UNITIL CORP - Quarter Report: 2014 September (Form 10-Q)

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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 September 30, 2014

Commission File Number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

New Hampshire

02-0381573

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)


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

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

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

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

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

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

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


Class		Outstanding at October 20, 2014
Common Stock, No par value		13,907,610 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended September 30, 2014

Table of Contents


		Page No.
Part I. Financial Information

Item 1.	Financial Statements - Unaudited

	Consolidated Statements of Earnings - Three and Nine Months Ended September 30, 2014 and 2013	22

	Consolidated Balance Sheets, September 30, 2014, September 30, 2013 and December 31, 2013	23-24

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2014 and 2013	25

	Consolidated Statements of Changes in Common Stock Equity - Nine Months Ended September 30, 2014 and 2013	26

	Notes to Consolidated Financial Statements	27-50

Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations	3-21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50

Item 4.	Controls and Procedures	50

Part II. Other Information

Item 1.	Legal Proceedings	50

Item 1A.	Risk Factors	50

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51

Item 3.	Defaults Upon Senior Securities	Inapplicable

Item 4.	Mine Safety Disclosures	Inapplicable

Item 5.	Other Information	51

Item 6.	Exhibits	52

Signatures		54

Exhibits		55

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;

•

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 102,400 electric customers and 75,900 natural gas customers in their service territories.

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 $706.0 million at September 30, 2014. 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

Northern Utilities – Maine – On December 27, 2013, the Maine Public Utilities Commission (MPUC) approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine division, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed to implement a Targeted Infrastructure Replacement Adjustment (TIRA) rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects. The TIRA has an initial term of four years and covers targeted capital expenditures in 2013 through 2016. On February 28, 2014 Northern Utilities filed its first annual TIRA for rates effective May 1, 2014, seeking an annual increase in base distribution revenue of $1.3 million. This filing was approved by the MPUC on April 29, 2014. TIRA filings in future periods are projected to result in annual increases in revenue of approximately $1.0 million each year.

Northern Utilities – New Hampshire – On April 21, 2014, the New Hampshire Public Utilities Commission (NHPUC) approved a settlement agreement providing for an increase of $4.6 million in distribution base revenue and a return on equity of 9.5% for Northern Utilities’ New Hampshire division. In addition, the settlement agreement provides for additional step adjustments in 2014 and 2015 to recover the revenue requirements associated with investments in gas main extensions and infrastructure replacement projects. The 2014 step adjustment provides for an annual increase in revenue of $1.4 million effective May 1, 2014. The 2015 step adjustment is for a projected annual increase in revenue of approximately $1.4 million effective May 1, 2015. The newly-approved rates will be reconciled to the effective date temporary rates were established, July 1, 2013.

Unitil Energy – On April 26, 2011, the NHPUC approved a rate settlement that extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with a series of step adjustments to increase revenue in future years to support Unitil Energy’s continued capital improvements to its distribution system. On April 30, 2014 the NHPUC approved Unitil Energy’s third and final step increase of $1.5 million in annual revenue effective May 1, 2014.

Granite State – Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects. On June 27, 2014, Granite State filed to increase its rates and annual revenue by an additional $0.6 million beginning August 1, 2014. The FERC accepted this filing on June 18, 2014 and the new rates became effective August 1, 2014.

Fitchburg – Electric – In July 2013, Fitchburg filed a rate case with the Massachusetts Department of Public Utilities (MDPU) requesting an increase of $6.7 million in electric base revenue. A final rate order was issued by the MDPU on May 30, 2014 for rates effective June 1, 2014, approving a $5.6 million increase in electric base revenue, or 9.5% over 2012 test year operating revenue. The MDPU approved a 9.7% return on equity and a common equity ratio of 48%. As part of the increase in base revenue, the MDPU approved the recovery, over three years, of $5.0 million of previously deferred emergency storm repair costs incurred in 2011 as a result of Hurricane Irene and the October snow storm and in 2012 as a result of Superstorm Sandy. In addition, the MDPU approved an expanded storm resiliency vegetation management program at an annual funding amount of $0.5 million. The MDPU also approved the recovery of $0.9 million over a five-year period of past due amounts associated with hardship accounts that are protected from shut-off.

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 customers, however, continue to purchase such supplies through the distribution utilities under regulated energy rates and tariffs. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual approved costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

On August 1, 2011, the MDPU issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of Fitchburg. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of

electricity or natural gas sales. One of the primary purposes of decoupling is to eliminate the disincentive a utility otherwise has to encourage and promote energy conservation programs designed to reduce energy usage. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011 forward, distribution revenues for Fitchburg based on established revenue targets. These revenue targets may be adjusted as a result of rate cases that the Company files with the MDPU. As discussed above, Fitchburg’s electric division received a final rate order, issued by the MDPU on May 30, 2014, for rates effective June 1, 2014, approving a $5.6 million increase in electric base revenue.

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 MD&A compares the results of operations for each of the two fiscal periods ended September 30, 2014 and September 30, 2013 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, which are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

The Company’s results of operations reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the heating season as a result of higher sales of natural gas due to cold weather. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales but may also be affected by the weather conditions in both the winter and summer seasons. Also, as a result of recent rate cases, the Company’s natural gas sales margins are derived from a higher percentage of fixed billing components, including customer charges. Therefore, natural gas revenues and margin will be less affected by the seasonal nature of the natural gas business. In addition, as discussed above, approximately 27% and 11% of the Company’s total annual electric and natural gas sales volumes, respectively, are decoupled and changes in sales to existing customers do not affect sales margin.

Earnings Overview

The Company’s Net Income was $1.6 million, or $0.11 per share, for the third quarter of 2014, an increase of $1.0 million, or $0.07 per share, compared to the third quarter of 2013. For the nine months ended September 30, 2014, the Company reported Net Income of $15.3 million, a 35% increase over the same period in 2013. Earnings Per Share (EPS) for the nine months ended September 30, 2014 were $1.10 compared to EPS of $0.82 for the same period of 2013. The Company’s earnings for 2014 were driven by increases in natural gas and electric sales and margins.

Natural gas sales margins were $15.2 million and $68.0 million in the three and nine months ended September 30, 2014, respectively, resulting in increases of $2.8 million and $11.7 million, respectively, compared to the same periods in 2013. Natural gas sales margins in 2014 were positively affected by higher therm unit sales, a growing customer base and recently approved distribution rates. Therm sales of natural gas increased 11.2% in the first nine months of 2014 compared to 2013, driven by the colder winter weather and new customer additions in 2014 compared to 2013. Based on weather data collected in the Company’s service areas, there were 12% more Heating Degree Days in the first nine months of 2014 compared to 2013. Weather-normalized gas therm sales, excluding decoupled sales, in the first nine months of 2014 are estimated to be up 5.7% compared to 2013.

Electric sales margins were $22.6 million and $60.7 million in the three and nine months ended September 30, 2014, respectively, resulting in increases of $1.8 million and $3.6 million, respectively, compared to 2013. These increases reflect recently approved electric distribution rates. In the third quarter of 2014, electric kilowatt-hour (kWh) sales decreased 2.2% compared to the same period in 2013, driven by the effect of milder summer weather in 2014. Based on weather data collected in the Company’s service areas, there were 21% fewer Cooling Degree Days in the third quarter of 2014 compared to the same period in 2013. Electric kWh sales increased 0.4% in the first nine months of 2014 compared to the same period in 2013, driven by the addition of new customers and the effect of colder than normal winter weather earlier in 2014, partially offset by milder summer weather.

Operation and Maintenance (O&M) expenses increased $1.4 million and $3.5 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. The increase in the three month period reflects higher compensation and benefit costs of $0.7 million, higher utility operating costs of $0.6 million and higher all other operating costs, net of $0.1 million. The increase in O&M expenses in the nine month period reflects higher compensation and benefit costs of $2.4 million and higher utility operating costs of $1.1 million.

Depreciation and Amortization expense increased $1.0 million and $2.4 million in the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. The increase in the three month period reflects higher depreciation of $0.6 million on higher utility plant assets in service and higher amortization of $0.4 million of major storm restoration costs. The increase in the nine month period reflects higher depreciation of $1.6 million on higher utility plant assets in service, higher amortization of $0.9 million of major storm restoration costs and a decrease in all other amortization of $0.1 million.

Taxes Other Than Income Taxes increased $0.4 million and $1.6 million in the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013, primarily reflecting higher local property taxes on higher levels of utility plant assets in service.

Interest Expense, net increased $0.2 million and $1.5 million in the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013, reflecting lower interest income on regulatory assets.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $4.5 million for the nine months ended September 30, 2014, an increase of $0.1 million compared to the same period in 2013.

