and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. The Company recovers the approved 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 $2.3 million, or 9.0%, and $7.1 million, or 12.5%, in the three and six month periods ended June 30, 2013, respectively, compared to the same periods in 2012. The decreases reflect lower wholesale electricity prices partially offset by higher kWh sales. 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 gas and electric utility operating costs, and the operating cost of the Company’s corporate and other business activities. Total O&M expenses increased $0.5 million and $2.4 million for the three and six months ended June 30, 2013, respectively, compared to the same periods in 2012. The increase in the three month period of $0.5 million primarily reflects higher gas system maintenance costs. The increase in O&M expenses in the six month period of $2.4 million reflects higher vegetation management and electric reliability enhancement program costs of $0.8 million, higher gas and electric system maintenance costs of $0.8 million, higher professional fees and insurance claims expenses of $1.0 million and a decrease in all other O&M expenses, net of $0.2 million. The increase of $0.8 million in new spending on vegetation management and electric reliability enhancement programs in the first six months of 2013 compared to same period in 2012 is recovered through cost tracker rate mechanisms that result in a corresponding and offsetting increase in revenue and margin in the period.

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 second quarter of 2013, approximately 73% of these costs were related to electric operations and 27% to gas operations.

Total C&LM expenses decreased $0.1 million, or 4.4% and $0.2 million, or 4.8%, in the three and six month periods ended June 30, 2013 compared to the same periods in 2012. 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 $0.5 million, or 5.8%, and $1.6 million, or 9.4%, in the three and six months ended June 30, 2013, respectively, compared to the same periods in 2012. The increase in the three month period reflects higher depreciation on normal utility plant additions of $0.3 million, higher amortization of major storm restoration costs of $0.1 million and an increase in all other amortization of $0.1 million. The increase in the six month period reflects higher depreciation on normal utility plant additions of $0.9 million, higher amortization of major storm restoration costs of $0.4 million and an increase in all other amortization of $0.3 million.

Local Property and Other Taxes – Local Property and Other Taxes increased $0.1 million, or 2.9%, and $0.2 million, or 2.8%, in the three and six month periods ended June 30, 2013, respectively, compared to the same periods in 2012, 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 $1.0 million for the six months ended June 30, 2013 compared to the same period in 2012, due to higher pre-tax earnings in 2013 compared to 2012.

Other Non-Operating Expenses (Income)

Other Non-Operating Expenses increased $0.1 million each of the three and six month periods ended June 30, 2013 compared to the same periods in 2012.

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 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 June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Interest Expense
Long-term Debt	$	5.1		$	5.1		$	—		$	10.1		$	10.1		$	—
Short-term Debt		0.2			0.4			(0.2	)		0.6			0.9			(0.3	)
Regulatory Liabilities		0.1			0.1			—			0.1			0.1			—

Subtotal Interest Expense		5.4			5.6			(0.2	)		10.8			11.1			(0.3	)

Interest (Income)
Regulatory Assets		(0.6	)		(0.8	)		0.2			(1.3	)		(1.3	)		—
AFUDC⁽¹⁾ and Other		(0.2	)		(0.2	)		—			(0.3	)		(0.3	)		—

Subtotal Interest (Income)		(0.8	)		(1.0	)		0.2			(1.6	)		(1.6	)		—

Total Interest Expense, Net	$	4.6		$	4.6		$	—		$	9.2		$	9.5		$	(0.3	)

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

In the three months ended June 30, 2013, Interest Expense, Net was relatively unchanged compared to the same period in 2012. Interest Expense, Net decreased $0.3 million in the six months ended June 30, 2013 compared to the same period in 2012, lower average rates and lower short-term borrowings.

CAPITAL REQUIREMENTS

Sources of Capital

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities. The Company initially supplements internally generated funds through bank borrowings, as needed, under its unsecured short-term revolving credit facility. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term nature of its utility assets. Additionally, from time to time, the Company has accessed the public capital markets through public offerings of equity securities. The Company’s utility operations are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The amount, type and timing of any future financing will vary from year to year based on capital needs and maturity or redemptions of securities.

The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (the Cash Pool). The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool allows for an efficient exchange of cash among the Company and its subsidiaries. The interest 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 June 30, 2013, June 30, 2012 and December 31, 2012, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

Unitil has an unsecured revolving credit facility with a group of banks that extends to October 8, 2013. The borrowing limit under the credit facility is currently $60 million, which the Company believes will be sufficient until its expected renewal.