Also in the third quarter, the Unitil Corporation Board of Directors declared the regular quarterly dividend on the Company’s common stock of $0.345 per share. This quarterly dividend results in a current effective annual dividend rate of $1.38 per share representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

A more detailed discussion of the Company’s results of operations for the three and nine months ended September 30, 2014 is presented below.

Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas increased 2.5% and 11.2% in the three and nine month periods ended September 30, 2014, respectively, compared to the same periods in 2013. Sales to residential customers increased 8.0% and 15.8%, respectively, in the three and nine months ended September 30, 2014 compared to the same periods in 2013. Sales to Commercial and Industrial (C&I) customers increased 1.8% and 10.0%, respectively, in the three and nine months ended September 30, 2014 compared to the same periods in 2013. The increase in gas therm sales in the Company’s utility service territories was driven by the colder winter and spring weather in 2014 compared to 2013 coupled with strong growth in the number of new customers. The number of natural gas customers has increased by 2.5% over the past twelve months. Based on weather data collected in the Company’s service areas, there were 12% more Heating Degree Days in the first nine months of 2014 compared to the same period in 2013. Weather-normalized gas therm sales, excluding decoupled sales, are estimated to be up 2.2% and 5.7%, respectively, in the three and nine months ended September 30, 2014 compared to the same periods in 2013. As discussed above, sales margin derived from decoupled sales is not sensitive to changes in gas therm sales.

The following table details total firm therm sales for the three and nine months ended September 30, 2014 and 2013, by major customer class:


Therm Sales (millions)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2014		2013		Change		% Change			2014		2013		Change		% Change
Residential		2.7		2.5		0.2		8.0	%		34.5		29.8		4.7		15.8	%
Commercial / Industrial		22.3		21.9		0.4		1.8	%		128.9		117.2		11.7		10.0	%

Total		25.0		24.4		0.6		2.5	%		163.4		147.0		16.4		11.2	%

Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and Sales Margin for the three and nine months ended September 30, 2014 and 2013:


Gas Operating Revenues and Sales Margin ($ millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2014		2013		$ Change			% Change			2014		2013		$ Change		% Change
Gas Operating Revenue:
Residential	$	7.6	$	6.8	$	0.8			11.8	%	$	55.9	$	45.6	$	10.3		22.6	%
Commercial / Industrial		13.3		12.1		1.2			9.9	%		83.4		66.2		17.2		26.0	%

Total Gas Operating Revenue	$	20.9	$	18.9	$	2.0			10.6	%	$	139.3	$	111.8	$	27.5		24.6	%

Cost of Gas Sales	$	5.7	$	6.5	$	(0.8	)		(12.3	%)	$	71.3	$	55.5	$	15.8		28.5	%

Gas Sales Margin	$	15.2	$	12.4	$	2.8			22.6	%	$	68.0	$	56.3	$	11.7		20.8	%

The Company analyzes operating results using Gas Sales Margin, a non-GAAP measure. Gas Sales Margin is calculated as Total Gas Operating Revenue less Cost of Gas Sales. The Company believes Gas Sales Margin is a better measure to analyze profitability than Total Gas Operating Revenue because the approved cost of sales are tracked and reconciled to costs that are passed through directly to the customer, resulting in an equal and offsetting amount reflected in Total Gas Operating Revenue. Sales margin can be reconciled to Operating Income, a GAAP measure, by including Operation and Maintenance, Depreciation and Amortization and Taxes Other Than Income Taxes for each segment in the analysis.

Natural gas sales margins were $15.2 million and $68.0 million in the three and nine months ended September 30, 2014, respectively, resulting in increases of $2.8 million and $11.7 million, respectively, compared to the same periods in 2013. For the third quarter, approximately $2.4 million of the increase reflects higher natural gas distribution rates and $0.4 million of the increase reflects higher sales volumes due to customer growth. For the nine month period, approximately $8.6 million of the increase reflects higher natural gas distribution rates and $3.1 million of the increase reflects higher sales volumes related to the colder than normal weather and customer growth.

The increase in Total Gas Operating Revenues of $2.0 million in the third quarter of 2014 reflects higher gas sales margin of $2.8 million, partially offset by lower costs of gas sales of $0.8 million, which are tracked and reconciled to costs that are passed through directly to customers.

The increase in Total Gas Operating Revenues of $27.5 million in the first nine months of 2014 reflects higher gas sales margin of $11.7 million and higher costs of gas sales of $15.8 million, which are tracked and reconciled to costs that are passed through directly to customers.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Unitil’s total electric kWh sales decreased 2.2% and increased 0.4%, respectively in the three and nine month periods ended September 30, 2014 compared to the same periods in 2013. In the third quarter of 2014, sales to residential customers decreased

5.8% compared to the same period in 2013, driven by the effect of milder summer weather in 2014, while sales to C&I customers increased 0.4% for that same period. Based on weather data collected in the Company’s service areas, there were 21% fewer Cooling Degree Days in the third quarter of 2014 compared to the same period in 2013. For the nine months ended September 30, 2014, sales to residential customers decreased 0.5% and sales to C&I customers increased 1.1% compared to the same period in 2013, respectively. The decrease in sales to residential customers in the nine month period was driven by the effect of milder summer weather in 2014, partially offset by colder than normal winter weather earlier in 2014. The increase in sales to C&I customers in the nine month period was driven by the addition of new customers and the effect of colder than normal winter weather earlier in 2014. As discussed above, sales margin derived from decoupled sales is not sensitive to changes in electric kWh sales.

The following table details total kWh sales for the three and nine months ended September 30, 2014 and 2013 by major customer class:


kWh Sales (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2014		2013		Change			% Change			2014		2013		Change			% Change
Residential		183.6		195.0		(11.4	)		(5.8	%)		532.5		535.0		(2.5	)		(0.5	%)
Commercial / Industrial		271.8		270.8		1.0			0.4	%		754.3		746.2		8.1			1.1	%

Total		455.4		465.8		(10.4	)		(2.2	%)		1,286.8		1,281.2		5.6			0.4	%

Electric Operating Revenues and Sales Margin – The following table details total Electric Operating Revenues and Sales Margin for the three and nine month periods ended September 30, 2014 and 2013:


Electric Operating Revenues and Sales Margin ($ millions)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2014		2013		$ Change		% Change			2014		2013		$ Change		% Change
Electric Operating Revenue:
Residential	$	29.2	$	28.7	$	0.5		1.7	%	$	87.4	$	77.4	$	10.0		12.9	%
Commercial / Industrial		25.0		23.4		1.6		6.8	%		74.8		63.5		11.3		17.8	%

Total Electric Operating Revenue	$	54.2	$	52.1	$	2.1		4.0	%	$	162.2	$	140.9	$	21.3		15.1	%

Cost of Electric Sales	$	31.6	$	31.3	$	0.3		1.0	%	$	101.5	$	83.8	$	17.7		21.1	%

Electric Sales Margin	$	22.6	$	20.8	$	1.8		8.7	%	$	60.7	$	57.1	$	3.6		6.3	%

The Company analyzes operating results using Electric Sales Margin, a non-GAAP measure. Electric Sales Margin is calculated as Total Electric Operating Revenues less Cost of Electric Sales. The Company believes Electric Sales Margin is a better measure to analyze profitability than Total Electric Operating Revenues because the approved cost of sales are tracked and reconciled to costs that are passed through directly to the customer resulting in an equal and offsetting amount reflected in Total Electric Operating Revenues. Sales margin can be reconciled to Operating Income, a GAAP measure, by including Operation and Maintenance, Depreciation and Amortization and Taxes Other Than Income Taxes for each segment in the analysis.

Electric sales margins were $22.6 million and $60.7 million in the three and nine months ended September 30, 2014, respectively, resulting in increases of $1.8 million and $3.6 million, respectively, compared to the same periods in 2013. For the third quarter, approximately $2.2 million of the increase reflects higher electric distribution rates partially offset by lower sales margin of $0.4 million due to lower sales volumes related to the mild summer weather in 2014. For the nine month period, the increase primarily reflects higher electric distribution rates.

The increase in Total Electric Operating Revenues of $2.1 million in the third quarter of 2014 reflects higher electric sales margin of $1.8 million and higher costs of electric sales of $0.3 million, which are tracked and reconciled to costs that are passed through directly to customers.

The increase in Total Electric Operating Revenues of $21.3 million in the first nine months of 2014 reflects higher electric sales margin of $3.6 million and higher costs of electric sales of $17.7 million, which are tracked and reconciled to costs that are passed through directly to customers.

Operating Revenue – Other

The following table details total Other Revenue for the three and nine months ended September 30, 2014 and 2013:


Other Revenue ($ millions)
	Three Months Ended September 30,								Nine Months Ended September 30,
	2014		2013		$ Change		% Change		2014		2013		$ Change		% Change
Other	$	1.5	$	1.5	$	—		—	$	4.5	$	4.4	$	0.1		2.3	%

Total Other Revenue	$	1.5	$	1.5	$	—		—	$	4.5	$	4.4	$	0.1		2.3	%

Total Other Operating Revenue is comprised of revenues from the Company’s non-regulated energy brokering business, Usource. For the third quarter of 2014, Usource’s revenues were essentially unchanged compared to the same period in 2013. For the nine months ended September 30, 2014, Usource’s revenues increased $0.1 million compared to the same period in 2013. 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.

Operating Expenses

Cost of Gas Sales – Cost of Gas Sales includes the cost of natural gas purchased and manufactured to supply the Company’s total gas supply requirements and spending on energy efficiency programs. Cost of Gas Sales decreased $0.8 million, or 12.3%, and increased $15.8 million, or 28.5%, in the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. The decrease in the three month period reflects lower wholesale natural gas prices partially offset by higher sales of natural gas and increased spending on energy efficiency programs. The increase in the nine month period reflects higher

sales of natural gas, higher wholesale natural gas prices, and increased spending on energy efficiency programs, partially offset by an increase in the amount of natural gas purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Gas Sales in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

Cost of Electric Sales – Cost of Electric Sales includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs, and spending on energy efficiency programs. Cost of Electric Sales increased $0.3 million, or 1.0%, and $17.7 million, or 21.1%, in the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. The increase in the three month period reflects higher wholesale electricity prices, partially offset by lower kWh sales and an increase in the amount of electricity purchased by customers directly from third-party suppliers. The increase in the nine month period reflects higher wholesale electricity prices, higher kWh sales and increased spending on energy efficiency programs, partially offset by an increase in the amount of electricity purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost 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 $1.4 million, or 9.0%, and $3.5 million, or 7.6%, for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. The increase in the three month period reflects higher compensation and benefit costs of $0.7 million, higher utility operating costs of $0.6 million and higher all other operating costs, net of $0.1 million. The increase in O&M expenses in the nine month period reflects higher compensation and benefit costs of $2.4 million and higher utility operating costs of $1.1 million.

Depreciation and Amortization – Depreciation and Amortization expense increased $1.0 million, or 10.2%, and $2.4 million, or 8.3%, in the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. The increase in the three month period reflects higher depreciation of $0.6 million on higher utility plant assets in service and higher amortization of $0.4 million of major storm restoration costs. The increase in the nine month period reflects higher depreciation of $1.6 million on higher utility plant assets in service, higher amortization of $0.9 million of major storm restoration costs and a decrease in all other amortization of $0.1 million. The increase in major storm restoration cost amortization is currently recovered in electric rates.

Taxes Other Than Income Taxes – Taxes Other Than Income Taxes increased $0.4 million, or 10.5%, and $1.6 million, or 14.3%, in the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013, primarily reflecting higher local property taxes on higher levels of utility plant assets in service.

Other Expense, net – Other Expense, net was relatively unchanged in the three and nine months ended September 30, 2014 compared to the same periods in 2013.

Income Tax Expense – Federal and State Income Taxes increased by $0.6 million and $2.4 million for the three and nine months ended September 30, 2014 compared to the same periods in 2013, reflecting higher pre-tax earnings in 2014 compared to 2013.

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 September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
Interest Expense
Long-term Debt	$	5.0		$	5.1		$	(0.1	)	$	15.1		$	15.2		$	(0.1	)
Short-term Debt		0.3			0.3			—			0.9			0.9			—
Regulatory Liabilities		0.1			0.2			(0.1	)		0.4			0.4			—

Subtotal Interest Expense		5.4			5.6			(0.2	)		16.4			16.5			(0.1	)

Interest (Income)
Regulatory Assets		(0.2	)		(0.5	)		0.3			(0.5	)		(1.9	)		1.4
AFUDC⁽¹⁾ and Other		(0.2	)		(0.3	)		0.1			(0.4	)		(0.6	)		0.2

Subtotal Interest (Income)		(0.4	)		(0.8	)		0.4			(0.9	)		(2.5	)		1.6

Total Interest Expense, net	$	5.0		$	4.8		$	0.2		$	15.5		$	14.0		$	1.5

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

CAPITAL REQUIREMENTS

Sources of Capital

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities. The Company initially supplements internally generated funds through bank borrowings, as needed, under its unsecured short-term revolving credit facility. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term nature of its utility assets. Additionally, from time to time, the Company

has accessed the public capital markets through public offerings of equity securities. The Company’s utility operations are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The amount, type and timing of any future financing will vary from year to year based on capital needs and maturity or redemptions of securities.

On October 15, 2014, Northern Utilities completed a private placement of $50 million aggregate principal amount of 4.42% Senior Unsecured Notes due October 15, 2044 to institutional investors and repaid $42.3 million of short-term debt from the proceeds. The remainder of the proceeds will be used for general corporate purposes. As a result of this subsequent event, the Company reclassified $42.3 million of short-term debt to long-term debt on its Consolidated Balance Sheet as of September 30, 2014.

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 September 30, 2014, September 30, 2013 and December 31, 2013, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 and provides for a new borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.375%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of September 30, 2014, September 30, 2013 and December 31, 2013:


	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2014		2013		2013
Limit	$	120.0	$	60.0	$	120.0
Outstanding	$	43.7	$	43.6	$	60.2
Available	$	76.3	$	16.4	$	59.8

The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility

provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65% tested on a quarterly basis. At September 30, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 4.)

In April 2014, Unitil Service Corp. entered into an arrangement for the financing of the construction and installation of a customer information system, including software and equipment. The financing arrangement is structured as a capital lease obligation with maximum availability of $15 million. As of September 30, 2014, Unitil Service Corp. has received funding under this financing arrangement in the amount of $6.0 million, which was used to fund project costs.

The continued availability of various methods of financing, as well as the choice of a specific form of security for such financing, will depend on many factors, including, but not limited to: security market conditions; general economic climate; regulatory approvals; the ability to meet covenant issuance restrictions; the level of earnings, cash flows and financial position; and the competitive pricing offered by financing sources.

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of September 30, 2014, there were approximately $29.7 million of guarantees outstanding and the longest term guarantee extends through April 2015.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $13.6 million, $11.8 million and $12.5 million of natural gas storage inventory at September 30, 2014, September 30, 2013 and December 31, 2013, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2014 and payable in October 2014 is $0.2 million and is recorded in Accounts Payable at September 30, 2014. The were no amounts of natural gas inventory released in September 2013 and payable in October 2013 that were recorded in Accounts Payable at September 30, 2013. The amount of natural gas inventory released in December 2013 and payable in January 2014 was $2.7 million and was recorded in Accounts Payable at December 31, 2013.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of September 30, 2014, the principal amount outstanding for the 8% Unitil Realty notes was $1.9 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 September 30, 2014, the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

Off-Balance Sheet Arrangements

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

Cash Flows

Unitil’s utility operations, taken as a whole, are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The tables below summarize the major sources and uses of cash (in millions) for the nine months ended September 30, 2014 compared to the same period in 2013.


	Nine Months Ended September 30,
	2014		2013
Cash Provided by Operating Activities	$	82.6	$	84.1

Cash Provided by Operating Activities – Cash Provided by Operating Activities was $82.6 million in the nine months ended September 30, 2014, a decrease of $1.5 million compared to 2013.

Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes, was $54.7 million in 2014 compared to $46.1 million in 2013, representing an increase of $8.6 million. The increase in net income in the nine months ended September 30, 2014 compared to the same period in 2013 is primarily attributable to increases in natural gas and electric sales margins as a result of higher unit sales and base rate relief from recently completed base rate cases. The increase in depreciation and amortization in 2014 compared to 2013 reflects higher utility depreciation from higher net utility plant in service and higher amortization from major storm restoration costs. The increase in the deferred tax provision in 2014 compared to 2013 is due to higher tax depreciation and tax repair expense on capital additions partially offset by federal and state net operating loss carryforward assets.

Changes in working capital items resulted in a $23.6 million net source of cash in 2014 compared to a $24.0 million net source of cash in 2013, representing a decrease of $0.4 million. Uses of cash for Accounts Payable were higher by $7.6 million in 2014 compared to 2013 as a result of normal variations in payment patterns from year-to-year. All other changes in Current Assets and Liabilities, including increases in Interest Payable and Environmental Obligations, resulted in an increase in sources of cash of $7.2 million in 2014 compared to 2013.

Changes in Deferred Regulatory and Other Charges resulted in a $5.1 million source of cash in 2014 compared to a $14.0 million source of cash in 2013. The reduction in sources of cash from Deferred Regulatory and Other Charges in 2014 compared to 2013 is primarily due to the higher recovery in 2013 of stranded costs related to electric industry restructuring in Massachusetts. All Other, net operating activities resulted in a use of cash of ($0.8) million in 2014 compared to $0.0 million in 2013.