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as June 30, 2013, June 30, 2012 and December 31, 2012:


	Revolving Credit Facility (millions)
	June 30,				December 31,
	2013		2012		2012
Limit	$	60.0	$	115.0	$	60.0
Outstanding	$	24.5	$	5.0	$	49.4
Available	$	35.5	$	110.0	$	10.6

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. At June 30, 2013, June 30, 2012 and December 31, 2012, 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 June 30, 2013, there were approximately $13.5 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 $7.2 million, $8.0 million and $10.7 million outstanding at June 30, 2013, June 30, 2012 and December 31, 2012, respectively, related to these asset management agreements. The amount of natural gas inventory released in June 2013 and payable in July 2013 is $0.1 million and is recorded in Accounts Payable at June 30, 2013. There were no amounts of natural gas inventory released in June 2012 and payable in July 2012 that were recorded in Accounts Payable at June 30, 2012. The amount of natural gas inventory released in December 2012 and payable in January 2013 is $2.1 million and is recorded in Accounts Payable at December 31, 2012.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of June 30, 2013, the principal amount outstanding for the 8% Unitil Realty notes was $2.6 million. On December 15, 2008, the Company entered into a guarantee for the payment of principal, interest and other amounts payable on the $10.0 million Granite State notes due 2018. As of June 30, 2013, 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 six months ended June 30, 2013 compared to the same period in 2012.


	Six Months Ended June 30,
	2013		2012
Cash Provided by Operating Activities	$	70.3	$	52.9

Cash Provided by Operating Activities – Cash Provided by Operating Activities was $70.3 million in 2013, an increase of $17.4 million compared to 2012. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes, was $35.1 million in 2013 compared to $31.0 million in 2012, representing an increase of $4.1 million. Working capital changes in Current Assets and Liabilities resulted in a $22.8 million net source of cash in 2013 compared to a $18.9 million net source of cash in 2012, representing an increase of $3.9 million. Deferred Regulatory and Other Charges resulted in a $7.6 million source of cash in 2013 compared to a $4.1 million source of cash in 2012. All Other, net operating activities resulted in a source of cash of $4.8 million in 2013 compared to a use of cash of ($1.1) million in 2012.


	Six Months Ended June 30,
	2013			2012
Cash (Used in) Investing Activities	$	(37.0	)	$	(23.9	)

Cash (Used in) Investing Activities – Cash Used in Investing Activities was ($37.0) million for 2013 compared to ($23.9) million in 2012. The capital spending in both periods is representative of normal distribution utility capital expenditures reflecting normal electric and gas utility system additions.


	Six Months Ended June 30,
	2013			2012
Cash (Used in) Financing Activities	$	(36.0	)	$	(29.7	)

Cash (Used in) Financing Activities – Cash Used in Financing Activities was ($36.0) million in 2013 compared to ($29.7) million in 2012. In 2013, sources of cash came from common stock issued in connection with its Dividend Reinvestment and Stock Purchase Plan and its 401(k) Plan of $0.6 million. Uses of cash included net repayment of short-term debt of ($24.9) million, repayment of long-term debt of ($0.2) million, a decrease in exchange gas financing of ($1.6) million, regular quarterly dividend payments on common and preferred stock of ($9.5) million. All other financing activities resulted in a net use of cash of ($0.4) 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 January 30, 2013.

Regulatory Accounting – The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the MDPU, Unitil Energy is regulated by the NHPUC and Northern Utilities is regulated by the MPUC and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the Financial Accounting Standards Board Accounting Standards Codification (FASB Codification). In accordance with the FASB Codification, the Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

The FASB Codification specifies the economic effects that result from the cause and effect relationship of costs and revenues in the rate-regulated environment and how these effects are to be accounted for by a regulated enterprise. Revenues intended to cover some costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets.” If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities.”

The Company’s principal regulatory assets and liabilities are included on the Company’s Consolidated Balance Sheet and a summary of the Company’s Regulatory Assets and Liabilities is provided in Note 1 thereto. The Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements.

The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Utility Revenue Recognition – Utility revenues are recognized according to regulations and are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled 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 has recognized, 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 years ended December 31, 2012 and 2011, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $367,000 and $325,000, respectively, in the Net Periodic Benefit Cost for the Pension Plan. For the years ended December 31, 2012 and 2011, a 1.0% increase in the assumption of health care cost trend rates would have resulted in increases in the Net Periodic Benefit Cost for the PBOP Plan of $981,000 and $909,000, respectively. Similarly, a 1.0% decrease in the assumption of health care cost trend rates for those same time periods would have resulted in decreases in the Net Periodic Benefit Cost for the PBOP Plan of $756,000 and $705,000, respectively. (See Note 9 to the accompanying unaudited Consolidated Financial Statements).