	Nine Months Ended September 30,
	2014			2013
Cash (Used in) Investing Activities	$	(60.7	)	$	(64.6	)

Cash (Used in) Investing Activities – Cash Used in Investing Activities was ($60.7) million in the nine months ended September 30, 2014 compared to ($64.6) million in 2013. The lower cash used in investing activities in the 2014 period is reflective of the timing of cash disbursements which is expected to increase during the year. The actual capital spending in both 2014 and 2013 is representative of distribution utility capital expenditures for electric and gas utility system additions. The Company’s projected capital spending range for 2014 is $91 million to $96 million.


	Nine Months Ended September 30,
	2014			2013
Cash (Used in) Financing Activities	$	(21.2	)	$	(17.0	)

Cash (Used in) Financing Activities – Cash Used in Financing Activities was ($21.2) million in the nine months ended September 30, 2014 compared to ($17.0) million in 2013. The higher cash used in financing activities in 2014 compared to 2013 is primarily a result of greater repayments of Short-Term Debt of $10.7 million offset by an increase in funding from Capital Lease Obligations of $6.2 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 29, 2014.

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 Regulatory 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 revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable customer rates.

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

through rate mechanisms. Also, as a result of the MDPU’s final rate order dated May 30, 2014, discussed above, the electric division of Fitchburg is authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

Retirement Benefit Obligations – The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan covering substantially all of its employees. The Company also sponsors an unfunded retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The FASB Codification requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a corresponding Regulatory Asset to recognize the future collection of these obligations in electric and gas rates.

The Company’s RBO and reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. The Company has made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. The Company’s RBO are affected by actual employee demographics, the level of contributions made to the plans, earnings on plan assets, and health care cost trends. Changes made to the provisions of these plans may also affect current and future costs. If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact on the Company’s financial statements. The discount rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For the years ended December 31, 2013 and 2012, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $431,000 and $367,000, respectively, in the Net Periodic Benefit Cost for the Pension Plan. For the years ended December 31, 2013 and 2012, a 1.0% increase in the assumption of health care cost trend rates would have resulted in increases in the Net Periodic Benefit Cost for the PBOP Plan of $1,169,000 and $981,000, respectively. Similarly, a 1.0% decrease in the assumption of health care cost trend rates for those same time periods would have resulted in decreases in the Net Periodic Benefit Cost for the PBOP Plan of $895,000 and $756,000, respectively. (See Note 9 to the accompanying Consolidated Financial Statements).

Income Taxes – The Company is subject to federal and state income taxes as well as various other business taxes. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s 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 unaudited Consolidated Financial Statements.

Commitments and Contingencies – The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of September 30, 2014, the Company is not aware of any material commitments or contingencies other than those disclosed in Note 6, Regulatory Matters and Note 7, Environmental Matters to the Company’s unaudited Consolidated Financial Statements below.

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

LABOR RELATIONS

As of September 30, 2014, the Company and its subsidiaries had 496 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of September 30, 2014, a total of 161 employees of certain of the Company’s subsidiaries were represented by labor unions. The following table details by subsidiary the employees covered by a collective bargaining agreement (CBA) as of September 30, 2014:


	Employees Covered		CBA Expiration
Fitchburg		45		05/31/2019
Northern Utilities NH Division		34		06/05/2017
Northern Utilities ME Division/Granite State		38		03/31/2017
Unitil Energy		39		03/31/2018
Unitil Service		5		05/31/2016

The CBAs provide discrete salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.

INTEREST RATE RISK

As discussed above, Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding was $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rates on the Company’s short-term borrowings for the three months ended September 30, 2014 and September 30, 2013 were 1.55% and 1.96%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 2014 and September 30, 2013 were 1.55% and 1.97%, respectively.

COMMODITY PRICE RISK

Although Unitil’s three distribution utilities are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for the reconciliation and collection of approved purchased electricity and 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.

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except per share data)

(UNAUDITED)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Operating Revenues
Gas	$	20.9	$	18.9	$	139.3	$	111.8
Electric		54.2		52.1		162.2		140.9
Other		1.5		1.5		4.5		4.4

Total Operating Revenues		76.6		72.5		306.0		257.1

Operating Expenses
Cost of Gas Sales		5.7		6.5		71.3		55.5
Cost of Electric Sales		31.6		31.3		101.5		83.8
Operation and Maintenance		16.9		15.5		49.3		45.8
Depreciation and Amortization		10.8		9.8		31.2		28.8
Taxes Other Than Income Taxes		4.2		3.8		12.8		11.2

Total Operating Expenses		69.2		66.9		266.1		225.1

Operating Income		7.4		5.6		39.9		32.0
Interest Expense, net		5.0		4.8		15.5		14.0
Other Expense, net		0.1		0.1		0.3		0.3

Income Before Income Taxes		2.3		0.7		24.1		17.7
Income Tax Expense		0.7		0.1		8.8		6.4


Net Income	$	1.6	$	0.6	$	15.3	$	11.3


Net Income Per Common Share (Basic and Diluted)	$	0.11	$	0.04	$	1.10	$	0.82
Weighted Average Common Shares Outstanding – (Basic and Diluted)		13.8		13.8		13.8		13.8
Dividends Declared Per Share of Common Stock	$	0.345	$	0.345	$	1.035	$	1.38

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)


	September 30,				December 31,
	2014		2013		2013
ASSETS:

Current Assets:
Cash and Cash Equivalents	$	10.1	$	12.3	$	9.4
Accounts Receivable, net		41.6		35.2		52.2
Accrued Revenue		31.4		40.2		56.6
Exchange Gas Receivable		14.5		12.8		10.8
Gas Inventory		1.0		1.2		1.2
Deferred Income Taxes		2.1		—		—
Materials and Supplies		6.6		5.3		5.0
Prepayments and Other		5.1		4.5		4.8

Total Current Assets		112.4		111.5		140.0

Utility Plant:
Gas		488.9		437.3		477.3
Electric		382.9		361.3		375.6
Common		32.4		31.5		31.6
Construction Work in Progress		54.2		58.2		24.6

Total Utility Plant		958.4		888.3		909.1
Less: Accumulated Depreciation		252.4		241.3		243.5

Net Utility Plant		706.0		647.0		665.6

Other Noncurrent Assets:
Regulatory Assets		85.3		120.9		100.1
Other Assets		12.8		15.8		14.9

Total Other Noncurrent Assets		98.1		136.7		115.0

TOTAL ASSETS	$	916.5	$	895.2	$	920.6

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions, except number of shares)

(UNAUDITED)


	September 30,				December 31,
	2014		2013		2013
LIABILITIES AND CAPITALIZATION:

Current Liabilities:
Accounts Payable	$	19.3	$	21.5	$	38.1
Short-Term Debt		1.4		43.6		60.2
Long-Term Debt, Current Portion		2.5		0.6		2.5
Energy Supply Obligations		18.1		15.4		14.4
Deferred Income Taxes		—		2.3		6.7
Dividends Declared and Payable		—		4.8		—
Environmental Obligations		5.3		1.1		1.0
Interest Payable		5.4		5.4		3.1
Regulatory Liabilities		13.0		11.4		9.7
Other Current Liabilities		11.0		9.4		9.0

Total Current Liabilities		76.0		115.5		144.7

Noncurrent Liabilities:
Deferred Income Taxes		88.3		55.4		73.2
Cost of Removal Obligations		63.2		56.7		57.3
Retirement Benefit Obligations		81.8		107.9		77.3
Capital Lease Obligations		6.5		0.3		0.2
Environmental Obligations		2.0		13.8		13.8
Other Noncurrent Liabilities		4.1		4.6		4.1

Total Noncurrent Liabilities		245.9		238.7		225.9

Capitalization:
Long-Term Debt, Less Current Portion		326.7		286.9		284.8
Stockholders’ Equity:
Common Equity (Outstanding 13,906,964, 13,831,624 and 13,841,400 Shares)		233.9		231.3		232.1
Retained Earnings		33.8		22.6		32.9

Total Common Stock Equity		267.7		253.9		265.0
Preferred Stock		0.2		0.2		0.2

Total Stockholders’ Equity		267.9		254.1		265.2

Total Capitalization		594.6		541.0		550.0

TOTAL LIABILITIES AND CAPITALIZATION	$	916.5	$	895.2	$	920.6

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)


	Nine Months Ended September 30,
	2014			2013
Operating Activities:
Net Income	$	15.3		$	11.3
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		31.2			28.8
Deferred Tax Provision		8.2			6.0
Changes in Working Capital Items:
Accounts Receivable		10.6			12.5
Accrued Revenue		25.2			23.2
Exchange Gas Receivable		(3.7	)		(3.4	)
Accounts Payable		(18.8	)		(11.2	)
Regulatory Liabilities		3.3			4.6
Other Changes in Working Capital Items		7.0			(1.7	)
Deferred Regulatory and Other Charges		5.1			14.0
Other, net		(0.8	)		—

Cash Provided by Operating Activities		82.6			84.1

Investing Activities:
Property, Plant and Equipment Additions		(60.7	)		(64.6	)

Cash (Used in) Investing Activities		(60.7	)		(64.6	)

Financing Activities:
Repayment of Short-Term Debt, net		(16.5	)		(5.8	)
Repayment of Long-Term Debt		(0.4	)		(0.3	)
Increase / (Decrease) in Capital Lease Obligations		5.6			(0.6	)
Net Decrease in Exchange Gas Financing		3.6			3.1
Dividends Paid		(14.4	)		(14.3	)
Proceeds from Issuance of Common Stock, net		0.9			0.9

Cash (Used in) Financing Activities		(21.2	)		(17.0	)

Net Increase in Cash and Cash Equivalents		0.7			2.5
Cash and Cash Equivalents at Beginning of Period		9.4			9.8

Cash and Cash Equivalents at End of Period	$	10.1		$	12.3

Supplemental Cash Flow Information:
Interest Paid	$	13.5		$	13.2
Income Taxes Paid	$	1.2		$	0.8
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	1.7		$	1.1

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(Millions, except number of shares)

(UNAUDITED)


	Common Equity		Retained Earnings			Total
Balance at January 1, 2014	$	232.1	$	32.9		$	265.0

Net Income				15.3			15.3
Dividends on Common Shares				(14.4	)		(14.4	)
Stock Compensation Plans		0.9					0.9
Issuance of 28,958 Common Shares		0.9					0.9

Balance at September 30, 2014	$	233.9	$	33.8		$	267.7


Balance at January 1, 2013	$	230.0	$	30.4		$	260.4

Net Income				11.3			11.3
Dividends on Common Shares				(19.1	)		(19.1	)
Stock Compensation Plans		0.4					0.4
Issuance of 29,783 Common Shares		0.9					0.9

Balance at September 30, 2013	$	231.3	$	22.6		$	253.9

(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.

The Company’s earnings are seasonal and are typically higher in the first and fourth quarters when customers use natural gas for heating purposes.

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 three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

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

Unitil also has three other wholly-owned subsidiaries: Unitil Service; Unitil Realty; and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to 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 and are of a normal and recurring nature. The results of operations for the three and nine months ended September 30, 2014 are not necessarily indicative of results to be expected for the year ending December 31, 2014. 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, 2013, as filed with the Securities and Exchange Commission (SEC) on January 29, 2014, for a description of the Company’s Basis of Presentation.

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


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

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

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

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

Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.

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

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 Deferred Income Taxes in Current and Noncurrent Liabilities on the Consolidated Balance Sheets based on the nature of the underlying timing item.

Cash and Cash Equivalents – Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator – New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations. As of September 30, 2014, September 30, 2013 and December 31, 2013, the Unitil subsidiaries had deposited $8.0 million, $8.8 million and $7.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. As of September 30, 2014, September 30, 2013 and December 31, 2013, there was $0, $0.7 million and $0, respectively, deposited for this purpose.

Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, as a result of the MDPU’s final rate order dated May 30, 2014, discussed below, the electric division of Fitchburg is authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. 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.

The Allowance for Doubtful Accounts as of September 30, 2014, September 30, 2013 and December 31, 2013, which are included in Accounts Receivable, net on the accompanying unaudited Consolidated Balance Sheets, were as follows:

September 30,

December 31,

Allowance for Doubtful Accounts ($ millions)

2014

2013

Allowance for Doubtful Accounts

2.1

2.5

1.6

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 September 30, 2014, September 30, 2013 and December 31, 2013.


	September 30,				December 31,
Accrued Revenue ($ millions)	2014		2013		2013
Regulatory Assets – Current	$	24.6	$	33.0	$	43.6
Unbilled Revenues		6.8		7.2		13.0

Total Accrued Revenue	$	31.4	$	40.2	$	56.6

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. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of September 30, 2014, September 30, 2013 and December 31, 2013.


	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2014		2013		2013
Northern Utilities	$	13.4	$	11.8	$	9.8
Fitchburg		1.1		1.0		1.0

Total Exchange Gas Receivable	$	14.5	$	12.8	$	10.8

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 September 30, 2014, September 30, 2013 and December 31, 2013.


	September 30,				December 31,
Gas Inventory ($ millions)	2014		2013		2013
Natural Gas	$	0.8	$	0.8	$	0.8
Propane		0.1		0.3		0.3
Liquefied Natural Gas & Other		0.1		0.1		0.1

Total Gas Inventory	$	1.0	$	1.2	$	1.2

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The 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 September 30, 2014, September 30, 2013 and December 31, 2013, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $63.2 million, $56.7 million, and $57.3 million, respectively. Included in Construction Work in Progress at September 30, 2014 is approximately $6.9 million related to the development of a new customer information system.

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 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, and which consist of the following:


	September 30,				December 31,
Regulatory Assets ($ millions)	2014		2013		2013
Energy Supply & Other Regulatory Tracker Mechanisms	$	17.6	$	20.9	$	32.5
Deferred Restructuring Costs		2.1		11.6		9.3
Retirement Benefit		42.2		62.7		42.6
Income Taxes		10.1		9.3		11.9
Environmental		10.6		16.1		16.1
Deferred Storm Charges		20.7		26.5		25.6
Other		6.6		6.8		5.7

Total Regulatory Assets	$	109.9	$	153.9	$	143.7
Less: Current Portion of Regulatory Assets⁽¹⁾		24.6		33.0		43.6

Regulatory Assets – noncurrent	$	85.3	$	120.9	$	100.1

⁽¹⁾

Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.


	September 30,				December 31,
Regulatory Liabilities ($ millions)	2014		2013		2013
Regulatory Tracker Mechanisms	$	13.0	$	11.4	$	9.7

Total Regulatory Liabilities	$	13.0	$	11.4	$	9.7

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.

Derivatives – The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that none of its energy supply contracts, other than the regulatory approved hedging program, described below, qualifies as a derivative instrument under the guidance set forth in the FASB Codification.

The Company has a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service. Prior to April 2013 Northern Utilities purchased natural gas futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to associated delivery months. Beginning in April 2013, the hedging program was redesigned and the Company began purchasing call option contracts on NYMEX natural gas futures contracts for future winter period months. As of September 30, 2014, all futures contracts purchased under the prior program design have been sold and the hedging portfolio now consists entirely of call option contracts.

Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas Adjustment Clause. 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 Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.

As of September 30, 2014, September 30, 2013 and December 31, 2013 the Company had 3.0 billion, 2.6 billion and 1.8 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.

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

include disclosure of the derivative assets and liabilities and the recognition of the charges from their corresponding regulatory liabilities and assets, respectively into Cost of Gas Sales. 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 Regulatory Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.


Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of:
		Fair Value
Description	Balance Sheet Location	September 30, 2014		September 30, 2013		December 31, 2013
Derivative Assets
Natural Gas Futures/ Options Contracts	Prepayments and Other	$	—	$	—	$	0.1
Natural Gas Futures/ Options Contracts	Other Assets		—		0.1		0.1

Total Derivative Assets		$	—	$	0.1	$	0.2

Derivative Liabilities
Natural Gas Futures/ Options Contracts	Other Current Liabilities	$	0.1	$	0.4	$	—
Natural Gas Futures/ Options Contracts	Other Noncurrent Liabilities		0.1		—		—

Total Derivative Liabilities		$	0.2	$	0.4	$	—


	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2014		2013		2014			2013
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures / Options Contracts	$	0.1	$	0.1	$	(0.4	)	$	0.7
Amount of Loss / (Gain) Reclassified into unaudited Consolidated Statements of Earnings⁽¹⁾:
Cost of Gas Sales	$	0.1	$	0.2	$	(0.8	)	$	1.1

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

Energy Supply Obligations – The following discussion and table summarize the nature and amounts of the items recorded as current Energy Supply Obligations and the noncurrent amount of Energy Supply Obligations which is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.


	September 30,				December 31,
Energy Supply Obligations ($ millions)	2014		2013		2013
Current:
Exchange Gas Obligation	$	13.4	$	11.8	$	9.8
Renewable Energy Portfolio Standards		4.1		2.7		3.7
Power Supply Contract Divestitures		0.6		0.9		0.9

Total Energy Supply Obligations – Current	$	18.1	$	15.4	$	14.4
Long-Term:
Power Supply Contract Divestitures	$	2.1	$	2.7	$	2.5

Total Energy Supply Obligations	$	20.2	$	18.1	$	16.9

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

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

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

Power Supply Contract Divestitures – As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the

implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. The obligations related to these divestitures are recorded in Energy Supply Obligations on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion).