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 June 30, 2013, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s 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 June 30, 2013, the Company and its subsidiaries had 477 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of June 30, 2013, a total of 156 employees of certain of the Company’s subsidiaries were represented by labor unions. There are 44 union employees of Fitchburg covered by a collective bargaining agreement (CBA) which expires on May 31, 2019; 31 union employees of Northern Utilities’ New Hampshire division covered by a separate CBA which expires on June 5, 2014; 38 union employees of Northern Utilities Maine division and Granite State covered by a separate CBA which expires on March 31, 2017; and 38 union employees of Unitil Energy covered by a separate CBA which expires on May 31, 2018. The agreements provide discrete salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.

In the fall of 2012, the Electric Systems Operators, which is a group of five employees of Unitil Service Corp., voted to be represented by a union. The company is currently in the process of negotiating the terms for a new collective bargaining agreement covering this group of five employees.

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 June 30, 2013 and June 30, 2012 were 1.98% and 2.02%, respectively. The average interest rates on the Company’s short-term borrowings for the six months ended June 30, 2013 and June 30, 2012 were 1.98% and 2.04%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2012 was 2.0%.

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 June 30,						Six Months Ended June 30,
	2013			2012			2013		2012
Operating Revenues
Gas	$	22.1		$	22.7		$	92.9	$	86.9
Electric		42.9			44.8			88.8		93.5
Other		1.4			1.3			2.9		2.6

Total Operating Revenues		66.4			68.8			184.6		183.0

Operating Expenses
Purchased Gas		8.1			9.4			47.8		45.9
Purchased Electricity		23.4			25.7			49.7		56.8
Operation and Maintenance		15.4			14.9			30.7		28.3
Conservation & Load Management		2.2			2.3			4.0		4.2
Depreciation and Amortization		9.2			8.7			18.6		17.0
Provisions (Benefit) for Taxes:
Local Property and Other		3.6			3.5			7.4		7.2
Federal and State Income		(0.1	)		—			6.3		5.3

Total Operating Expenses		61.8			64.5			164.5		164.7

Operating Income		4.6			4.3			20.1		18.3
Non-Operating Expenses		0.1			—			0.2		0.1

Income Before Interest Expense		4.5			4.3			19.9		18.2
Interest Expense, Net		4.6			4.6			9.2		9.5

Net Income (Loss)		(0.1	)		(0.3	)		10.7		8.7
Less: Dividends on Preferred Stock		—			0.1			—		0.1

Earnings (Loss) Applicable to Common Shareholders	$	(0.1	)	$	(0.4	)	$	10.7	$	8.6


Weighted Average Common Shares Outstanding – Basic (000’s)		13,768			12,331			13,758		11,624
Weighted Average Common Shares Outstanding – Diluted (000’s)		13,768			12,331			13,760		11,627
Earnings Per Common Share (Basic and Diluted)	$	(0.01	)	$	(0.03	)	$	0.78	$	0.74
Dividends Declared Per Share of Common Stock	$	0.345		$	0.345		$	1.035	$	1.035

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)


	June 30,				December 31,
	2013		2012		2012
ASSETS:

Utility Plant:
Electric	$	359.1	$	345.9	$	356.9
Gas		431.6		393.4		424.4
Common		31.5		30.6		30.9
Construction Work in Progress		40.4		24.9		21.0

Total Utility Plant		862.6		794.8		833.2
Less: Accumulated Depreciation		237.2		226.2		232.0

Net Utility Plant		625.4		568.6		601.2

Current Assets:
Cash		7.1		6.8		9.8
Accounts Receivable, net		40.8		33.2		47.7
Accrued Revenue		38.3		41.5		63.4
Exchange Gas Receivable		7.6		8.5		9.4
Gas Inventory		0.8		0.6		1.1
Materials and Supplies		5.4		4.1		4.1
Prepayments and Other		5.6		6.0		4.2

Total Current Assets		105.6		100.7		139.7

Noncurrent Assets:
Regulatory Assets		125.9		135.3		134.6
Other Noncurrent Assets		17.3		20.1		16.8

Total Noncurrent Assets		143.2		155.4		151.4

TOTAL ASSETS	$	874.2	$	824.7	$	892.3

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions)

(UNAUDITED)


	June 30,				December 31,
	2013		2012		2012
CAPITALIZATION AND LIABILITIES:

Capitalization:
Common Stock Equity	$	257.8	$	254.7	$	260.4
Preferred Stock		0.2		2.0		0.2
Long-Term Debt, Less Current Portion		287.0		287.6		287.3

Total Capitalization		545.0		544.3		547.9

Current Liabilities:
Long-Term Debt, Current Portion		0.6		0.5		0.5
Accounts Payable		21.7		17.4		32.7
Short-Term Debt		24.5		5.0		49.4
Energy Supply Contract Obligations		9.8		17.2		13.8
Current Deferred Income Taxes		3.1		3.7		13.4
Dividends Declared and Payable		4.8		4.8		—
Interest Payable		3.1		3.0		3.1
Regulatory Liabilities		13.3		8.0		6.8
Other Current Liabilities		9.7		10.8		11.4