Massachusetts Green Communities Act – In compliance with the Massachusetts Green Communities Act, discussed below in Note 6, Regulatory Matters, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The facility associated with one of these contracts has been constructed and is operating. The other contracts have been approved by the MDPU and are pending facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg recovers its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Recently Issued Pronouncements – On May 28, 2014, the FASB issued ASU 2014-09 which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The effective date of this pronouncement is for fiscal years beginning after December 15, 2016. The Company does not expect that the adoption of the new guidance will have a material impact on the Company’s Consolidated Financial Statements.

Other than ASU 2014-09, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.

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 unaudited consolidated financial statements. As discussed above in Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and below in Note 4 to the Company’s Consolidated Financial Statements, “Debt and Financing Arrangements”, on October 15, 2014, Northern Utilities completed a private placement of $50 million aggregate principal amount of 4.42% Senior Unsecured Notes due October 15, 2044 to institutional investors and repaid $42.3 million of short-term debt from the proceeds. As a result of this subsequent event, the Company reclassified $42.3 million of short-term debt to long-term debt on its Consolidated Balance Sheet as of September 30, 2014.

Reclassifications – Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. The Company has reclassified the funding of regulatory-approved major storm cost reserves from Operation and Maintenance expense to Depreciation and Amortization expense on the Company’s Consolidated Statements of Earnings. Also, energy efficiency program expenses, which were previously presented as Conservation & Load Management on the Company’s Consolidated Statements of Earnings are now included in Cost of Gas Sales and Cost of Electric Sales.

NOTE 2 – DIVIDENDS DECLARED PER SHARE


Declaration Date	Date Paid (Payable)	Shareholder of Record Date		Dividend Amount
10/21/14	11/28/14		11/14/14	$ 0.345
07/22/14	08/29/14		08/15/14	$ 0.345
04/22/14	05/29/14		05/15/14	$ 0.345
01/16/14	02/28/14		02/14/14	$ 0.345

09/18/13	11/15/13		11/01/13	$ 0.345
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

NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and nine months ended September 30, 2014 and September 30, 2013 and as of December 31, 2013 ($ millions):


	Gas			Electric		Non-Regulated		Other			Total
Three Months Ended September 30, 2014
Revenues	$	20.9		$	54.2	$	1.5	$	—		$	76.6
Segment Profit (Loss)		(1.5	)		2.9		0.2		—			1.6
Capital Expenditures		23.1			7.1		0.1		1.3			31.6

Three Months Ended September 30, 2013
Revenues	$	18.9		$	52.1	$	1.5	$	—		$	72.5
Segment Profit (Loss)		(1.9	)		2.6		0.3		(0.4	)		0.6
Capital Expenditures		20.1			6.1		—		1.4			27.6

Nine Months Ended September 30, 2014
Revenues	$	139.3		$	162.2	$	4.5	$	—		$	306.0
Segment Profit		9.3			5.2		0.6		0.2			15.3
Capital Expenditures		39.4			17.2		0.4		3.7			60.7
Segment Assets		505.6			392.1		6.4		12.4			916.5

Nine Months Ended September 30, 2013
Revenues	$	111.8		$	140.9	$	4.4	$	—		$	257.1
Segment Profit		4.1			6.0		0.9		0.3			11.3
Capital Expenditures		44.6			16.5		—		3.5			64.6
Segment Assets		474.2			409.6		6.5		4.9			895.2

As of December 31, 2013
Segment Assets	$	502.3		$	402.8	$	6.2	$	9.3		$	920.6

NOTE 4 – DEBT AND FINANCING ARRANGEMENTS

Long-Term Debt – On October 15, 2014, Northern Utilities completed a private placement of $50 million aggregate principal amount of 4.42% Senior Unsecured Notes due October 15, 2044 to institutional investors and repaid $42.3 million of short-term debt from the proceeds. The remainder of the proceeds will be used for general corporate purposes. As a result of this subsequent event, the Company reclassified $42.3 million of short-term debt to long-term debt on its Consolidated Balance Sheet as of September 30, 2014.

Details on long-term debt at September 30, 2014, September 30, 2013 and December 31, 2013 are shown below ($ millions):


	September 30,				December 31,
	2014		2013		2013
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		1.9		2.5		2.3

Total Long-Term Debt		286.9		287.5		287.3
Short-Term Debt Reclassifed to Long-Term Debt		42.3		—		—

Total Long-Term Debt After Reclassification		329.2		287.5		287.3
Less: Current Portion		2.5		0.6		2.5

Total Long-Term Debt, Less Current Portion	$	326.7	$	286.9	$	284.8

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

($ millions)

September 30,

December 31,

2014

2013

Estimated Fair Value of Long-Term Debt

378.2

326.7

327.3

Credit Arrangements

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of September 30, 2014, September 30, 2013 and December 31, 2013:


	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2014		2013		2013
Limit	$	120.0	$	60.0	$	120.0
Outstanding	$	43.7	$	43.6	$	60.2
Available	$	76.3	$	16.4	$	59.8

letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65% tested on a quarterly basis. At September 30, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

Guarantees

NOTE 5 – COMMON STOCK AND PREFERRED STOCK

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol, “UTL.”

The Company had 13,906,964, 13,831,624 and 13,841,400 shares of common stock outstanding at September 30, 2014, September 30, 2013 and December 31, 2013, respectively.

Dividend Reinvestment and Stock Purchase Plan – During the first nine months of 2014, the Company sold 28,958 shares of its common stock, at an average price of $32.20 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans

resulting in net proceeds of approximately $932,000. 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 Second Amended and Restated 2003 Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors to receive awards under the Stock Plan, including awards of restricted shares (Restricted Shares), or of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

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

Restricted Shares

Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a participant’s account. Awards may be grossed up to offset the participant’s tax obligations in connection with the award. For purposes of compensation expense, the Company uses the non-substantive vesting period approach, under which compensation expense is recognized immediately for awards granted to retirement-eligible employees or over the period from the grant date to the date retirement eligibility is achieved if that date is expected to occur during the normal vesting period. 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 January 31, 2014, 35,500 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.1 million. There were 67,334 and 53,480 non-vested shares under the Stock Plan as of September 30, 2014 and 2013, respectively. The weighted average grant date fair value of these shares was $28.51 and $25.99, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.3 million and $0.6 million for the nine months ended September 30, 2014 and 2013, respectively. At September 30, 2014, there was approximately $0.9 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.6 years. There were no forfeitures or cancellations under the Stock Plan during the nine months ended June 30, 2014.

Restricted Stock Units

Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of

the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity portion of Restricted Stock Units activity during the nine months ended September 30, 2014 in conjunction with the Stock Plan are presented in the following table:


Restricted Stock Units (Equity Portion)
	Units			Weighted Average Stock Price
Restricted Stock Units as of December 31, 2013		14,903		$	28.90
Restricted Stock Units Granted		—			—
Dividend Equivalents Earned		473		$	32.19
Restricted Stock Units Settled		(1,106	)	$	29.49

Restricted Stock Units as of September 30, 2014		14,270		$	28.96

There were 4,024 Restricted Stock Units (equity portion) outstanding as of September 30, 2013 with a weighted average stock price of $27.44. On October 1, 2014, there were 12,969 fully-vested Restricted Stock Units issued to members of the Company’s Board of Directors. The fair value of liabilities associated with the cash portion of fully-vested Restricted Stock Units is approximately $0.2 million, $0.1 million and 0.2 million as of September 30, 2014, September 30, 2013 and December 31, 2013, respectively, and is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.

Preferred Stock

There was $0.2 million, or 2,250 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2014, September 30, 2013 and December 31, 2013. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three and nine month periods ended September 30, 2014 and September 30, 2013, respectively.

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2013 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 29, 2014.

Regulatory Matters

Northern Utilities – Base Rates – Maine – On December 27, 2013, the Maine Public Utilities Commission (MPUC) approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine division, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed to implement a Targeted Infrastructure Replacement Adjustment (TIRA) rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects. The TIRA has an initial term of four years, and covers targeted capital expenditures in 2013 through 2016. The settlement agreement also provides for Earning Sharing where Northern would be allowed to retain all earnings up to a return of 10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement continues and revises the service quality plan

(SQP) that Northern Utilities has been operating under since 2004 and established in Docket No. 2002-140. The revised SQP consists of seven metrics with an appurtenant administrative penalty for failure to meet any of the seven metrics. The settlement agreement further provides that Northern Utilities will be subject to a maximum annual penalty of $500,000 if it fails to meet any of the baseline performance targets under the revised SQP. On February 28, 2014 Northern Utilities filed its first annual TIRA for rates effective May 1, 2014, seeking an annual increase in base distribution revenue of $1.3 million. This filing was approved by the MPUC on April 29, 2014. TIRA filings in future periods are projected to result in annual increases in revenue of approximately $1.0 million each year.

Northern Utilities – Base Rates – New Hampshire – On April 21, 2014, the NHPUC approved a settlement agreement providing for an increase of $4.6 million in distribution base revenue and a return on equity of 9.5% for Northern Utilities’ New Hampshire division. The settlement agreement provides for additional step adjustments in 2014 and 2015 to recover the revenue requirements associated with investments in gas mains extensions and infrastructure replacement projects. The 2014 step adjustment provides for an annual increase in revenue of $1.4 million effective May 1, 2014. The 2015 step adjustment is for a projected annual increase in revenue of approximately $1.4 million effective May 1, 2015. The settlement agreement also provides for Earning Sharing where Northern Utilities would be allowed to retain all earnings up to a return of 10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement provides that the Company’s next filing of a distribution base rate case is to be based on an historic test year of no earlier than twelve months ending December 31, 2016. The newly-approved rates have been reconciled to the effective date temporary rates were established, July 1, 2013.

Unitil Energy – Base Rates – On April 26, 2011, the NHPUC approved a rate settlement that extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with a series of step adjustments to increase revenue in future years to support Unitil Energy’s continued capital improvements to its distribution system. On April 30, 2014 the NHPUC approved Unitil Energy’s third and final step increase of $1.5 million in annual revenue effective May 1, 2014.

Granite State – Base Rates – Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects. On June 27, 2014, Granite State filed to increase its rates and annual revenue by an additional $0.6 million beginning August 1, 2014. With this filing, Granite State has reached the settlement agreement cost cap. The FERC accepted this filing on June 18, 2014 and the new rates became effective August 1, 2014.

Fitchburg – Electric Base Rates – In July 2013, Fitchburg filed a rate case with the MDPU requesting an increase of $6.7 million in electric base revenue. A final rate order was issued by the MDPU on May 30, 2014 for rates effective June 1, 2014, approving a $5.6 million increase in electric base revenue, or 9.5% over 2012 test year operating revenue. The MDPU approved a 9.7% return on equity and a common equity ratio of 48%. As part of the increase in base revenue, the MDPU approved the recovery, over three years, of $5.0 million of previously deferred emergency storm repair costs incurred in 2011 as a result of Hurricane Irene and the October snow storm and in 2012 as a result of Superstorm Sandy. In addition, the MDPU approved an expanded storm resiliency vegetation management program at an annual funding amount of $0.5 million. The MDPU also approved the recovery of $0.9 million over a five-year period of past due amounts associated with hardship accounts that are protected from shut-off. The impact of the rate order on previously capitalized or deferred items was not material.

Major Storms – Fitchburg and Unitil Energy

Fitchburg – 2011 Storm Cost Deferral and 2012 Storm Costs – As part of its May 30, 2014 order approving a base rate increase for Fitchburg, the MDPU approved the recovery over three years, without carrying charges, of $5.0 million of costs of repair for damage due to severe storms, including previously deferred costs incurred in 2011, as well as costs incurred in 2012 as a result of Superstorm Sandy.

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

Northern Utilities – Other – On September 12, 2014, Northern Utilities purchased a property for its new Maine Gas Distribution Operations Center (DOC). The new property includes an existing building and is located at 400 Riverside Industrial Parkway in Portland, Maine. In addition, on September 19, 2014, Northern Utilities sold its existing DOC facility located at 1075 Forest Avenue in Portland, Maine. The MPUC approved the sale of Northern Utilities’ existing DOC facility. The approval to sell was contingent upon completion of the acquisition of the new DOC property. The new DOC facility was needed due space limitations at the existing DOC. In recent years the Company’s gas expansion initiative and the work associated with it resulted in staff, company vehicles, and material storage additions to a facility that could not adequately handle these additions. The new DOC facility is currently undergoing renovations and the Company plans to occupy the new DOC in 2015. Until the Company moves into the new DOC facility, it is leasing its previous DOC facility from the new owner under a lease that can be cancelled by the Company with a 30 day notice at any time.

Fitchburg – Electric Operations – On November 15, 2013, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing also includes the reconciliation of costs and revenues for a number of other surcharges and cost factors which are subject to review and approval by the MDPU. Many of the surcharges and cost factors were redesigned based on cost-based rate design in compliance with a MDPU order in its Investigation into Cost-Based Rate Design for Reconciliation Factors, which resulted from the “Act Relative to Competitively Priced Electricity in the Commonwealth”, signed into law by the Governor of Massachusetts on August 3, 2012. All of the rates were approved effective January 1, 2014 for billing purposes, subject to reconciliation pending investigation by the MDPU. On June 4, 2014, the MDPU issued a final order approving Fitchburg’s annual reconciliation filing. Other cost factors are pending final approval.

Fitchburg – Gas Operations – On June 26, 2014, the Governor of Massachusetts signed into law a gas leak bill providing for the following, among other items: amends MDPU’s ability to fine gas companies for violations of gas pipeline safety rules consistent with federal law; establishes a uniform natural gas leak classification standard for the Commonwealth; provides that the MDPU investigate new programs and policies to facilitate customer conversions to natural gas; and establishes an infrastructure replacement program to address aging natural gas pipeline infrastructure. It is expected the MDPU will open a proceeding to address and implement changes resulting from this new law in the near future.

Fitchburg – Service Quality – On March 1, 2014, Fitchburg submitted its 2013 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 its gas division. The electric division met or exceeded all metric benchmarks except for two measures relating to the performance of certain individual distribution circuits as compared to the performance of the system as a whole. As a result of penalty offsets earned in six metrics where company performance exceeded the benchmark measure, however, no penalties are due.

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 order invited comments on a variety of topics related to service quality. After review of all the comments and discovery responses, on July 11, 2014, the MDPU issued an order containing proposed revisions to their Service Quality Guidelines. The MDPU proposes several changes to its Service Quality standards. The changes apply in various ways to the different metrics but, in sum, they involve three interrelated purposes: (1) increasing the level of performance required by companies through new approaches for calculating penalty thresholds and the elimination of offsets; (2) establishing statewide standards applicable to all companies; and (3) updating the standards to eliminate unnecessary or outdated metrics and adding new metrics to align company incentives with the MDPU’s policy objectives. Fitchburg, along with other Massachusetts utility companies, has submitted comments critical of several aspects of the proposed changes. Technical sessions to discuss the changes are to be held by the MDPU in mid-October. A final order in this investigation is expected by the end of the year.

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 Fitchburg’s rate cases in 2006 (gas) and 2007 (electric) satisfied the requirement for a hearing ordered by the SJC. The MDPU opened a docket to address the amounts collected by Fitchburg between the time the MDPU first approved dollar for dollar collection of the Fitchburg’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 December 23, 2013 the MDPU opened an investigation into Modernization of the Electric Grid. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices” and all related objectives. On June 12, 2014 the MDPU issued a further order as a result of its investigation. It sets forth a requirement that each electric distribution company submit a ten-year strategic grid modernization plan (GMP) within nine months of the issuance of a Final Order in related, but still ongoing, MDPU proceedings. As part of the GMP, each company must include a five-year short-term investment plan (STIP), which must include an approach to achieving advanced metering functionality within five years of the Department’s approval of the GMP. The filing of a GMP will

be a recurring obligation and must be updated as part of subsequent base distribution rate cases, which by statute must occur no less often than every five years. Capital investments contained in the STIP are eligible for pre-authorization, meaning that the MDPU will not revisit in later filings whether the company should have proceeded with these investments. Also on June 12, 2014, the MPDU issued an order setting forth its initial policy with respect to time varying rates, finding that the provision of basic energy service should be designed as time varying rates for all rate classes following the deployment of advanced metering functionality. This initial determination may be subject to modification upon the receipt of comments by interested parties. The MDPU also proposes to address in separate proceedings (1) cybersecurity, privacy, and access to meter data, and (2) electric vehicles. These matters remain pending.

Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (Fitchburg), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December, 2008. The Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit would now proceed with only the twelve named plaintiffs seeking damages; however, the plaintiffs have appealed this decision to the Massachusetts Supreme Judicial Court (the “SJC”). The SJC accepted the matter for review, briefs have been submitted and oral arguments have been held. The decision of the SJC is pending. The Town of Lunenburg has also filed a separate action in the Court arising out of the December 2008 ice storm. The parties to this action have agreed to put this matter on hold pending the decision of the SJC in Bellermann. The Company continues to believe these suits are without merit and will continue to defend itself vigorously.

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2013 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 29, 2014.