Total Current Liabilities		90.6		70.4		131.1

Noncurrent Liabilities:
Energy Supply Contract Obligations		2.9		3.8		3.3
Noncurrent Deferred Income Taxes		54.4		48.1		38.7
Cost of Removal Obligations		54.7		48.6		51.4
Retirement Benefit Obligations		110.6		91.1		103.7
Environmental Obligations		13.8		14.5		13.8
Other Noncurrent Liabilities		2.2		3.9		2.4

Total Noncurrent Liabilities		238.6		210.0		213.3

TOTAL CAPITALIZATION AND LIABILITIES	$	874.2	$	824.7	$	892.3

(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)


	Six Months Ended June 30,
	2013			2012
Operating Activities:
Net Income	$	10.7		$	8.7
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		18.6			17.0
Deferred Tax Provision		5.8			5.3
Changes in Working Capital Items:
Accounts Receivable		6.9			11.9
Accrued Revenue		25.1			21.2
Regulatory Liabilities		6.5			(3.2	)
Exchange Gas Receivable		1.8			5.0
Accounts Payable		(11.0	)		(9.9	)
Other Changes in Working Capital Items		(6.5	)		(6.1	)
Deferred Regulatory and Other Charges		7.6			4.1
Other, net		4.8			(1.1	)

Cash Provided by Operating Activities		70.3			52.9

Investing Activities:
Property, Plant and Equipment Additions		(37.0	)		(23.9	)

Cash (Used in) Investing Activities		(37.0	)		(23.9	)

Financing Activities:
Repayment of Short-Term Debt		(24.9	)		(82.9	)
Repayment of Long-Term Debt		(0.2	)		(0.2	)
Net Decrease in Exchange Gas Financing		(1.6	)		(4.5	)
Dividends Paid		(9.5	)		(7.6	)
Proceeds from Issuance of Common Stock, net		0.6			66.0
Other, net		(0.4	)		(0.5	)

Cash (Used in) Financing Activities		(36.0	)		(29.7	)

Net Decrease in Cash		(2.7	)		(0.7	)
Cash at Beginning of Period		9.8			7.5

Cash at End of Period	$	7.1		$	6.8

Supplemental Cash Flow Information:
Interest Paid	$	10.4		$	10.8
Income Taxes Paid	$	0.8		$	0.6
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	1.8		$	1.3

(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 six months ended June 30, 2013 are not necessarily indicative of results to be expected for the year ending December 31, 2013. 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, 2012, as filed with the Securities and Exchange Commission (SEC) on January 30, 2013, for a description of the Company’s Basis of Presentation.

Regulatory Accounting – The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the Financial Accounting Standards Board (FASB) Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.


	June 30,				December 31,
Regulatory Assets consist of the following (millions)	2013		2012		2012
Energy Supply & Other Regulatory Tracker Mechanisms	$	19.3	$	30.4	$	41.0
Deferred Restructuring Costs		14.5		21.3		20.1
Retirement Benefit Obligations		62.5		55.1		62.5
Income Taxes		9.5		10.8		10.2
Environmental Obligations		16.7		16.9		16.8
Deferred Storm Charges		28.1		26.2		27.8
Other		6.9		9.8		8.1

Total Regulatory Assets	$	157.5	$	170.5	$	186.5
Less: Current Portion of Regulatory Assets⁽¹⁾		31.6		35.2		51.9

Regulatory Assets – noncurrent	$	125.9	$	135.3	$	134.6

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


	June 30,				December 31,
Regulatory Liabilities consist of the following (millions)	2013		2012		2012
Regulatory Tracker Mechanisms	$	13.3	$	8.0	$	6.8

Total Regulatory Liabilities	$	13.3	$	8.0	$	6.8

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Prior to June 30, 2013, certain regulatory tracker mechanisms which are currently recorded in Regulatory Liabilities had been recorded in Accrued Revenue and Other Current Liabilities on the Consolidated Balance Sheets. The above table shows the amounts recorded in Regulatory Liabilities subsequent to these reclassifications.

Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of June 30, 2013, June 30, 2012 and December 31, 2012.


	June 30,				December 31,
Accrued Revenue ($millions)	2013		2012		2012
Regulatory Assets – Current	$	31.6	$	35.2	$	51.9
Unbilled Revenues		6.7		6.3		11.5

Total Accrued Revenue	$	38.3	$	41.5	$	63.4

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At June 30, 2013, June 30, 2012 and December 31, 2012, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $54.7 million, $48.6 million, and $51.4 million, respectively. Prior to December 31, 2012, the cost of removal amounts had been recorded in Accumulated Depreciation on the Consolidated Balance Sheets.