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company believes it is in material compliance with applicable environmental and safety laws and regulations, and the Company believes that as of September 30, 2014, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

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

Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, Lewiston and Scarborough sites. The site in Portland has been investigated and remedial activities are ongoing with the most recent phase completed in December 2013. Final remediation activities in Portland are scheduled to occur in 2015. In May 2014, the State of Maine completed its taking of the site via eminent domain for the expansion of the adjacent marine terminal. As a result of the outcome of negotiations with the State, future operation, maintenance and remedial costs have been accrued, to ensure that applicable remedial activities are completed. Additionally, as a result of the eminent domain taking by the State of Maine, a long-term lease on the property previously entered into by Northern Utilities and New Yard LLC in 2013, to redevelop the Portland site as a possible boat repair facility was terminated.

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.

The Environmental Obligations table below shows the amounts accrued for Northern Utilities related to estimated future cleanup costs associated with Northern Utilities’ environmental remediation obligations for former MGP sites. Corresponding Regulatory Assets were recorded to reflect that the future recovery of these environmental remediation costs is expected based on regulatory precedent and established practices.

Fitchburg’s Manufactured Gas Plant Site – Fitchburg began work on the permanent remediation solution at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts in the second quarter of 2014. Work is expected to be completed in the fourth quarter of 2014. During the second quarter of 2014, the Company updated its estimate for remediation of this site based upon revised estimates from the consultant performing the work. Consequently, the Company’s previously recorded estimate for this work was adjusted from $12.0 million to $5.5 million. As of September 30, 2014, $1.4 million was spent in 2014 on this remediation project. The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site with a corresponding Regulatory Asset recorded to reflect that the recovery of these environmental remediation costs are probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, without carrying costs.

The Company’s ultimate liability for future environmental remediation costs, including MGP site costs, may vary from estimates, which may be adjusted as new information or future developments become available. Based on the Company’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

Environmental Obligations – The following table shows the Environmental Obligations recognized by the Company as of September 30, 2014, September 30, 2013 and December 31, 2013.


	September 30,				December 31,
Environmental Obligations ($ millions)	2014		2013		2013
Current:
Northern Utilities	$	1.2	$	1.1	$	1.0
Fitchburg		4.1		—		—

Total Current Environmental Obligations		5.3		1.1		1.0

Noncurrent:
Northern Utilities		2.0		1.8		1.8
Fitchburg		—		12.0		12.0

Total Noncurrent Environmental Obligations		2.0		13.8		13.8

Total Environmental Obligations	$	7.3	$	14.9	$	14.8

NOTE 8: INCOME TAXES

The Company filed its tax returns for the year ended December 31, 2013 with the Internal Revenue Service (IRS) in September 2014 and generated federal net operating loss (NOL) carryforward assets of $2.1 million principally due to bonus depreciation and tangible asset and repair deductions. As of December 31, 2013, the Company had recorded cumulative federal and state NOL carryforward assets of $19.0 million to offset against taxes payable in future periods. If unused, the Company’s state NOL carryforward assets will begin to expire in 2019 and the federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2013, the Company had $2.1 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

The Company evaluated its tax positions at September 30, 2014 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2011; December 31, 2012; and December 31, 2013.

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.

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, 2013 as filed with the SEC on January 29, 2014 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:


	2014			2013
Used to Determine Plan Costs
Discount Rate		4.80	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2018			2017

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


	Pension Plan						PBOP Plan						SERP
Three Months Ended September 30,	2014			2013			2014			2013			2014		2013
Service Cost	$	753		$	893		$	497		$	630		$	15	$	19
Interest Cost		1,273			1,142			671			612			68		60
Expected Return on Plan Assets		(1,562	)		(1,488	)		(230	)		(180	)		—		—
Prior Service Cost Amortization		52			52			421			425			2		2
Actuarial Loss Amortization		711			1,057			14			197			25		46

Sub-total		1,227			1,656			1,373			1,684			110		127
Amounts Capitalized and Deferred		(556	)		(805	)		(632	)		(808	)		—		—

Net Periodic Benefit Cost Recognized	$	671		$	851		$	741		$	876		$	110	$	127


	Pension Plan						PBOP Plan						SERP
Nine Months Ended September 30,	2014			2013			2014			2013			2014		2013
Service Cost	$	2,255		$	2,680		$	1,491		$	1,892		$	43	$	55
Interest Cost		3,819			3,425			2,015			1,836			204		181
Expected Return on Plan Assets		(4,684	)		(4,466	)		(690	)		(541	)		—		—
Prior Service Cost Amortization		158			156			1,261			1,275			8		8
Actuarial Loss Amortization		2,135			3,172			42			590			75		138

Sub-total		3,683			4,967			4,119			5,052			330		382
Amounts Capitalized and Deferred		(1,400	)		(2,189	)		(1,697	)		(2,255	)		—		—

Net Periodic Benefit Cost Recognized	$	2,283		$	2,778		$	2,422		$	2,797		$	330	$	382

Employer Contributions

As of September 30, 2014, the Company had made $3.5 million of contributions to its Pension Plan in 2014 and had not made any contributions to its PBOP Plan in 2014. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2014 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in rates for these Pension and PBOP Plan costs.

As of September 30, 2014, the Company had made $40,000 of contributions to the SERP Plan in 2014. The Company presently anticipates contributing an additional $13,000 to the SERP Plan in 2014.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

Item 4.

Controls and Procedures

Management of the Company, under the supervision and with the participation of the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of September 30, 2014. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of September 30, 2014 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 materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting. During 2015, the Company intends to implement a new customer information system.

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, 2013 as filed with the SEC on January 29, 2014.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Recent Sales of Unregistered Securities

There were no sales of unregistered equity securities by the Company during the fiscal quarter ended September 30, 2014.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table shows purchases made by or on behalf of the Company or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act)) of shares of the Company’s common stock during the fiscal quarter ended September 30, 2014.


	Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share ⁽¹⁾		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ⁽¹⁾		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs ⁽²⁾
7/1/14 – 7/31/14		—		—		—	$	84,140
8/1/14 – 8/31/14		—		—		—	$	84,140
9/1/14 – 9/30/14		160	$	32.30		160	$	78,972

Total		160				160

⁽¹⁾	All purchases were made pursuant to the Company’s 2014 Trading Plan (as defined below).

⁽²⁾

On May 1, 2014, the Company adopted a written trading plan under Rule 10b5-1 (the 2014 Trading Plan) under the Exchange Act to facilitate the repurchase of shares of its common stock on the open market in connection with its Employee Length of Service Awards and the stock portion of its Directors’ annual retainer. On May 1, 2014, the Company filed a Current Report on Form 8-K announcing that it had adopted the 2014 Trading Plan. The 2014 Trading Plan provides for the repurchase of up to $90,000 worth of shares of the Company’s common stock during its term. The 2014 Trading Plan became effective on May 1, 2014 and will terminate on May 1, 2015. The Company may suspend or terminate the 2014 Trading Plan at any time, so long as the suspension or termination is made in good faith and not as part of a plan or scheme to evade the prohibitions of Rule 10b-5 under the Exchange Act or other applicable securities laws.

Item 5.

Other Information

On October 23, 2014, the Company issued a press release announcing its results of operations for the three- and nine-month periods ended September 30, 2014. 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
4.1	Form of Note Purchase Agreement dated as of October 15, 2014 by and among Northern Utilities and the several purchasers named therein.	Exhibit 4.1 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)

4.2	Form of Note issued pursuant to the Note Purchase Agreement dated as of October 15, 2014 by and among Northern Utilities and the several purchasers named therein.	Exhibit 4.2 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)

11	Computation in Support of Earnings Per Weighted Average Common Share	Filed herewith

31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.3	Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

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

99.1	Unitil Corporation Press Release Dated October 23, 2014 Announcing Earnings For the Quarter Ended September 30, 2014.	Filed herewith

101.INS	XBRL Instance Document.	Filed herewith

101.SCH	XBRL Taxonomy Extension Schema Document.	Filed herewith

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



101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith

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

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

SIGNATURES

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


		UNITIL CORPORATION
		(Registrant)

Date: October 23, 2014		/s/ Mark H. Collin
		Mark H. Collin
		Chief Financial Officer

Date: October 23, 2014		/s/ Laurence M. Brock
		Laurence M. Brock
		Chief Accounting Officer

EXHIBIT INDEX


Exhibit No.	Description of Exhibit	Reference
4.1	Form of Note Purchase Agreement dated as of October 15, 2014 by and among Northern Utilities and the several purchasers named therein.	Exhibit 4.1 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)

4.2	Form of Note issued pursuant to the Note Purchase Agreement dated as of October 15, 2014 by and among Northern Utilities and the several purchasers named therein.	Exhibit 4.2 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)

11	Computation in Support of Earnings Per Weighted Average Common Share	Filed herewith

31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.3	Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

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

99.1	Unitil Corporation Press Release Dated October 23, 2014 Announcing Earnings For the Quarter Ended September 30, 2014.	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