Gas Inventory – The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of June 30, 2013, June 30, 2012 and December 31, 2012.


	June 30,				December 31,
Gas Inventory ($millions)	2013		2012		2012
Natural Gas	$	0.4	$	0.1	$	0.6
Propane		0.3		0.4		0.4
Liquefied Natural Gas & Other		0.1		0.1		0.1

Total Gas Inventory	$	0.8	$	0.6	$	1.1

Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. Prior to March 31, 2013, the exchange gas amounts had been recorded in Gas Inventory on the Company’s Consolidated Balance Sheets. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of June 30, 2013, June 30, 2012 and December 31, 2012.


	June 30,				December 31,
Exchange Gas Receivable ($millions)	2013		2012		2012
Northern Utilities	$	7.0	$	8.0	$	8.7
Fitchburg		0.6		0.5		0.7

Total Exchange Gas Receivable	$	7.6	$	8.5	$	9.4

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

Gas Inventory Obligation – Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations.

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

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


	June 30,				December 31,
Energy Supply Obligations ($millions)	2013		2012		2012
Current:
Exchange Gas Obligation	$	7.0	$	8.0	$	8.7
Power Supply Contract Divestitures		0.9		4.7		0.9
Renewable Energy Portfolio Standards		1.9		4.5		4.2

Total Energy Supply Obligations – Current	$	9.8	$	17.2	$	13.8
Long-Term:
Power Supply Contract Divestitures	$	2.9	$	3.8	$	3.3

Total Energy Supply Obligations	$	12.7	$	21.0	$	17.1

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 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 options and futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to the associated delivery month. Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through a regulatory commission approved recovery mechanism. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing

prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Purchased Gas when the gains and losses are passed through to customers in accordance with rate reconciling mechanisms.

As of June 30, 2013, June 30, 2012 and December 31, 2012, the Company had 1.8 billion, 1.8 billion and 1.9 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program.

The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. As discussed above, the change in fair value related to these derivatives is recorded initially as a regulatory asset or liability then reclassified into Purchased Gas in accordance with the recovery mechanism. The tables below include disclosure of the derivative assets and liabilities and the reclassifications from their corresponding regulatory liabilities and assets, respectively into Purchased Gas. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Other Current Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.

Liability Derivatives ($ millions)


Fair Value Amount of Derivative Liabilities (millions) Offset in Regulatory Assets, as of:
		Fair Value
Description	Balance Sheet Location	June 30, 2013		June 30, 2012		December 31, 2012
Derivative Liabilities
Natural Gas Futures Contracts	Other Current Liabilities	$	0.3	$	1.5	$	0.7

Natural Gas Futures Contracts	Other Noncurrent Liabilities		0.1		—		—

Total Derivative Liabilities		$	0.4	$	1.5	$	0.7


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	0.9	$	0.1	$	0.6	$	1.4
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings⁽¹⁾:
Purchased Gas	$	—	$	0.6	$	0.9	$	2.2

⁽¹⁾	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 June 30, 2013, June 30, 2012 and December 31, 2012, which are included in Accounts Receivable, net on the accompanying unaudited Consolidated Balance Sheets, were as follows:


	June 30,				December 31,
	2013		2012		2012
Allowance for Doubtful Accounts	$	2.4	$	2.9	$	1.9

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

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

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.

Reclassifications – Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. Most significant has been the reclassification of certain regulatory tracker mechanisms from Accrued Revenue and Other Current Liabilities to Regulatory Liabilities, the reclassification of cost of removal costs associated with asset retirements from Accumulated Depreciation to Cost of Removal Obligations, the reclassification of exchange gas amounts from Gas Inventory to Exchange Gas Receivable and the segregation of Deferred Income Taxes to current and noncurrent amounts on the Company’s Consolidated Balance Sheets, as discussed above in Regulatory Accounting, Utility Plant, Exchange Gas Receivable and Income Taxes, respectively.

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

NOTE 2 – DIVIDENDS DECLARED PER SHARE

Declaration

Date

Date Paid

(Payable)

Shareholder of

Record Date

Dividend

Amount

06/05/13

08/15/13

08/01/13

0.345

03/28/13

05/15/13

05/01/13

0.345

01/17/13

02/15/13

02/01/13

0.345

09/19/12

11/15/12

11/01/12

0.345

06/06/12

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

NOTE 3 – COMMON STOCK AND PREFERRED STOCK

Common Stock

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

The Company had 13,822,318, 13,758,805 and 13,780,601 of common shares outstanding at June 30, 2013, June 30, 2012 and December 31, 2012, respectively.

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

Dividend Reinvestment and Stock Purchase Plan – During the first six months of 2013, the Company sold 20,477 shares of its common stock, at an average price of $28.27 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) Plan resulting in net proceeds of approximately $579,000. 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 to receive awards under the Stock Plan, including awards of restricted shares (Restricted Shares), or of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

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

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

On February 4, 2013, 21,240 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of $564,134. There were 53,480 and 53,942 non-vested shares under the Stock Plan as of June 30, 2013 and 2012, respectively. The weighted average grant date fair value of these shares was $25.99 and $24.67, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $0.5 million and $1.0 million for the six months ended June 30, 2013 and 2012, respectively. At June 30, 2013, there was approximately $0.9 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.7 years. There were no forfeitures or cancellations under the Stock Plan during the six months ended June 30, 2013.

There were no Restricted Stock Units issued under the Stock Plan during the six months ended June 30, 2013. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of June 30, 2013, June 30, 2012 and December 31, 2012 is less than $0.1 million, zero and less than $0.1 million, respectively, representing the fair value of liabilities associated with the portion of fully vested Restricted Stock Units that will be settled in cash.

Preferred Stock

Details on preferred stock at June 30, 2013, June 30, 2012 and December 31, 2012 are shown below:


	June 30,				December 31,
	2013		2012		2012
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		—
8.00% Series, $100 Par Value		—		1.0		—

Total Preferred Stock	$	0.2	$	2.0	$	0.2

There were 2,250 shares of Unitil Energy’s 6.00% Series Preferred Stock outstanding at June 30, 2013, June 30, 2012 and December 31, 2012.

There were 7,823 shares of Fitchburg’s 5.125% Series Preferred Stock and 9,654 shares of Fitchburg’s 8.00% Series Preferred Stock outstanding at June 30, 2012. On December 1, 2012, Fitchburg redeemed and retired the two outstanding issues of its Redeemable, Cumulative Preferred Stock. The 8.00% Series was redeemed at par (aggregate par value of $965,400). The 5.125% Series was redeemed at par plus a premium of 1.28% (aggregate value of $792,313). Fitchburg used operating cash to effect this transaction.

There were less than $0.1 million of total dividends declared on Preferred Stock in the three and six months ended June 30, 2013, respectively, and $0.1 million of total dividends declared on Preferred Stock in the three and six months ended June 30, 2012, respectively.

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

Long-Term Debt

Details on long-term debt at June 30, 2013, June 30, 2012 and December 31, 2012 are shown below ($ Millions):


	June 30,				December 31,
	2013		2012		2012
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, Inc.:
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 State Gas Transmission, Inc.:
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		2.6		3.1		2.8

Total Long-Term Debt		287.6		288.1		287.8
Less: Current Portion		0.6		0.5		0.5

Total Long-term Debt, Less Current Portion	$	287.0	$	287.6	$	287.3

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)

June 30,

December 31,

2013

2012

Estimated Fair Value of Long-Term Debt

333.2

341.6

349.7

Credit Arrangements

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as of June 30, 2013, June 30, 2012 and December 31, 2012:


	Revolving Credit Facility (millions)
	June 30,				December 31,
	2013		2012		2012
Limit	$	60.0	$	115.0	$	60.0
Outstanding	$	24.5	$	5.0	$	49.4
Available	$	35.5	$	110.0	$	10.6

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 June 30, 2013, June 30, 2012 and December 31, 2012, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

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 June 30, 2013, there were approximately $13.5 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 six months ended June 30, 2013 and June 30, 2012 (Millions):


Three Months Ended June 30, 2013	Electric		Gas			Other		Non- Regulated		Total
Revenues	$	42.9	$	22.1		$	—	$	1.4	$	66.4
Segment Profit (Loss)		1.4		(2.3	)		0.6		0.2		(0.1	)
Capital Expenditures		3.4		17.6			1.6		—		22.6

Three Months Ended June 30, 2012
Revenues	$	44.8	$	22.7		$	—	$	1.3	$	68.8
Segment Profit (Loss)		1.4		(2.2	)		0.1		0.3		(0.4	)
Capital Expenditures		4.1		10.0			0.7		—		14.8

Six Months Ended June 30, 2013
Revenues	$	88.8	$	92.9		$	—	$	2.9	$	184.6
Segment Profit		3.4		6.0			0.7		0.6		10.7
Capital Expenditures		10.4		24.5			2.1		—		37.0
Segment Assets		405.7		456.8			5.3		6.4		874.2

Six Months Ended June 30, 2012
Revenues	$	93.5	$	86.9		$	—	$	2.6	$	183.0
Segment Profit (Loss)		2.6		5.4			—		0.6		8.6
Capital Expenditures		9.4		13.1			1.4		—		23.9
Segment Assets		398.3		416.1			3.3		7.0		824.7

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, 2012 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 30, 2013.

Regulatory Matters

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

Northern Utilities – Base Rates Filed – In April 2013, Northern Utilities filed two separate rate cases, with the NHPUC and MPUC, requesting approval to increase its natural gas distribution base rates. In New Hampshire, the Company requested an increase of $5.2 million in gas distribution base revenue or approximately 9.4 percent over test year operating revenue. In Maine, the Company requested an increase of $4.6 million in gas distribution base revenue or approximately 6.3 percent over test year operating revenue. Both filings include proposed multi-year rate plans that include cost tracking mechanisms to recover future capital costs associated with Northern Utilities’ infrastructure replacements and safety and reliability improvements to the natural gas distribution system. Northern Utilities has been authorized to implement temporary rates in New Hampshire to collect a $2.5 million increase (annualized) in gas distribution revenue, effective July 1, 2013. These rate case filings are subject to regulatory review and approval with final rate orders expected in the first half of 2014. Once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were established, July 1, 2013.

Fitchburg – Electric Base Rates Filed – In July 2013, Fitchburg filed a rate case with the MDPU requesting approval to increase its electric distribution rates. The Company requested an increase of $6.7 million in electric base revenue or approximately 11.5 percent over test year operating revenue. Included in the amount of this annual increase is approximately $2.1million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to two severe storms in 2011, Tropical Storm Irene and the October snowstorm, and Superstorm Sandy in 2012. The filing includes a proposed modified revenue decoupling mechanism by means of either a capital cost adjustment mechanism or a multi-year rate plan featuring a revenue cap index. The filing also includes a proposed major storm reserve fund to address the costs of future major storms by collecting $2.8 million per year through a reconciling storm recovery adjustment factor beginning January 1, 2015. The rate case filing is subject to regulatory review and approval with final rate orders expected in the second quarter of 2014.

Major Storms – Fitchburg and Unitil Energy

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

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

Unitil Energy – 2012 Storm Costs – On March 14, 2013, Unitil Energy filed a petition with the NHPUC to increase its storm recovery adjustment factor effective May 1, 2013, to recover approximately $2.3 million of costs to repair damage to its electrical system resulting from Superstorm Sandy. On April 25, 2013, the NHPUC approved the recovery of these costs over a five-year period with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, to be applied to the uncollected balance through the recovery period.

Fitchburg – Electric Operations – On November 30, 2012, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing also includes the reconciliation of costs and revenues for a number of other surcharges and cost factors which are subject to review and approval by the MDPU. All of the rates were approved effective January 1, 2013 for billing purposes, subject to reconciliation pending investigation by the MDPU. The reconciliation of costs and revenues for transition and transmission was approved on May 14, 2013. The reconciliation of costs and revenues for other surcharge and cost factors remains pending.

Fitchburg – Service Quality – On March 1, 2013, Fitchburg submitted its 2012 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. On March 29, 2013, the MDPU issued its order approving the 2011 Service Quality Report for Fitchburg’s gas division. The 2010-2012 Service Quality reports for Fitchburg’s electric division remain pending.

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

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

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

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

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

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

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

Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (Fitchburg), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December, 2008. The Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit would now proceed with only the twelve named plaintiffs seeking damages; however, the plaintiffs have appealed this decision to the Massachusetts Supreme Judicial Court. The Company continues to believe the suit is without merit and will continue to 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, 2012 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 30, 2013.

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company believes it is in compliance with applicable environmental and safety laws and regulations, and the Company believes that as of June 30, 2013, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

Fitchburg’s Manufactured Gas Plant Site – 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 Sheets at June 30, 2013 are accrued liabilities totaling $12.0 million related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site. A corresponding Regulatory Asset was recorded to reflect that the recovery of this environmental remediation cost is probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, without carrying costs.

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

Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, Lewiston and Scarborough sites. The site in Portland has been investigated and remedial activities are currently underway. Additionally, Northern Utilities has executed an Option Agreement with New Yard, LLC which establishes conditions for finalizing a long-term lease on the property to redevelop the Portland site as a boat repair facility with lease proceeds being used to offset remediation costs. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs until all remedial activities are completed.

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

Included in Environmental Obligations on the Company’s Consolidated Balance Sheet at June 30, 2013 are accrued liabilities totaling $1.8 million associated with Northern Utilities’ environmental remediation obligations for former MGP sites. In addition to the amounts noted above, there are $1.0 million of accrued liabilities in Other Current Liabilities on the Company’s Consolidated Balance Sheet at June 30, 2013 associated with Northern Utilities’ environmental remediation obligations for former MGP sites. Corresponding Regulatory Assets were recorded to reflect that the future recovery of these environmental remediation costs is expected based on regulatory precedent and established practices.

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.

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. As of December 31, 2012, the Company had recorded cumulative federal and state net operating loss (NOL) carryforward assets of $8.5 million to offset against taxes payable in future periods. If unused, the Company’s state NOL carryforward assets will begin to expire in 2019 and the federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2012, the Company had $1.5 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

The Company evaluated its tax positions at June 30, 2013 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, 2012 as filed with the SEC on January 30, 2013 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:


	2013			2012
Used to Determine Plan Costs
Discount Rate		4.00	%		4.60	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		6.50	%
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 June 30,	2013			2012			2013			2012			2013		2012
Service Cost	$	894		$	807		$	631		$	517		$	18	$	72
Interest Cost		1,141			1,158			612			576			60		53
Expected Return on Plan Assets		(1,489	)		(1,347	)		(180	)		(174	)		—		—
Prior Service Cost Amortization		52			47			425			432			3		3
Transition Obligation Amortization		—			—			—			5			—		—
Actuarial Loss Amortization		1,056			904			196			32			46		16

Sub-total		1,654			1,569			1,684			1,388			127		144
Amounts Capitalized and Deferred		(768	)		(725	)		(678	)		(560	)		—		—

Net Periodic Benefit Cost Recognized	$	886		$	844		$	1,006		$	828		$	127	$	144


	Pension Plan						PBOP Plan						SERP
Six Months Ended June 30,	2013			2012			2013			2012			2013		2012
Service Cost	$	1,787		$	1,613		$	1,262		$	1,033		$	36	$	144
Interest Cost		2,283			2,317			1,224			1,151			121		106
Expected Return on Plan Assets		(2,978	)		(2,695	)		(361	)		(348	)		—		—
Prior Service Cost Amortization		104			94			850			864			6		6
Transition Obligation Amortization		—			—			—			11			—		—
Actuarial Loss Amortization		2,115			1,808			393			65			92		32

Sub-total		3,311			3,137			3,368			2,776			255		288
Amounts Capitalized and Deferred		(1,384	)		(1,281	)		(1,447	)		(980	)		—		—

Net Periodic Benefit Cost Recognized	$	1,927		$	1,856		$	1,921		$	1,796		$	255	$	288

Employer Contributions

As of June 30, 2013, the Company had not made any contributions to its Pension and PBOP Plans in 2013. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2013 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of June 30, 2013, the Company had made $26,000 of contributions to the SERP Plan in 2013. The Company presently anticipates contributing an additional $27,000 to the SERP Plan in 2013.

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 June 30, 2013. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of June 30, 2013 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, 2012 as filed with the SEC on January 30, 2013.

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 June 30, 2013.

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 June 30, 2013.


	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⁾
4/1/13 – 4/30/13		—		—		—	$	91,800
5/1/13 – 5/31/13		—		—		—	$	91,800
6/1/13 – 6/30/13		279	$	28.55		279	$	83,834

Total		279				279

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

⁽²⁾

On March 28, 2013, the Company adopted a new written trading plan under Rule 10b5-1 (the 2013 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 common stock portion of its Directors’ annual retainer. On March 29, 2013, the Company filed a Current Report on Form 8-K announcing that it had adopted the 2013 Trading Plan. The 2013 Trading Plan provides for the repurchase of up to $91,800 worth of shares of the Company’s common stock during its term. The 2013 Trading Plan became effective on March 28, 2013 and will terminate on March 28, 2014. The Company may suspend or terminate the 2013 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 July 24, 2013, the Company issued a press release announcing its results of operations for the three- and six-month periods ended June 30, 2013. 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, dated June 5, 2013, 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 June 5, 2013

10.2	Unitil Corporation Management Incentive Plan	Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K dated June 5, 2013

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 July 24, 2013 Announcing Earnings For the Quarter Ended June 30, 2013.	Filed herewith

101.INS	XBRL Instance Document.	Filed herewith

101.SCH	XBRL Taxonomy Extension Schema Document.	Filed herewith

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.	Filed herewith



101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith

101.LAB	XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith

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: July 24, 2013		/s/ Mark H. Collin
		Mark H. Collin
		Chief Financial Officer

Date: July 24, 2013		/s/ Laurence M. Brock
		Laurence M. Brock
		Chief Accounting Officer

EXHIBIT INDEX


Exhibit No.	Description of Exhibit	Reference
10.1	Employment Agreement, dated June 5, 2013, 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 June 5, 2013

10.2	Unitil Corporation Management Incentive Plan	Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K dated June 5, 2013

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 July 24, 2013 Announcing Earnings For the Quarter Ended June 30, 2013.	Filed herewith

101.INS	XBRL Instance Document.	Filed herewith

101.SCH	XBRL Taxonomy Extension Schema Document.	Filed herewith

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.	Filed herewith



101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith

101.LAB	XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith