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Table of Contents
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 the quarterly period ended
September 30, 2019
or

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

For the transition period from
__
______to __
__
___
_
_
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
Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Trading Symbol |  | Name of each exchange of which registered
Common Stock |  | UTL |  | New York Stock Exchange

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
☒
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
☒
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.

Large accelerated filer |  | ☒ |  | Accelerated filer |  | ☐
Non-accelerated filer |  | ☐ |  | Smaller reporting company |  | ☐
(Do not check if a smaller reporting company) |  | Emerging growth company |  | ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act
☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2
of the Exchange Act). Yes
☐
No
☒
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 21, 2019
Common Stock, No par value |  | 14,926,205 Shares

Table of Contents
UNITIL CORPORATION AND SUBSIDIARY COMPANIES
FORM
10-Q
For the Quarter Ended September 30, 2019

|  | Page No. |
Part I. Financial Information |  |  |  |
Item 1. |  | Financial Statements - Unaudited |  |  |  |
|  | Consolidated Statements of Earnings - Three and Nine Months Ended September 30, 2019 and 2018 |  |  | 19 |
|  | Consolidated Balance Sheets, September 30, 2019, September 30, 2018 and December 31, 2018 |  |  | 20- 21 |
|  | Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2019 and 2018 |  |  | 22 |
|  | Consolidated Statements of Changes in Common Stock Equity - Three and Nine Months Ended September 30, 2019 and 2018 |  |  | 23- 24 |
|  | Notes to Consolidated Financial Statements |  |  | 25- 51 |
Item 2. |  | Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations |  |  | 3- 18 |
Item 3. |  | Quantitative and Qualitative Disclosures About Market Risk |  |  | 51 |
Item 4. |  | Controls and Procedures |  |  | 51 |
Part II. Other Information |  |  |  |
Item 1. |  | Legal Proceedings |  |  | 51 |
Item 1A. |  | Risk Factors |  |  | 52 |
Item 2. |  | Unregistered Sales of Equity Securities and Use of Proceeds |  |  | 52 |
Item 3. |  | Defaults Upon Senior Securities |  |  | Inapplicable |
Item 4. |  | Mine Safety Disclosures |  |  | Inapplicable |
Item 5. |  | Other Information |  |  | 52 |
Item 6. |  | Exhibits |  |  | 53 |
Signatures |  |  |  |  | 55

Table of Contents
Cautionary Statement
This report and the documents incorporated by reference into this report contain statements that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, included or incorporated by reference into this report, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for the Company’s future operations, are forward-looking statements.
These statements include declarations regarding the Company’s beliefs and current expectations. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue,” or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in Item 1A (Risk Factors) and the following:

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

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

| • | customers’ preferred energy sources;

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

| • | the potential for disruption to the Company’s operations due to cyber-attacks, computer viruses, human errors, acts of war or terrorism or other reasons;

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

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

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

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

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

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

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

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

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

| • | catastrophic events;

2

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

| i) | 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 105,600 electric customers and 82,700 natural gas customers in their service territory.
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 $1,083.9 million at September 30, 2019. 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 Resources is the Company’s wholly-owned
non-regulated
subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource), which the Company divested of in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. Usource provided brokering and advisory services to large commercial and industrial customers in the northeastern United States. See additional discussion of the divestiture of Usource in “Divestiture of
Non-Regulated
Business Subsidiary” in Note 1 to the Consolidated Financial Statements.
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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., 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
Regulation
Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities are also regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the Massachusetts Department of Public Utilities (MDPU); and Northern Utilities is regulated by the NHPUC and the Maine Public Utilities Commission (MPUC). Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.
Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, and earn a return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its natural gas transmission pipeline company may also recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost tracker rate mechanisms.
Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recognized as an increase or a decrease in Accrued Revenue which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the MDPU. The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.
Tax Cuts and Jobs Act of 2017
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law. Among other things, the TCJA substantially reduced the corporate income tax rate to 21 percent, effective January 1, 2018. Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, issued orders directing how the tax law changes were to be reflected in rates. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State. More recently, on November 15, 2018, the FERC issued a Notice of Proposed Rulemaking and a Policy Statement to address the TCJA’s effects on the Accumulated Deferred Income Taxes (ADIT) on transmission rates. Under the proposed rules all public utilities with transmission formula rates, including Fitchburg, would be required to: (1) include mechanisms
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to deduct any excess ADIT from or add any deficient ADIT to their rate bases; (2) include mechanisms in those rates that would raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (3) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. The Company believes that these matters are substantially resolved and will not have a material impact on its financial position, operating results, or cash flows.
Rate Case Activity
Northern Utilities – Base Rates – Maine –
On June 28, 2019, Northern Utilities filed a petition with the MPUC seeking an increase to annual base operating revenues of $7.0 million. If approved as filed, the requested increase will result in a 7 percent increase over the Company’s test-year operating revenues. The intended rate effective date is April 1, 2020. In addition, Northern Utilities is requesting approval to implement a multi-year alternative rate mechanism (“Capital Investment Recovery Adjustment” or “CIRA”) that will allow for future changes to the Company’s distribution rates and mitigate the need to file a general rate case. The CIRA is designed to recover the costs of replacing, relocating and abandoning existing facilities and other operational and safety-related system improvements. The first annual adjustment is proposed for November 1, 2020, to recover the Company’s 2019 investment cost of eligible facilities and improvements. This matter remains pending.
Northern Utilities – Targeted Infrastructure Replacement Adjustment (TIRA) – Maine –
The settlement in Northern Utilities’ Maine division’s 2013 rate case allowed the Company to implement a 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, including the Company’s Cast Iron Replacement Program (CIRP). In its Final Order issued on February 28, 2018 for Northern Utilities’ last base rate case, the MPUC approved an extension of the TIRA mechanism, for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. On May 7, 2018, the MPUC approved the Company’s request to increase its annual base rates by 2.4%, or $1.1 million, effective May 1, 2018, to recover the revenue requirements for 2017 eligible facilities. On April 17, 2019, the MPUC approved the Company’s request to increase its annual base rates by 2.1%, or $1.0 million, effective May 1, 2019, to recover the revenue requirements for 2018 eligible facilities.
Northern Utilities – Base Rates – New Hampshire –
On May 2, 2018, the NHPUC approved a settlement agreement providing for a net annual revenue increase of $3.2 million, incorporating the effect of the TCJA, and an initial step increase to recover post-test year capital investments. The Company’s second step increase of approximately $1.4 million of annual revenue was approved by the NHPUC, effective May 1, 2019, to recover eligible capital investments in 2018. According to the terms of the settlement agreement, Northern Utilities’ next distribution base rate case shall be based on an historic test year of no earlier than twelve months ending December 31, 2020.
Unitil Energy – Base Rates –
On April 20, 2017 the NHPUC issued its final order providing for a permanent increase of $4.1 million, effective May 1, 2017, followed by two annual rate step adjustments to recover the revenue requirements associated with certain capital expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s first step increase, effective May 1, 2018. On April 22, 2019, the NHPUC approved Unitil Energy’s second and final step adjustment, providing for a revenue increase of approximately $340,000, effective May 1, 2019.
Fitchburg – Base Rates – Electric –
Fitchburg’s base rates are decoupled, and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On April 3, 2019, the DPU approved Fitchburg’s cumulative revenue requirement associated with the Company’s 2015 and 2016 capital expenditures, an increase of $0.4 million. The increase was effective January 1, 2018. On November 1, 2018, Fitchburg filed its cumulative revenue requirement of $0.9 million associated with the Company’s 2015, 2016 and 2017 capital expenditures. On December 27, 2018, the filing was approved, effective January 1, 2019, subject to further investigation and reconciliation. Final approval of the 2018 filing
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remains pending. On September 5, 2019, Fitchburg’s electric division filed with the MDPU a letter of intent to file for a general increase in base rates. Under MDPU precedent, a utility company is required to provide no less than a 30 day advance notice of its intent to file for a base rate increase. At this time, Fitchburg anticipates that the filing will be made during the fourth quarter 2019.
Fitchburg – Base Rates – Gas –
Pursuant to the Company’s revenue decoupling adjustment clause tariff, as approved in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather and energy efficiency impacts to the Company’s revenues. The MDPU has consistently found that the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that they result in just and reasonable rates. On September 5, 2019, Fitchburg’s gas division filed with the MDPU a letter of intent to file for a general increase in base rates. Under MDPU precedent, a utility company is required to provide no less than a 30 day advance notice of its intent to file for a base rate increase. At this time, Fitchburg anticipates that the filing will be made during the fourth quarter 2019.
Fitchburg – Gas System Enhancement Program –
Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31 (the “GSEP Filing”); and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred (the “GREC Filing”). The Company considers these to be routine regulatory proceedings and there are no material issues outstanding.
In an Order issued on April 30, 2019, the MDPU approved Fitchburg’s 2018 GSEP Filing and increased the annual cap on recovery. Because the amount approved for recovery, $1.6 million, still exceeded the annual cap, the Order resulted in a revenue increase of $1.0 million that went into effect on May 1, 2019, subject to reconciliation. The amount that exceeded the cap, $0.6 million, has been deferred to be recovered in a later proceeding. On May 1, 2019, the Company made its 2019 GREC Filing, seeking a waiver of the annual cap and a revenue increase of $1.0 million. This matter remains pending.
Granite State – Base Rates –
On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which provided for no change in rates, and accounted for the effects of a capital step adjustment offset by the effect of the TCJA. The settlement was approved by FERC on June 27, 2018, and complies with the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reductions under the TCJA.
RESULTS OF OPERATIONS
The following section of MD&A compares the results of operations for each of the two fiscal periods ended September 30, 2019 and September 30, 2018 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.
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Earnings Overview
The Company’s Net Income was $2.3 million, or $0.15 in Earnings Per Share (EPS), for the third quarter of 2019, a decrease of $0.5 million, or $0.04 in EPS, compared to the third quarter of 2018. For the nine months ended September 30, 2019, the Company reported Net Income of $32.8 million, or $2.20 in EPS, an increase of $10.8 million, or $0.71 in EPS, compared to the same nine month period in 2018. In the first quarter of 2019, the Company recognized a
one-time
net gain of $9.8 million, or $0.66 in EPS, on the Company’s divestiture of its
non-regulated
business subsidiary, Usource. In addition, the Company’s earnings in the first nine months 2019 were driven by higher natural gas and electric sales margins. Earnings for the Company’s utility operations were Net Income of $23.0 million, or $1.54 in EPS, for the first nine months of 2019, an increase of $1.0 million in Net Income, or $0.05 in EPS, compared to the first nine months of 2018.
Natural gas sales margins were $18.7 million and $85.5 million in the three and nine months ended September 30, 2019, respectively, increases of $1.1 million and $5.1 million, respectively, compared to the same periods in 2018. Gas sales margins in the third quarter of 2019 were positively affected by higher natural gas distribution rates of $0.8 million and by $0.3 million from higher therm sales, reflecting customer growth and increased average consumption by Commercial and Industrial (C&I) and Residential customers.
Gas sales margins in the first nine months of 2019 were positively affected by higher natural gas distribution rates of $4.6 million and by $1.7 million from higher therm sales, reflecting customer growth and increased average consumption by C&I and Residential customers. The positive effect of the higher rates and customer growth was partially offset by the absence in the current period of a $1.2 million
non-recurring
adjustment recognized in the second quarter of 2018 to increase gas revenue in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility.
Natural gas therm sales increased 4.2% and 2.5% in the three and nine month periods ended September 30, 2019, respectively, compared to the same periods in 2018. The increase in gas therm sales in the Company’s service areas was driven by customer growth and increased average consumption by C&I and Residential customers. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 5.5% in the first nine months of 2019 compared to the same period in 2018. As of September 30, 2019, the number of total natural gas customers served has increased by 1,468 over the last year.
Electric sales margins were $25.1 million and $70.6 million in the three and nine months ended September 30, 2019, respectively, a decrease of $0.8 million and an increase of $0.1 million, respectively, compared to the same periods in 2018. The decrease in electric sales margins in the third quarter were due to lower kWh sales, reflecting milder summer weather in 2019 and overall lower average usage, including reduced usage by some industrial customers for production purposes, partially offset by positive customer growth. Electric sales margins in the first nine months of 2019 were positively affected by higher electric distribution rates of $1.4 million, partially offset by a decrease of $1.3 million from lower kWh sales, for the reasons noted above.
Total electric kilowatt-hour (kWh) sales decreased 5.3% and 5.2%, respectively in the three and nine month periods ended September 30, 2019 compared to the same periods in 2018. For the third quarter, the decrease reflects milder summer weather in 2019 compared to 2018. Based on weather data collected in the Company’s electric service areas, there were 19% fewer Cooling Degree Days in the third quarter of 2019 compared to the same period in 2018. The decreases in the three and nine month periods also reflect overall lower average usage due to both energy efficiency purposes and aforementioned reduced usage by some industrial customers, but were partially offset by overall customer growth. As of September 30, 2019, the number of total electric customers served has increased by 554 over the last year.
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Operation and Maintenance (O&M) expenses decreased $0.9 million and $1.6 million in three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. Excluding a
non-recurring
adjustment to increase O&M expenses by $1.2 million in the second quarter of 2018 in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility; O&M expenses decreased $0.4 million in the nine months ended September 30, 2019 compared to the same period in 2018. The decrease in the three month period reflects lower labor and other costs of $0.8 million, resulting from the divestiture of the Company’s
non-regulated
business subsidiary, Usource. In addition, in the three month period, the decrease in O&M expenses reflects lower professional fees of $0.4 million, partially offset by higher compensation and benefit costs of $0.3 million. The decrease in the nine month period reflects lower labor and other costs of $1.7 million, resulting from the divestiture of the Company’s
non-regulated
business subsidiary, Usource. O&M expenses in the nine month period also reflect higher compensation and benefit costs of $0.9 million, higher utility operating costs of $0.3 million and higher professional fees of $0.1 million.
Depreciation and Amortization expense increased $0.4 million and $1.6 million in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. These increases reflect increased depreciation on higher levels of utility plant in service, partially offset by lower amortization.
Taxes Other Than Income Taxes in the three months ended September 30, 2019 was essentially unchanged compared to the same period in 2018, reflecting higher local property tax rates on higher levels of utility plant in service, offset by property tax abatements. Taxes Other Than Income Taxes increased $0.5 million in the nine months ended September 30, 2019 compared to the same period in 2018. The increase in the nine month period reflects higher local property tax rates on higher levels of utility plant in service, partially offset by property tax abatements.
Interest Expense, Net decreased $0.2 million in the three months ended September 30, 2019, compared to the same period in 2018, reflecting lower interest on short-term borrowings and higher interest income on AFUDC. For the nine months ended September 30, 2019, Interest Expense, Net was essentially unchanged compared to the same period in 2018, reflecting lower interest on long-term debt and higher interest income on AFUDC, offset by interest on higher levels of short-term borrowings.
Other Expense (Income), Net decreased by $0.1 million for the three months ended September 30, 2019 compared to the same period in 2018. Other Expense (Income), Net changed from an expense of $4.1 million in the first nine months of 2018 to income of $9.8 million in the first nine months of 2019, a net change of $13.9 million. This change primarily reflects a
pre-tax
gain of $13.4 million on the Company’s divestiture of Usource, discussed above, and lower retirement benefit costs in the current period. The Usource divestiture generated a capital gain to the Company and a $3.6 million provision is included in the Company’s income tax expense for the nine months ended September 30, 2019.
Federal and State Income Taxes increased by $0.5 million and $5.2 million for the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. The increase in the nine month period reflects income taxes associated with the Company’s divestiture of its
non-regulated
business subsidiary, Usource, discussed above.
At its January 2019, April 2019, July 2019 and October 2019 meetings, the Unitil Corporation Board of Directors declared quarterly dividends on the Company’s common stock of $0.37 per share. These quarterly dividends result in a current effective annualized dividend rate of $1.48 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, 2019 is presented below.
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Gas Sales, Revenues and Margin
Therm Sales –
Unitil’s total therm sales of natural gas increased 4.2% and 2.5% in the three and nine month periods ended September 30, 2019, respectively, compared to the same periods in 2018. In the third quarter of 2019, sales to Residential and C&I customers increased 4.0% and 4.2%, respectively, compared to the same period in 2018. For the nine months ended September 30, 2019, sales to Residential and C&I customers increased 0.8% and 2.9%, respectively, compared to the same period in 2018. The increase in gas therm sales in the Company’s service areas was driven by customer growth and increased average consumption by C&I and Residential customers. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 5.5% in the first nine months of 2019 compared to the same period in 2018. As of September 30, 2019, the number of total natural gas customers served has increased by 1,468 over the last year. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 11% of total annual therm sales volume) are 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, 2019 and 2018, by major customer class:

Therm Sales (millions) |
|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2019 |  |  | 2018 |  |  | Change |  |  | % Change |  |  | 2019 |  |  | 2018 |  |  | Change |  |  | % Change |
Residential |  |  | 2.6 |  |  |  | 2.5 |  |  |  | 0.1 |  |  |  | 4.0 | % |  |  | 36.2 |  |  |  | 35.9 |  |  |  | 0.3 |  |  |  | 0.8 | %
Commercial / Industrial |  |  | 24.9 |  |  |  | 23.9 |  |  |  | 1.0 |  |  |  | 4.2 | % |  |  | 136.2 |  |  |  | 132.3 |  |  |  | 3.9 |  |  |  | 2.9 | %
Total |  |  | 27.5 |  |  |  | 26.4 |  |  |  | 1.1 |  |  |  | 4.2 | % |  |  | 172.4 |  |  |  | 168.2 |  |  |  | 4.2 |  |  |  | 2.5 | %

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, 2019 and 2018:

Gas Operating Revenues and Sales Margin (millions) |
|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2019 |  |  | 2018 |  |  | $ Change |  |  | % Change |  |  | 2019 |  |  | 2018 |  |  | $ Change |  |  | % Change |
Gas Operating Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 8.9 |  |  | $ | 9.2 |  |  | $ | (0.3 | ) |  |  | (3.3 | %) |  | $ | 57.8 |  |  | $ | 58.9 |  |  | $ | (1.1 | ) |  |  | (1.9 | %)
Commercial / Industrial |  |  | 16.0 |  |  |  | 16.5 |  |  |  | (0.5 | ) |  |  | (3.0 | %) |  |  | 86.1 |  |  |  | 88.5 |  |  |  | (2.4 | ) |  |  | (2.7 | %)
Total Gas Operating Revenue |  | $ | 24.9 |  |  | $ | 25.7 |  |  | $ | (0.8 | ) |  |  | (3.1 | %) |  | $ | 143.9 |  |  | $ | 147.4 |  |  | $ | (3.5 | ) |  |  | (2.4 | %)
Cost of Gas Sales |  | $ | 6.2 |  |  | $ | 8.1 |  |  | $ | (1.9 | ) |  |  | (23.5 | %) |  | $ | 58.4 |  |  | $ | 67.0 |  |  | $ | (8.6 | ) |  |  | (12.8 | %)
Gas Sales Margin |  | $ | 18.7 |  |  | $ | 17.6 |  |  | $ | 1.1 |  |  |  | 6.2 | % |  | $ | 85.5 |  |  | $ | 80.4 |  |  | $ | 5.1 |  |  |  | 6.3 | %

The Company analyzes operating results using Gas Sales Margin, a
non-GAAP
measure. Gas Sales Margin is calculated as Total Gas Operating Revenue (See “Utility Revenue Recognition” in Note 1 to the accompanying Consolidated Financial Statements) less Cost of Gas Sales. The Company believes Gas Sales Margin is an important measure to analyze profitability because the approved cost of sales are tracked and reconciled 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.
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Natural gas sales margins were $18.7 million and $85.5 million in the three and nine months ended September 30, 2019, respectively, increases of $1.1 million and $5.1 million, respectively, compared to the same periods in 2018. Gas sales margins in the third quarter of 2019 were positively affected by higher natural gas distribution rates of $0.8 million and by $0.3 million from higher therm sales, reflecting customer growth and increased average consumption by C&I and Residential customers.
Gas sales margins in the first nine months of 2019 were positively affected by higher natural gas distribution rates of $4.6 million and by $1.7 million from higher therm sales, reflecting customer growth and increased average consumption by C&I and Residential customers. The positive effect of the higher rates and customer growth was partially offset by the absence in the current period of a $1.2 million
non-recurring
adjustment recognized in the second quarter of 2018 to increase gas revenue in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility.
The decreases in Total Gas Operating Revenues of $0.8 million and $3.5 million in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2019, reflect lower cost of gas sales, which are tracked and reconciled costs that are passed through directly to customers, and for the nine month period, the
non-recurring
adjustment recognized in the second quarter of 2019, discussed above, partially offset by higher natural gas sales volumes.
Electric Sales, Revenues and Margin
Kilowatt-hour Sales
– Unitil’s total electric kWh sales decreased 5.3% and 5.2%, respectively in the three and nine month periods ended September 30, 2019 compared to the same periods in 2018. Sales to Residential customers decreased 7.2% and 5.6%, respectively, in the three and nine month periods ended September 30, 2019 compared to the same periods in 2018. Sales to C&I customers decreased 4.0% and 4.9%, respectively, in the three and nine month periods ended September 30, 2019 compared to the same periods in 2018. For the third quarter, the decrease reflects milder summer weather in 2019 compared to 2018. Based on weather data collected in the Company’s electric service areas, there were 19% fewer Cooling Degree Days in the third quarter of 2019 compared to the same period in 2018. The decreases in the three and nine month periods also reflect overall lower average usage due to both energy efficiency purposes and aforementioned reduced usage by some industrial customers, but were partially offset by overall customer growth. As of September 30, 2019, the number of total electric customers served has increased by 554 over the last year. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 27% of total annual kWh sales volume) are not sensitive to changes in electric kWh sales.
The following table details total kWh sales for the three and nine months ended September 30, 2019 and 2018 by major customer class:

kWh Sales (millions) |
|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2019 |  |  | 2018 |  |  | Change |  |  | % Change |  |  | 2019 |  |  | 2018 |  |  | Change |  |  | % Change |
Residential |  |  | 180.9 |  |  |  | 195.0 |  |  |  | (14.1 | ) |  |  | (7.2 | %) |  |  | 498.3 |  |  |  | 527.8 |  |  |  | (29.5 | ) |  |  | (5.6 | %)
Commercial / Industrial |  |  | 257.7 |  |  |  | 268.3 |  |  |  | (10.6 | ) |  |  | (4.0 | %) |  |  | 718.5 |  |  |  | 755.9 |  |  |  | (37.4 | ) |  |  | (4.9 | %)
Total |  |  | 438.6 |  |  |  | 463.3 |  |  |  | (24.7 | ) |  |  | (5.3 | %) |  |  | 1,216.8 |  |  |  | 1,283.7 |  |  |  | (66.9 | ) |  |  | (5.2 | %)

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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, 2019 and 2018:

Electric Operating Revenues and Sales Margin (millions) |
|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2019 |  |  | 2018 |  |  | $ Change |  |  | % Change |  |  | 2019 |  |  | 2018 |  |  | $ Change |  |  | % Change |
Electric Operating Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 34.4 |  |  | $ | 35.5 |  |  | $ | (1.1 | ) |  |  | (3.1 | %) |  | $ | 101.9 |  |  | $ | 95.7 |  |  | $ | 6.2 |  |  |  | 6.5 | %
Commercial / Industrial |  |  | 26.0 |  |  |  | 25.9 |  |  |  | 0.1 |  |  |  | 0.4 | % |  |  | 75.1 |  |  |  | 71.9 |  |  |  | 3.2 |  |  |  | 4.5 | %
Total Electric Operating Revenue |  | $ | 60.4 |  |  | $ | 61.4 |  |  | $ | (1.0 | ) |  |  | (1.6 | %) |  | $ | 177.0 |  |  | $ | 167.6 |  |  | $ | 9.4 |  |  |  | 5.6 | %
Cost of Electric Sales |  | $ | 35.3 |  |  | $ | 35.5 |  |  | $ | (0.2 | ) |  |  | (0.6 | %) |  | $ | 106.4 |  |  | $ | 97.1 |  |  | $ | 9.3 |  |  |  | 9.6 | %
Electric Sales Margin |  | $ | 25.1 |  |  | $ | 25.9 |  |  | $ | (0.8 | ) |  |  | (3.1 | %) |  | $ | 70.6 |  |  | $ | 70.5 |  |  | $ | 0.1 |  |  |  | 0.1 | %

The Company analyzes operating results using Electric Sales Margin, a
non-GAAP
measure. Electric Sales Margin is calculated as Total Electric Operating Revenues (See “Utility Revenue Recognition” in Note 1 to the accompanying Consolidated Financial Statements) less Cost of Electric Sales. The Company believes Electric Sales Margin is an important measure to analyze profitability because the approved cost of sales are tracked and reconciled 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 $25.1 million and $70.6 million in the three and nine months ended September 30, 2019, respectively, a decrease of $0.8 million and an increase of $0.1 million, respectively, compared to the same periods in 2018. The decrease in electric sales margins in the third quarter were due to lower kWh sales, reflecting milder summer weather in 2019 and overall lower average usage, including reduced usage by some industrial customers for production purposes, partially offset by positive customer growth. Electric sales margins in the first nine months of 2019 were positively affected by higher electric distribution rates of $1.4 million, partially offset by a decrease of $1.3 million from lower kWh sales, for the reasons noted above.
Total Electric Operating Revenues decreased $1.0 million in the three months ended September 30, 2019, respectively, compared to the same period in 2018 reflecting lower sales of electricity, partially offset by lower cost of electric sales, which are tracked and reconciled to costs that are passed through directly to customers. Total Electric Operating Revenues increased $9.4 million in the nine months ended September 30, 2019, respectively, compared to the same period in 2018 reflecting higher cost of electric sales, partially offset by lower sales of electricity.
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Operating Revenue – Other
The following table details total Other Revenue for the three and nine months ended September 30, 2019 and 2018:

Other Revenue (000’s) |
|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2019 |  |  | 2018 |  |  | $ Change |  |  | % Change |  |  | 2019 |  |  | 2018 |  |  | $ Change |  |  | % Change |
Other |  | $ | — |  |  | $ | 1.1 |  |  | $ | (1.1 | ) |  |  | N/M |  |  | $ | 0.9 |  |  | $ | 3.5 |  |  | $ | (2.6 | ) |  |  | (74.3 | %)
Total Other Revenue |  | $ | — |  |  | $ | 1.1 |  |  | $ | (1.1 | ) |  |  | N/M |  |  | $ | 0.9 |  |  | $ | 3.5 |  |  | $ | (2.6 | ) |  |  | (74.3 | %)

Total Other Operating Revenue (See “Other Operating Revenue –
Non-regulated”
in Note 1 to the accompanying Consolidated Financial Statements), which is comprised of revenues from the Company’s
non-regulated
energy brokering business, Usource, decreased $1.1 million and $2.6 million, respectively, in the three and nine months ended September 30, 2019, compared to the same periods in 2018, reflecting the Company’s divestiture of Usource in the first quarter of 2019 (See “Divestiture of
Non-Regulated
Business Subsidiary” in Note 1 to the accompanying Consolidated Financial Statements).
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 $1.9 million, or 23.5%, and $8.6 million, or 12.8%, in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. These decreases reflect lower wholesale natural gas prices, partially offset by higher sales of natural gas. 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 decreased $0.2 million, or 0.6%, and increased $9.3 million, or 9.6%, in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. The decrease in the three month period reflects lower sales of electricity, partially offset by higher wholesale electricity prices and a decrease 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 and a decrease in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by lower sales of electricity. The Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost on a pass-through basis and therefore changes in approved expenses do not affect earnings.
Operation and Maintenance (O&M) –
O&M expense includes gas and electric utility operating costs, and the operating cost of the Company’s corporate and other business activities. O&M expense decreased $0.9 million, or 5.5%, and $1.6 million, or 3.1%, in three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. Excluding a
non-recurring
adjustment to increase O&M expenses by $1.2 million in the second quarter of 2018 in connection with a then ongoing base rate case for the Company’s New Hampshire natural gas utility; O&M expenses decreased $0.4 million in the nine months ended September 30, 2019 compared to the same period in 2018. The decrease in the three month period reflects lower labor and other costs of $0.8 million, resulting from the divestiture of the Company’s
non-regulated
business subsidiary, Usource. In addition, in the three month period, the decrease in O&M expenses reflects lower professional fees of $0.4 million, partially offset by higher compensation and benefit costs of $0.3 million. The decrease in the nine month period reflects lower labor and other costs of $1.7 million, resulting from the divestiture of the Company’s
non-regulated
business subsidiary, Usource. O&M expenses in the nine month period also reflect higher compensation and benefit costs of $0.9 million, higher utility operating costs of $0.3 million and higher professional fees of $0.1 million.
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Depreciation and Amortization –
Depreciation and Amortization expense increased $0.4 million, or 3.2%, and $1.6 million, or 4.3%, in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. These increases reflect increased depreciation on higher levels of utility plant in service, partially offset by lower amortization.
Taxes Other Than Income Taxes
– Taxes Other Than Income Taxes in the three months ended September 30, 2019 was essentially unchanged compared to the same period in 2018, reflecting higher local property tax rates on higher levels of utility plant in service, offset by property tax abatements. Taxes Other Than Income Taxes increased $0.5 million, or 3.0%, in the nine months ended September 30, 2019 compared to the same period in 2018. The increase in the nine month period reflects higher local property tax rates on higher levels of utility plant in service, partially offset by property tax abatements.
Other Expense (Income), Net –
Other Expense (Income), Net decreased by $0.1 million for the three months ended September 30, 2019 compared to the same period in 2018. Other Expense (Income), Net changed from an expense of $4.1 million in the first nine months of 2018 to income of $9.8 million in the first nine months of 2019, a net change of $13.9 million. This change primarily reflects a
pre-tax
gain of $13.4 million on the Company’s divestiture of Usource, discussed above, and lower retirement benefit costs in the current period. The Usource divestiture generated a capital gain to the Company and a $3.6 million provision is included in the Company’s income tax expense for the nine months ended September 30, 2019.
Provision for Income Taxes
– Federal and State Income Taxes increased by $0.5 million and $5.2 million for the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. The increase in the nine month period reflects income taxes associated with the Company’s divestiture of its
non-regulated
business subsidiary, Usource, discussed above.
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 accrued.
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.
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Interest Expense, Net (Millions) |  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2019 |  |  | 2018 |  |  | Change |  |  | 2019 |  |  | 2018 |  |  | Change |
Interest Expense |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term Debt |  | $ | 5.7 |  |  | $ | 5.7 |  |  | $ | — |  |  | $ | 17.0 |  |  | $ | 17.3 |  |  | $ | (0.3 | )
Short-term Debt |  |  | 0.6 |  |  |  | 0.7 |  |  |  | (0.1 | ) |  |  | 2.4 |  |  |  | 1.6 |  |  |  | 0.8 |
Regulatory Liabilities |  |  | 0.2 |  |  |  | 0.2 |  |  |  | — |  |  |  | 0.5 |  |  |  | 0.5 |  |  |  | — |
Subtotal Interest Expense |  |  | 6.5 |  |  |  | 6.6 |  |  |  | (0.1 | ) |  |  | 19.9 |  |  |  | 19.4 |  |  |  | 0.5 |
Interest (Income) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  | (0.2 | ) |  |  | (0.2 | ) |  |  | — |  |  |  | (0.6 | ) |  |  | (0.6 | ) |  |  | — |
AFUDC (1) and Other |  |  | (0.5 | ) |  |  | (0.4 | ) |  |  | (0.1 | ) |  |  | (1.4 | ) |  |  | (0.9 | ) |  |  | (0.5 | )
Subtotal Interest (Income) |  |  | (0.7 | ) |  |  | (0.6 | ) |  |  | (0.1 | ) |  |  | (2.0 | ) |  |  | (1.5 | ) |  |  | (0.5 | )
Total Interest Expense, Net |  | $ | 5.8 |  |  | $ | 6.0 |  |  | $ | (0.2 | ) |  | $ | 17.9 |  |  | $ | 17.9 |  |  | $ | — |

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

Interest Expense, Net decreased $0.2 million in the three months ended September 30, 2019, compared to the same period in 2018, reflecting lower interest on short-term borrowings and higher interest income on AFUDC. For the nine months ended September 30, 2019, Interest Expense, Net was essentially unchanged compared to the same period in 2018, reflecting lower interest on long-term debt and higher interest income on AFUDC, offset by interest on higher levels of short-term borrowings.
Capital Requirements
Sources of Capital
Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities. The Company initially supplements internally-generated funds through short-term bank borrowings, as needed, under its unsecured revolving Credit Facility. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term nature of its utility assets. Additionally, from time to time, the Company has accessed the public capital markets through public offerings of equity securities. The Company’s utility operations are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The amount, type and timing of any future financing will vary from year to year based on capital needs and maturity or redemptions of securities.
The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (the “Cash Pool”). The Cash Pool is the financing vehicle for
day-to-day
cash borrowing and investing. The Cash Pool allows for an efficient exchange of cash among the Company and its subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on actual interest costs from lenders under the Company’s revolving Credit Facility (as defined below). At September 30, 2019, September 30, 2018 and December 31, 2018, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.
On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement and related documents (collectively, the “Credit Facility”) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit facility. The Credit Facility extends to July 25, 2023, subject to two
one-year
extensions under certain circumstances, and has a borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company 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 1.125%. The Company may increase the borrowing limit under the Credit Facility by up to $50 million under certain circumstances.
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The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $187.1 million for the nine months ended September 30, 2019. Total gross repayments were $220.7 million for the nine months ended September 30, 2019. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30, 2019, September 30, 2018 and December 31, 2018:

|  | Revolving Credit Facility ($ millions) |
|  | September 30, |  |  | December 31, |
|  | 2019 |  |  | 2018 |  |  | 2018 |
Limit |  | $ | 120.0 |  |  | $ | 120.0 |  |  | $ | 120.0 |
Short-Term Borrowings Outstanding |  |  | 49.2 |  |  |  | 69.1 |  |  |  | 82.8 |
Letter of Credit Outstanding |  |  | 0.1 |  |  |  | — |  |  |  | — |
Available |  | $ | 70.7 |  |  | $ | 50.9 |  |  | $ | 37.2 |

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, the Company’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on the Company’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 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 Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2019, September 30, 2018 and December 31, 2018, 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.)
The Company believes the future operating cash flows of the Company, along with its existing borrowing availability and access to financial markets for the issuance of new long-term debt, will be sufficient to meet any working capital and future operating requirements, and capital investment forecast opportunities.
As discussed previously, the Company divested of its
non-regulated
subsidiary business, Usource, in the first quarter of 2019. The Company used the net proceeds of $9.8 million from this divestiture for general corporate purposes.
On September 12, 2019, Northern Utilities issued $40 million of Notes due 2049 at 4.04%. Northern Utilities used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.2 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.
On November 30, 2018 Unitil Energy issued $30 million of First Mortgage Bonds due November 30, 2048 at 4.18%. Unitil Energy used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been netted against long-term debt for presentation purposes on the Consolidated Balance Sheets.
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In April 2014, Unitil Service Corp. entered into a financing arrangement, structured as a capital lease obligation, for various information systems and technology equipment. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. This capital lease was paid in full in the second quarter of 2019.
Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services. Unitil Corporation and Granite State are currently rated “Baa2”, and Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1” by Moody’s Investors Services.
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, 2019, there were approximately $4.3 million of guarantees outstanding.
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 $8.1 million, $9.6 million and $8.4 million of natural gas storage inventory at September 30, 2019, September 30, 2018 and December 31, 2018, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2019 and payable in October 2019 is $0.1 million and is recorded in Accounts Payable at September 30, 2019. The amount of natural gas inventory released in September 2018 and payable in October 2018 was $0.1 million and was recorded in Accounts Payable at September 30, 2018. The amount of natural gas inventory released in December 2018 and payable in January 2019 was $0.9 million and was recorded in Accounts Payable at December 31, 2018.
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 Corporation’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. Additionally, as of September 30, 2019, there were approximately $4.3 million of guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities outstanding. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.
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. 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 31, 2019.
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LABOR RELATIONS
As of September 30, 2019, the Company and its subsidiaries had 503 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.
As of September 30, 2019, a total of 162 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, 2019:

|  | Employees Covered |  |  | CBA Expiration |
Fitchburg |  |  | 44 |  |  |  | 05/31/2022 |
Northern Utilities NH Division |  |  | 37 |  |  |  | 06/05/2020 |
Northern Utilities ME Division |  |  | 36 |  |  |  | 03/31/2021 |
Granite State |  |  | 4 |  |  |  | 03/31/2021 |
Unitil Energy |  |  | 36 |  |  |  | 05/31/2023 |
Unitil Service |  |  | 5 |  |  |  | 05/31/2023 |

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 and intercompany money pool transactions for the three months ended September 30, 2019 and September 30, 2018 were 3.4% and 3.3%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 2019 and September 30, 2018 were 3.6% and 3.2%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2018 was 3.3%.
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 full collection of electric power and natural gas supply costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making.
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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.
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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, |
|  | 2019 |  |  | 2018 |  |  | 2019 |  |  | 2018 |
Operating Revenues |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas |  | $ | 24.9 |  |  | $ | 25.7 |  |  | $ | 143.9 |  |  | $ | 147.4 |
Electric |  |  | 60.4 |  |  |  | 61.4 |  |  |  | 177.0 |  |  |  | 167.6 |
Other |  |  | — |  |  |  | 1.1 |  |  |  | 0.9 |  |  |  | 3.5 |
Total Operating Revenues |  |  | 85.3 |  |  |  | 88.2 |  |  |  | 321.8 |  |  |  | 318.5 |
Operating Expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cost of Gas Sales |  |  | 6.2 |  |  |  | 8.1 |  |  |  | 58.4 |  |  |  | 67.0 |
Cost of Electric Sales |  |  | 35.3 |  |  |  | 35.5 |  |  |  | 106.4 |  |  |  | 97.1 |
Operation and Maintenance |  |  | 15.5 |  |  |  | 16.4 |  |  |  | 49.9 |  |  |  | 51.5 |
Depreciation and Amortization |  |  | 12.8 |  |  |  | 12.4 |  |  |  | 39.0 |  |  |  | 37.4 |
Taxes Other Than Income Taxes |  |  | 5.5 |  |  |  | 5.5 |  |  |  | 17.0 |  |  |  | 16.5 |
Total Operating Expenses |  |  | 75.3 |  |  |  | 77.9 |  |  |  | 270.7 |  |  |  | 269.5 |
Operating Income |  |  | 10.0 |  |  |  | 10.3 |  |  |  | 51.1 |  |  |  | 49.0 |
Interest Expense, Net |  |  | 5.8 |  |  |  | 6.0 |  |  |  | 17.9 |  |  |  | 17.9 |
Other Expense (Income), Net |  |  | 1.0 |  |  |  | 1.1 |  |  |  | (9.8 | ) |  |  | 4.1 |
Income Before Income Taxes |  |  | 3.2 |  |  |  | 3.2 |  |  |  | 43.0 |  |  |  | 27.0 |
Provision for Income Taxes |  |  | 0.9 |  |  |  | 0.4 |  |  |  | 10.2 |  |  |  | 5.0 |
Net Income |  | $ | 2.3 |  |  | $ | 2.8 |  |  | $ | 32.8 |  |  | $ | 22.0 |
Net Income Per Common Share (Basic and Diluted) |  | $ | 0.15 |  |  | $ | 0.19 |  |  | $ | 2.20 |  |  | $ | 1.49 |
Weighted Average Common Shares Outstanding – (Basic and Diluted) |  |  | 14.9 |  |  |  | 14.8 |  |  |  | 14.9 |  |  |  | 14.8 |

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)
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UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Millions)
(UNAUDITED)

|  | September 30, |  |  | December 31, |
|  | 2019 |  |  | 2018 |  |  | 2018 |
ASSETS: |  |  |  |  |  |  |  |  |  |  |  |
Current Assets : |  |  |  |  |  |  |  |  |  |  |  |
Cash and Cash Equivalents |  | $ | 7.3 |  |  | $ | 6.3 |  |  | $ | 7.8 |
Accounts Receivable, Net |  |  | 39.4 |  |  |  | 52.3 |  |  |  | 66.8 |
Accrued Revenue |  |  | 35.3 |  |  |  | 36.0 |  |  |  | 54.7 |
Exchange Gas Receivable |  |  | 8.6 |  |  |  | 10.1 |  |  |  | 8.1 |
Refundable Taxes |  |  | 2.9 |  |  |  | — |  |  |  | 0.5 |
Gas Inventory |  |  | 0.8 |  |  |  | 0.9 |  |  |  | 0.8 |
Materials and Supplies |  |  | 7.7 |  |  |  | 7.2 |  |  |  | 7.0 |
Prepayments and Other |  |  | 5.4 |  |  |  | 7.8 |  |  |  | 6.5 |
Total Current Assets |  |  | 107.4 |  |  |  | 120.6 |  |  |  | 152.2 |
Utility Plant: |  |  |  |  |  |  |  |  |  |  |  |
Gas |  |  | 783.2 |  |  |  | 712.7 |  |  |  | 760.6 |
Electric |  |  | 514.8 |  |  |  | 485.6 |  |  |  | 500.1 |
Common |  |  | 61.6 |  |  |  | 82.1 |  |  |  | 83.1 |
Construction Work in Progress |  |  | 72.9 |  |  |  | 68.4 |  |  |  | 25.5 |
Utility Plant |  |  | 1,432.5 |  |  |  | 1,348.8 |  |  |  | 1,369.3 |
Less: Accumulated Depreciation |  |  | 348.6 |  |  |  | 326.5 |  |  |  | 332.5 |
Net Utility Plant |  |  | 1,083.9 |  |  |  | 1,022.3 |  |  |  | 1,036.8 |
Other Noncurrent Assets: |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  | 98.7 |  |  |  | 111.6 |  |  |  | 99.0 |
Operating Lease Right of Use Assets |  |  | 4.2 |  |  |  | — |  |  |  | — |
Other Assets |  |  | 15.5 |  |  |  | 10.0 |  |  |  | 10.3 |
Total Other Noncurrent Assets |  |  | 118.4 |  |  |  | 121.6 |  |  |  | 109.3 |
TOTAL ASSETS |  | $ | 1,309.7 |  |  | $ | 1,264.5 |  |  | $ | 1,298.3 |

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)
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UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS (Cont.)
(Millions, except number of shares)
(UNAUDITED)

|  | September 30, |  |  | December 31, |
|  | 2019 |  |  | 2018 |  |  | 2018 |
LIABILITIES AND CAPITALIZATION: |  |  |  |  |  |  |  |  |  |  |  |
Current Liabilities: |  |  |  |  |  |  |  |  |  |  |  |
Accounts Payable |  | $ | 22.9 |  |  | $ | 27.4 |  |  | $ | 42.6 |
Short-Term Debt |  |  | 49.2 |  |  |  | 69.1 |  |  |  | 82.8 |
Long-Term Debt, Current Portion |  |  | 19.5 |  |  |  | 31.8 |  |  |  | 18.4 |
Regulatory Liabilities |  |  | 14.4 |  |  |  | 12.2 |  |  |  | 11.5 |
Energy Supply Obligations |  |  | 12.5 |  |  |  | 15.0 |  |  |  | 13.4 |
Interest Payable |  |  | 7.1 |  |  |  | 7.0 |  |  |  | 4.3 |
Other Current Liabilities |  |  | 18.8 |  |  |  | 18.0 |  |  |  | 19.5 |
Total Current Liabilities |  |  | 144.4 |  |  |  | 180.5 |  |  |  | 192.5 |
Noncurrent Liabilities: |  |  |  |  |  |  |  |  |  |  |  |
Retirement Benefit Obligations |  |  | 120.8 |  |  |  | 142.4 |  |  |  | 121.5 |
Deferred Income Taxes, net |  |  | 108.3 |  |  |  | 86.4 |  |  |  | 97.8 |
Cost of Removal Obligations |  |  | 98.4 |  |  |  | 91.2 |  |  |  | 90.7 |
Regulatory Liabilities |  |  | 46.7 |  |  |  | 47.9 |  |  |  | 47.0 |
Other Noncurrent Liabilities |  |  | 10.2 |  |  |  | 10.0 |  |  |  | 10.1 |
Total Noncurrent Liabilities |  |  | 384.4 |  |  |  | 377.9 |  |  |  | 367.1 |
Capitalization: |  |  |  |  |  |  |  |  |  |  |  |
Long-Term Debt, Less Current Portion |  |  | 410.9 |  |  |  | 361.1 |  |  |  | 387.4 |
Stockholders’ Equity: |  |  |  |  |  |  |  |  |  |  |  |
Common Equity (Authorized: 25,000,000 and Outstanding: 14,925,898, 14,872,011 and 14,876,955 Shares) |  |  | 281.7 |  |  |  | 278.3 |  |  |  | 279.1 |
Retained Earnings |  |  | 88.1 |  |  |  | 66.5 |  |  |  | 72.0 |
Total Common Stock Equity |  |  | 369.8 |  |  |  | 344.8 |  |  |  | 351.1 |
Preferred Stock |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.2 |
Total Stockholders’ Equity |  |  | 370.0 |  |  |  | 345.0 |  |  |  | 351.3 |
Total Capitalization |  |  | 780.9 |  |  |  | 706.1 |  |  |  | 738.7 |
Commitments and Contingencies (Notes 6 & 7) |  |  |  |  |  |  |  |  |  |  |  |
TOTAL LIABILITIES AND CAPITALIZATION |  | $ | 1,309.7 |  |  | $ | 1,264.5 |  |  | $ | 1,298.3 |

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)
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UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(UNAUDITED)

|  | Nine Months Ended September 30, |
|  | 2019 |  |  | 2018 |
Operating Activities: |  |  |  |  |  |  |  |
Net Income |  | $ | 32.8 |  |  | $ | 22.0 |
Adjustments to Reconcile Net Income to Cash |  |  |  |  |  |  |  |
Provided by Operating Activities: |  |  |  |  |  |  |  |
Depreciation and Amortization |  |  | 39.0 |  |  |  | 37.4 |
Deferred Tax Provision |  |  | 9.3 |  |  |  | 4.6 |
Gain on Divestiture, Net (See Note 1) |  |  | (13.4 | ) |  |  | — |
Changes in Working Capital Items: |  |  |  |  |  |  |  |
Accounts Receivable |  |  | 27.4 |  |  |  | 15.1 |
Accrued Revenue |  |  | 19.4 |  |  |  | 17.3 |
Exchange Gas Receivable |  |  | (0.5 | ) |  |  | (4.3 | )
Regulatory Liabilities |  |  | 2.9 |  |  |  | 3.0 |
Accounts Payable |  |  | (19.7 | ) |  |  | (14.1 | )
Other Changes in Working Capital Items |  |  | (2.4 | ) |  |  | 3.7 |
Deferred Regulatory and Other Charges |  |  | (4.7 | ) |  |  | (5.7 | )
Other, net |  |  | 2.1 |  |  |  | (9.0 | )
Cash Provided by Operating Activities |  |  | 92.2 |  |  |  | 70.0 |
Investing Activities: |  |  |  |  |  |  |  |
Property, Plant and Equipment Additions |  |  | (76.7 | ) |  |  | (76.3 | )
Proceeds from Divestiture, Net (See Note 1) |  |  | 13.4 |  |  |  | — |
Cash (Used in) Investing Activities |  |  | (63.3 | ) |  |  | (76.3 | )
Financing Activities: |  |  |  |  |  |  |  |
(Repayment of) Proceeds from Short-Term Debt, net |  |  | (33.6 | ) |  |  | 30.8 |
Repayment of Long-Term Debt |  |  | (15.2 | ) |  |  | (13.5 | )
Issuance of Long-Term Debt |  |  | 39.8 |  |  |  | — |
Decrease in Capital Lease Obligations |  |  | (5.1 | ) |  |  | (2.3 | )
Net Increase in Exchange Gas Financing |  |  | 0.5 |  |  |  | 4.1 |
Dividends Paid |  |  | (16.7 | ) |  |  | (16.3 | )
Proceeds from Issuance of Common Stock, net |  |  | 0.9 |  |  |  | 0.9 |
Cash (Used in) Provided by Financing Activities |  |  | (29.4 | ) |  |  | 3.7 |
Net Decrease in Cash and Cash Equivalents |  |  | (0.5 | ) |  |  | (2.6 | )
Cash and Cash Equivalents at Beginning of Period |  |  | 7.8 |  |  |  | 8.9 |
Cash and Cash Equivalents at End of Period |  | $ | 7.3 |  |  | $ | 6.3 |
Supplemental Cash Flow Information: |  |  |  |  |  |  |  |
Interest Paid |  | $ | 15.6 |  |  | $ | 15.6 |
Income Taxes Paid |  | $ | 0.9 |  |  | $ | 0.4 |
Payments on Capital Leases |  | $ | 5.4 |  |  | $ | 2.3 |
Non-cash Investing Activity: |  |  |  |  |  |  |  |
Capital Expenditures Included in Accounts Payable |  | $ | 0.8 |  |  | $ | 1.2 |
Right-of-Use Assets Obtained in Exchange for Lease Obligations |  | $ | 4.2 |  |  | $ | — |

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)
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UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(Millions, except per share data and number of shares)
(UNAUDITED)

|  | Common Equity |  |  | Retained Earnings |  |  | Total |
Three Months Ended September 30, 2019 |  |  |  |  |  |  |  |  |  |  |  |
Balance at July 1, 2019 |  | $ | 281.3 |  |  | $ | 91.5 |  |  | $ | 372.8 |
Net Income |  |  |  |  |  |  | 2.3 |  |  |  | 2.3 |
Dividends on Common Shares ($0.370 per share) |  |  |  |  |  |  | (5.7 | ) |  |  | (5.7 | )
Stock Compensation Plans |  |  | 0.1 |  |  |  |  |  |  |  | 0.1 |
Issuance of 4,727 Common Shares |  |  | 0.3 |  |  |  |  |  |  |  | 0.3 |
Balance at September 30, 2019 |  | $ | 281.7 |  |  | $ | 88.1 |  |  | $ | 369.8 |
Three Months Ended September 30, 2018 |  |  |  |  |  |  |  |  |  |  |  |
Balance at July 1, 2018 |  | $ | 277.9 |  |  | $ | 69.1 |  |  | $ | 347.0 |
Net Income |  |  |  |  |  |  | 2.8 |  |  |  | 2.8 |
Dividends on Common Shares ($0.365 per share) |  |  |  |  |  |  | (5.4 | ) |  |  | (5.4 | )
Stock Compensation Plans |  |  | 0.1 |  |  |  |  |  |  |  | 0.1 |
Issuance of 5,423 Common Shares |  |  | 0.3 |  |  |  |  |  |  |  | 0.3 |
Balance at September 30, 2018 |  | $ | 278.3 |  |  | $ | 66.5 |  |  | $ | 344.8 |

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)
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UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(Millions, except per share data and number of shares)
(UNAUDITED)

|  | Common Equity |  |  | Retained Earnings |  |  | Total |
Nine Months Ended September 30, 2019 |  |  |  |  |  |  |  |  |  |  |  |
Balance at January 1, 2019 |  | $ | 279.1 |  |  | $ | 72.0 |  |  | $ | 351.1 |
Net Income |  |  |  |  |  |  | 32.8 |  |  |  | 32.8 |
Dividends on Common Shares ($1.11 per share) |  |  |  |  |  |  | (16.7 | ) |  |  | (16.7 | )
Stock Compensation Plans |  |  | 1.7 |  |  |  |  |  |  |  | 1.7 |
Issuance of 15,793 Common Shares |  |  | 0.9 |  |  |  |  |  |  |  | 0.9 |
Balance at September 30, 2019 |  | $ | 281.7 |  |  | $ | 88.1 |  |  | $ | 369.8 |
Nine Months Ended September 30, 2018 |  |  |  |  |  |  |  |  |  |  |  |
Balance at January 1, 2018 |  | $ | 275.8 |  |  | $ | 60.8 |  |  | $ | 336.6 |
Net Income |  |  |  |  |  |  | 22.0 |  |  |  | 22.0 |
Dividends on Common Shares ($1.095 per share) |  |  |  |  |  |  | (16.3 | ) |  |  | (16.3 | )
Stock Compensation Plans |  |  | 1.5 |  |  |  |  |  |  |  | 1.5 |
Issuance of 19,700 Common Shares |  |  | 1.0 |  |  |  |  |  |  |  | 1.0 |
Balance at September 30, 2018 |  | $ | 278.3 |  |  | $ | 66.5 |  |  | $ | 344.8 |

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)
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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., which the Company sold in the first quarter of 2019, were wholly-owned 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), which the Company divested of in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. Usource provided brokering and advisory services to large commercial and industrial customers in the northeastern United States. See additional discussion of the divestiture of Usource
below.
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, 2019 are not necessarily indicative of results to be expected for the year ending December 31, 2019. 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, 2018, as filed with the Securities and Exchange Commission (SEC) on January 31, 2019, for a description of the Company’s Basis of Presentation.
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Divestiture of Non-Regulated Business Subsidiary –
On March 1, 2019, the Company divested of its
non-regulated
energy brokering and advisory business subsidiary, Usource. The Company recognized an
after-tax
net gain of approximately $9.8 million on this divestiture in the first quarter of 2019. The
pre-tax
net gain of approximately $13.4 million on this divestiture is included in Other Income (Expense), Net on the Consolidated Statements of Earnings for the nine months ended September 30, 2019, while the income taxes associated with this transaction of $3.6 million are included in the Provision For Income Taxes.
Utility Revenue Recognition
–
Gas Operating Revenues and Electric Operating Revenues consist of billed and unbilled revenue and revenue from rate adjustment mechanisms. Billed and unbilled revenue includes delivery revenue and pass-through revenue, recognized according to tariffs approved by federal and state regulatory commissions which determine the amount of revenue the Company will record for these items. Revenue from rate adjustment mechanisms is accrued revenue, recognized in connection with rate adjustment mechanisms, and authorized by regulators for recognition in the current period for future cash recoveries from, or credits to, customers.
Billed and unbilled revenue is 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 and are then reversed in the following month when billed to customers.
A majority of the Company’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customer monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer.
The Company’s billed and unbilled revenue meets the definition of “revenues from contracts with customers” as defined in ASU
2014-09.
Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in Accounting Standards Codification (ASC)
980-605-25-3,
as the Company has the ability to adjust rates in the future as a result of past activities or completed events. ASU
2014-09
requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.
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In the following tables, revenue is classified by the types of goods/services rendered and market/customer type.

|  | Three Months Ended September 30, 2019 |
Gas and Electric Operating Revenues ($ millions): |  | Gas |  |  | Electric |  |  | Total |
Billed and Unbilled Revenue: |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 6.9 |  |  | $ | 31.3 |  |  | $ | 38.2 |
C&I |  |  | 12.5 |  |  |  | 24.5 |  |  |  | 37.0 |
Other |  |  | 1.1 |  |  |  | 1.5 |  |  |  | 2.6 |
Total Billed and Unbilled Revenue |  |  | 20.5 |  |  |  | 57.3 |  |  |  | 77.8 |
Rate Adjustment Mechanism Revenue |  |  | 4.4 |  |  |  | 3.1 |  |  |  | 7.5 |
Total Gas and Electric Operating Revenues |  | $ | 24.9 |  |  | $ | 60.4 |  |  | $ | 85.3 |
|  | Three Months Ended September 30, 2018 |
Gas and Electric Operating Revenues ($ millions): |  | Gas |  |  | Electric |  |  | Total |
Billed and Unbilled Revenue: |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 6.6 |  |  | $ | 33.6 |  |  | $ | 40.2 |
C&I |  |  | 11.9 |  |  |  | 25.3 |  |  |  | 37.2 |
Other |  |  | 1.1 |  |  |  | 2.0 |  |  |  | 3.1 |
Total Billed and Unbilled Revenue |  |  | 19.6 |  |  |  | 60.9 |  |  |  | 80.5 |
Rate Adjustment Mechanism Revenue |  |  | 6.1 |  |  |  | 0.5 |  |  |  | 6.6 |
Total Gas and Electric Operating Revenues |  | $ | 25.7 |  |  | $ | 61.4 |  |  | $ | 87.1 |
|  | Nine Months Ended September 30, 2019 |
Gas and Electric Operating Revenues ($ millions): |  | Gas |  |  | Electric |  |  | Total |
Billed and Unbilled Revenue: |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 61.4 |  |  | $ | 94.8 |  |  | $ | 156.2 |
C&I |  |  | 89.5 |  |  |  | 72.2 |  |  |  | 161.7 |
Other |  |  | 9.1 |  |  |  | 5.8 |  |  |  | 14.9 |
Total Billed and Unbilled Revenue |  |  | 160.0 |  |  |  | 172.8 |  |  |  | 332.8 |
Rate Adjustment Mechanism Revenue |  |  | (16.1 | ) |  |  | 4.2 |  |  |  | (11.9 | )
Total Gas and Electric Operating Revenues |  | $ | 143.9 |  |  | $ | 177.0 |  |  | $ | 320.9 |

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|  | Nine Months Ended September 30, 2018 |
Gas and Electric Operating Revenues ($ millions): |  | Gas |  |  | Electric |  |  | Total |
Billed and Unbilled Revenue: |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 58.3 |  |  | $ | 95.6 |  |  | $ | 153.9 |
C&I |  |  | 84.7 |  |  |  | 74.1 |  |  |  | 158.8 |
Other |  |  | 8.1 |  |  |  | 6.5 |  |  |  | 14.6 |
Total Billed and Unbilled Revenue |  |  | 151.1 |  |  |  | 176.2 |  |  |  | 327.3 |
Rate Adjustment Mechanism Revenue |  |  | (3.7 | ) |  |  | (8.6 | ) |  |  | (12.3 | )
Total Gas and Electric Operating Revenues |  | $ | 147.4 |  |  | $ | 167.6 |  |  | $ | 315.0 |

Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded as an increase or a decrease in Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases that the Company files with the Massachusetts Department of Public Utilities (MDPU). The Company estimates that revenue decoupling applies to approximately
27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.
Other Operating Revenue – Non-regulated – Other Operating Revenue – Non-regulated –
Other Operating Revenue consists solely of
revenue from Usource, Unitil’s
non-regulated
subsidiary, which, as discussed previously, the Company divested of on March 1, 2019. Usource conducted its business activities as a broker of competitive energy services. Usource did not take title to the electric and gas commodities which were the subject of the brokerage contracts. The Company recorded energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource partnered with certain entities to facilitate these brokerage services and paid these entities a fee under revenue sharing agreements.
Income Taxes –
The Company is subject to Federal and State income taxes as well as various other business taxes. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with the Financial Accounting Standards Board (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.
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Cash and Cash Equivalents
–
Cash and Cash Equivalents include 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, less credit amounts that are based on the Company’s credit rating. As of September 30, 2019, September 30, 2018 and December 31, 2018, the Unitil subsidiaries had deposited $3.5 million, $3.2 million and $3.5 million, respectively to satisfy their
ISO-NE
obligations.
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, the electric and gas divisions of Fitchburg are 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 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.
The Allowance for Doubtful Accounts as of September 30, 2019, September 30, 2018 and December 31, 2018, which is included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows:

($ millions) |  |  |  |  |  |
|  | September 30, |  |  | December 31, |
|  | 2019 |  |  | 2018 |  |  | 2018 |
Allowance for Doubtful Accounts |  | $ | 1.0 |  |  | $ | 1.2 |  |  | $ | 1.3 |

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, 2019, September 30, 2018 and December 31, 2018.

|  | September 30, |  |  | December 31, |
Accrued Revenue ($ millions) |  | 2019 |  |  | 2018 |  |  | 2018 |
Regulatory Assets – Current |  | $ | 24.9 |  |  | $ | 26.4 |  |  | $ | 41.3 |
Unbilled Revenues |  |  | 10.4 |  |  |  | 9.6 |  |  |  | 13.4 |
Total Accrued Revenue |  | $ | 35.3 |  |  | $ | 36.0 |  |  | $ | 54.7 |

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, 2019, September 30, 2018 and December 31, 2018.
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|  | September 30, |  |  | December 31, |
Exchange Gas Receivable ($ millions) |  | 2019 |  |  | 2018 |  |  | 2018 |
Northern Utilities |  | $ | 8.0 |  |  | $ | 9.5 |  |  | $ | 7.5 |
Fitchburg |  |  | 0.6 |  |  |  | 0.6 |  |  |  | 0.6 |
Total Exchange Gas Receivable |  | $ | 8.6 |  |  | $ | 10.1 |  |  | $ | 8.1 |

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, 2019, September 30, 2018 and December 31, 2018.

|  | September 30, |  |  | December 31, |
Gas Inventory ($ millions) |  | 2019 |  |  | 2018 |  |  | 2018 |
Natural Gas |  | $ | 0.4 |  |  | $ | 0.4 |  |  | $ | 0.3 |
Propane |  |  | 0.3 |  |  |  | 0.4 |  |  |  | 0.4 |
Liquefied Natural Gas & Other |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 0.1 |
Total Gas Inventory |  | $ | 0.8 |  |  | $ | 0.9 |  |  | $ | 0.8 |

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, 2019, September 30, 2018 and December 31, 2018, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $98.4 million, $91.2 million, and $90.7 million, respectively.
Leases –
On January 1, 2019, the Company adopted ASU No.
2016-02,
“Leases (Topic 842)”
.
The new standard requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows the Company to carryforward the historical lease classification. The Company also elected the practical expedient related to land easements, allowing the Company to carry forward its current accounting treatment for land easements on existing agreements. The Company made an accounting policy election to keep leases with an initial term of 12 months or less off of the balance sheet. The Company recognizes those lease payments in the Consolidated Statements of Earnings on a straight-line basis over the lease term. The adoption of the standard resulted in recognition of approximately $4.2 million of lease assets and lease liabilities as of January 1, 2019 on the Company’s Consolidated Balance Sheets. The Company’s adoption of the standard did not have a material effect on its Consolidated Statements of Earnings and Consolidated Statements of Cash Flows. See additional discussion below in the “Leases” section of Note 4 to the Consolidated Financial Statements.
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
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(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.

|  | September 30, |  |  | December 31, |
Regulatory Assets consist of the following ($ millions) |  | 2019 |  |  | 2018 |  |  | 2018 |
Retirement Benefits |  | $ | 74.0 |  |  | $ | 88.0 |  |  | $ | 72.0 |
Energy Supply & Other Rate Adjustment Mechanisms |  |  | 20.6 |  |  |  | 24.8 |  |  |  | 38.4 |
Deferred Storm Charges |  |  | 5.0 |  |  |  | 6.3 |  |  |  | 6.3 |
Environmental |  |  | 8.0 |  |  |  | 8.9 |  |  |  | 7.9 |
Income Taxes |  |  | 4.3 |  |  |  | 5.9 |  |  |  | 5.7 |
Other |  |  | 11.7 |  |  |  | 4.1 |  |  |  | 10.0 |
Total Regulatory Assets |  |  | 123.6 |  |  |  | 138.0 |  |  |  | 140.3 |
Less: Current Portion of Regulatory Assets (1) |  |  | 24.9 |  |  |  | 26.4 |  |  |  | 41.3 |
Regulatory Assets – noncurrent |  | $ | 98.7 |  |  | $ | 111.6 |  |  | $ | 99.0 |

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

|  | September 30, |  |  | December 31, |
Regulatory Liabilities consist of the following ($ millions) |  | 2019 |  |  | 2018 |  |  | 2018 |
Income Taxes (Note 8) |  | $ | 47.6 |  |  | $ | 47.9 |  |  | $ | 47.0 |
Energy Supply & Other Rate Adjustment Mechanisms |  |  | 13.5 |  |  |  | 12.2 |  |  |  | 11.5 |
Total Regulatory Liabilities |  |  | 61.1 |  |  |  | 60.1 |  |  |  | 58.5 |
Less: Current Portion of Regulatory Liabilities |  |  | 14.4 |  |  |  | 12.2 |  |  |  | 11.5 |
Regulatory Liabilities—noncurrent |  | $ | 46.7 |  |  | $ | 47.9 |  |  | $ | 47.0 |

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. As of September 30, 2019 there are
$5.8
million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years which regulators have authorized recovery of, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.
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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 currently qualify as a derivative instrument under the guidance set forth in the FASB Codification.
As discussed below in the “Fitchburg – Massachusetts RFP’s” section of Note 6 (Regulatory Matters), Fitchburg has entered into power purchase agreements for which contingencies exist. Until these contingencies are satisfied, these contracts will not qualify for derivative accounting. The Company believes that the power purchase obligations under these long-term contracts will have a material impact on the contractual obligations and regulatory assets of Fitchburg, once they qualify for derivative accounting.
Investments in Marketable Securities
–
T
he Company has a trust through which it invests in a variety of equity and fixed income mutual funds. These funds are intended to satisfy obligations under the Company’s SERP Plan (See further discussion of the SERP Plan in Note 9.)
At September 30, 2019, September 30, 2018 and December 31, 2018, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.9 million, $5.3 million and $4.8 million, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense (Income), Net.

|  | September 30, |  |  | December 31, |
Fair Value of Marketable Securities ($ millions) |  | 2019 |  |  | 2018 |  |  | 2018 |
Equity Funds |  | $ | — |  |  | $ | 3.0 |  |  | $ | — |
Fixed Income Funds |  |  | — |  |  |  | 2.3 |  |  |  | — |
Money Market Funds |  |  | 5.9 |  |  |  | — |  |  |  | 4.8 |
Total Marketable Securities |  | $ | 5.9 |  |  | $ | 5.3 |  |  | $ | 4.8 |

The Company also sponsors the Unitil Corporation Deferred Compensation Plan (the “DC Plan”). The DC Plan is a
non-qualified
deferred compensation plan that provides a vehicle for participants to accumulate
tax-deferred
savings to supplement retirement income. The DC Plan, which was effective January 1, 2019, is open to senior management or other highly compensated employees as determined by the Company’s Board of Directors, and may also be used for recruitment and retention purposes for newly hired senior executives. The DC Plan design mirrors the Company’s Tax Deferred Savings and Investment Plan formula, but provides for contributions on compensation above the IRS limit, which will allow participants to defer up to 85% of base salary, and up to 85% of any cash incentive for retirement. The Company may also elect to make discretionary contributions on behalf of any participant in an amount determined by the Company’s Board of Directors. A trust has been established to invest the funds associated with the DC Plan.
At September 30, 2019, September 30, 2018 and December 31, 2018, the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $0.1 million, $0 and $0, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.
Changes in the fair value of these investments are recorded in Other Expense, Net.​​​​​​​
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|  | September 30, |  |  | December 31, |
Fair Value of Marketable Securities ($ millions) |  | 2019 |  |  | 2018 |  |  | 2018 |
Equity Funds |  | $ | — |  |  | $ | — |  |  | $ | — |
Money Market Funds |  |  | 0.1 |  |  |  | — |  |  |  | — |
Total Marketable Securities |  | $ | 0.1 |  |  | $ | — |  |  | $ | — |

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

|  | September 30, |  |  | December 31, |
Energy Supply Obligations ($ millions) |  | 2019 |  |  | 2018 |  |  | 2018 |
Current: |  |  |  |  |  |  |  |  |  |  |  |
Exchange Gas Obligation |  | $ | 8.0 |  |  | $ | 9.5 |  |  | $ | 7.5 |
Renewable Energy Portfolio Standards |  |  | 4.2 |  |  |  | 5.2 |  |  |  | 5.6 |
Power Supply Contract Divestitures |  |  | 0.3 |  |  |  | 0.3 |  |  |  | 0.3 |
Total Energy Supply Obligations – Current |  |  | 12.5 |  |  |  | 15.0 |  |  |  | 13.4 |
Noncurrent: |  |  |  |  |  |  |  |  |  |  |  |
Power Supply Contract Divestitures |  |  | 0.4 |  |  |  | 0.7 |  |  |  | 0.6 |
Total Energy Supply Obligations |  | $ | 12.9 |  |  | $ | 15.7 |  |  | $ | 14.0 |

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 defer costs for RPS compliance which is recorded in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.
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Fitchburg has entered into long-term renewable contracts for the purchase of clean energy and/or renewable energy certificates (RECs) pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (“Green Communities Act”, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (“Energy Diversity Act”, 2016). The generating facilities associated with four of these contracts have been constructed and are now operating. Since 2017, the Company has participated in two major statewide procurements which resulted in contracts for imported hydroelectric power and associated transmission and for offshore wind generation. The contracts were approved by the MDPU in the second quarter of 2019.
Additional long-term clean energy contracts are expected in compliance with the Energy Diversity Act and An Act to Promote a Clean Energy Future (2018). Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery 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).
Recently Issued Pronouncements –
In February 2016, the FASB issued ASU No.
2016-02,
“Leases (Topic 842)”. The new standard requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than 12 months. The Company adopted the standard as of January 1, 2019. See “Leases” above in Note 1.
Other than the pronouncement discussed above, 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 would result in adjustment to or disclosure in its unaudited consolidated financial statements.
Note 2
–
Dividends Declared Per Share

Declaration Date |  | Date Paid (Payable) |  | Shareholder of Record Date |  | Dividend Amount
10/23/19 |  | 11/27/19 |  | 11/13/19 |  | $ 0.370
07/24/19 |  | 08/29/19 |  | 08/15/19 |  | $ 0.370
04/24/19 |  | 05/29/19 |  | 05/15/19 |  | $ 0.370
01/30/19 |  | 02/28/19 |  | 02/14/19 |  | $ 0.370
10/24/18 |  | 11/29/18 |  | 11/15/18 |  | $ 0.365
07/25/18 |  | 08/29/18 |  | 08/15/18 |  | $ 0.365
04/25/18 |  | 05/29/18 |  | 05/15/18 |  | $ 0.365
01/30/18 |  | 02/28/18 |  | 02/14/18 |  | $ 0.365

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note 3
–
Segment Information
The following table provides significant segment financial data for the three and nine months ended September 30, 2019 and September 30, 2018 and as of December 31, 2018 (millions):

|  | Gas |  |  | Electric |  |  | Non- Regulated |  |  | Other |  |  | Total |
Three Months Ended September 30, 2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Billed and Unbilled Revenue |  | $ | 20.5 |  |  | $ | 57.3 |  |  | $ | — |  |  | $ | — |  |  | $ | 77.8 |
Rate Adjustment Mechanism Revenue |  |  | 4.4 |  |  |  | 3.1 |  |  |  | — |  |  |  | — |  |  |  | 7.5 |
Other Operating Revenue – Non-Regulated |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Total Operating Revenues |  | $ | 24.9 |  |  | $ | 60.4 |  |  | $ | — |  |  | $ | — |  |  | $ | 85.3 |
Segment Profit |  |  | (3.9 | ) |  |  | 4.4 |  |  |  | — |  |  |  | 1.8 |  |  |  | 2.3 |
Capital Expenditures |  |  | 26.9 |  |  |  | 9.2 |  |  |  | — |  |  |  | 1.9 |  |  |  | 38.0 |
Three Months Ended September 30, 2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Billed and Unbilled Revenue |  | $ | 19.6 |  |  | $ | 60.9 |  |  | $ | — |  |  | $ | — |  |  | $ | 80.5 |
Rate Adjustment Mechanism Revenue |  |  | 6.1 |  |  |  | 0.5 |  |  |  | — |  |  |  | — |  |  |  | 6.6 |
Other Operating Revenue – Non-Regulated |  |  | — |  |  |  | — |  |  |  | 1.1 |  |  |  | — |  |  |  | 1.1 |
Total Operating Revenues |  | $ | 25.7 |  |  | $ | 61.4 |  |  | $ | 1.1 |  |  | $ | — |  |  | $ | 88.2 |
Segment Profit (Loss) |  |  | (3.2 | ) |  |  | 4.5 |  |  |  | 0.3 |  |  |  | 1.2 |  |  |  | 2.8 |
Capital Expenditures |  |  | 30.9 |  |  |  | 7.2 |  |  |  | — |  |  |  | 1.0 |  |  |  | 39.1 |

Nine Months Ended September 30, 2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Billed and Unbilled Revenue |  | $ | 160.0 |  |  | $ | 172.8 |  |  | $ | — |  |  | $ | — |  |  | $ | 332.8 |
Rate Adjustment Mechanism Revenue |  |  | (16.1 | ) |  |  | 4.2 |  |  |  | — |  |  |  | — |  |  |  | (11.9 | )
Other Operating Revenue – Non-Regulated |  |  | — |  |  |  | — |  |  |  | 0.9 |  |  |  | — |  |  |  | 0.9 |
Total Operating Revenues |  | $ | 143.9 |  |  | $ | 177.0 |  |  | $ | 0.9 |  |  | $ | — |  |  | $ | 321.8 |
Segment Profit |  |  | 10.1 |  |  |  | 9.7 |  |  |  | 10.2 |  |  |  | 2.8 |  |  |  | 32.8 |
Capital Expenditures |  |  | 48.3 |  |  |  | 24.1 |  |  |  | — |  |  |  | 4.3 |  |  |  | 76.7 |
Segment Assets |  |  | 780.7 |  |  |  | 507.6 |  |  |  | 0.3 |  |  |  | 21.1 |  |  |  | 1,309.7 |
Nine Months Ended September 30, 2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Billed and Unbilled Revenue |  | $ | 151.1 |  |  | $ | 176.2 |  |  | $ | — |  |  | $ | — |  |  | $ | 327.3 |
Rate Adjustment Mechanism Revenue |  |  | (3.7 | ) |  |  | (8.6 | ) |  |  | — |  |  |  | — |  |  |  | (12.3 | )
Other Operating Revenue – Non-Regulated |  |  | — |  |  |  | — |  |  |  | 3.5 |  |  |  | — |  |  |  | 3.5 |
Total Operating Revenues |  | $ | 147.4 |  |  | $ | 167.6 |  |  | $ | 3.5 |  |  | $ | — |  |  | $ | 318.5 |
Segment Profit |  |  | 9.1 |  |  |  | 10.2 |  |  |  | 0.9 |  |  |  | 1.8 |  |  |  | 22.0 |
Capital Expenditures |  |  | 53.1 |  |  |  | 20.8 |  |  |  | — |  |  |  | 2.4 |  |  |  | 76.3 |
Segment Assets |  |  | 730.0 |  |  |  | 485.7 |  |  |  | 6.6 |  |  |  | 42.2 |  |  |  | 1,264.5 |

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Note 4
–
Debt AND FINANCING ARRANGEMENTS
Details on long-term debt at September 30, 2019, Sept
e
mber 30, 2018 and December 31, 2018 are shown below:

($ millions) |  | September 30, |  |  | December 31, |
|  | 2019 |  |  | 2018 |  |  | 2018 |
Unitil Corporation: |  |  |  |  |  |  |  |  |  |  |  |
6.33% Senior Notes, Due May 1, 2022 |  | $ | 20.0 |  |  | $ | 20.0 |  |  | $ | 20.0 |
3.70% Senior Notes, Due August 1, 2026 |  |  | 30.0 |  |  |  | 30.0 |  |  |  | 30.0 |
Unitil Energy First Mortgage Bonds: |  |  |  |  |  |  |  |  |  |  |  |
5.24% Senior Secured Notes, Due March 2, 2020 |  |  | 5.0 |  |  |  | 10.0 |  |  |  | 10.0 |
8.49% Senior Secured Notes, Due October 14, 2024 |  |  | 6.0 |  |  |  | 7.5 |  |  |  | 6.0 |
6.96% Senior Secured Notes, Due September 1, 2028 |  |  | 18.0 |  |  |  | 20.0 |  |  |  | 20.0 |
8.00% Senior Secured Notes, Due May 1, 2031 |  |  | 15.0 |  |  |  | 15.0 |  |  |  | 15.0 |
6.32% Senior Secured Notes, Due September 15, 2036 |  |  | 15.0 |  |  |  | 15.0 |  |  |  | 15.0 |
4.18% Senior Secured Notes, Due November 30, 2048 |  |  | 30.0 |  |  |  | — |  |  |  | 30.0 |
Fitchburg: |  |  |  |  |  |  |  |  |  |  |  |
6.75% Senior Notes, Due November 30, 2023 |  |  | 5.7 |  |  |  | 7.6 |  |  |  | 5.7 |
6.79% Senior Notes, Due October 15, 2025 |  |  | 10.0 |  |  |  | 10.0 |  |  |  | 10.0 |
3.52% Senior Notes, Due November 1, 2027 |  |  | 10.0 |  |  |  | 10.0 |  |  |  | 10.0 |
7.37% Senior Notes, Due January 15, 2029 |  |  | 12.0 |  |  |  | 12.0 |  |  |  | 12.0 |
5.90% Senior Notes, Due December 15, 2030 |  |  | 15.0 |  |  |  | 15.0 |  |  |  | 15.0 |
7.98% Senior Notes, Due June 1, 2031 |  |  | 14.0 |  |  |  | 14.0 |  |  |  | 14.0 |
4.32% Senior Notes, Due November 1, 2047 |  |  | 15.0 |  |  |  | 15.0 |  |  |  | 15.0 |
Northern Utilities: |  |  |  |  |  |  |  |  |  |  |  |
6.95% Senior Notes, Due December 3, 2018 |  |  | — |  |  |  | 10.0 |  |  |  | — |
5.29% Senior Notes, Due March 2, 2020 |  |  | 8.2 |  |  |  | 16.6 |  |  |  | 16.6 |
3.52% Senior Notes, Due November 1, 2027 |  |  | 20.0 |  |  |  | 20.0 |  |  |  | 20.0 |
7.72% Senior Notes, Due December 3, 2038 |  |  | 50.0 |  |  |  | 50.0 |  |  |  | 50.0 |
4.42% Senior Notes, Due October 15, 2044 |  |  | 50.0 |  |  |  | 50.0 |  |  |  | 50.0 |
4.32% Senior Notes, Due November 1, 2047 |  |  | 30.0 |  |  |  | 30.0 |  |  |  | 30.0 |
4.04% Senior Notes, Due September 12, 2049 |  |  | 40.0 |  |  |  | — |  |  |  | — |
Granite State: |  |  |  |  |  |  |  |  |  |  |  |
7.15% Senior Notes, Due December 15, 2018 |  |  | — |  |  |  | 3.3 |  |  |  | — |
3.72% Senior Notes, Due November 1, 2027 |  |  | 15.0 |  |  |  | 15.0 |  |  |  | 15.0 |
Total Long-Term Debt |  |  | 433.9 |  |  |  | 396.0 |  |  |  | 409.3 |
Less: Unamortized Debt Issuance Costs |  |  | 3.5 |  |  |  | 3.1 |  |  |  | 3.5 |
Total Long-Term Debt, net of Unamortized Debt Issuance Costs |  |  | 430.4 |  |  |  | 392.9 |  |  |  | 405.8 |
Less: Current Portion (1) |  |  | 19.5 |  |  |  | 31.8 |  |  |  | 18.4 |
Total Long-term Debt, Less Current Portion |  | $ | 410.9 |  |  | $ | 361.1 |  |  | $ | 387.4 |

(1) | The Current Portion of Long-Term Debt ​​​​​​​includes sinking ​​​​​​​fund payments.

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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, |
|  | 2019 |  |  | 2018 |  |  | 2018 |
Estimated Fair Value of Long-Term Debt |  | $ | 495.1 |  |  | $ | 418.7 |  |  | $ | 422.0 |

On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement and related documents (collectively, the “Credit Facility”) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit facility. The Credit Facility extends to July 25, 2023, subject to two
one-year
extensions under certain circumstances, and has a borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company 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 1.125%. The Company may increase the borrowing limit under the Credit Facility by up to $50 million under certain circumstances.
The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $187.1 million for the nine months ended September 30, 2019. Total gross repayments were $220.7 million for the nine months ended September 30, 2019. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30 2019, September 30, 2018 and December 31, 2018:

|  | Revolving Credit Facility ($ millions) |
|  | September 30, |  |  | December 31, |
|  | 2019 |  |  | 2018 |  |  | 2018 |
Limit |  | $ | 120.0 |  |  | $ | 120.0 |  |  | $ | 120.0 |
Short-Term Borrowings Outstanding |  |  | 49.2 |  |  |  | 69.1 |  |  |  | 82.8 |
Letter of Credit Outstanding |  |  | 0.1 |  |  |  | — |  |  |  | — |
Available |  | $ | 70.7 |  |  | $ | 50.9 |  |  | $ | 37.2 |

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, the
Company’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on the Company’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 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 Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2019, September 30, 2018 and December 31, 2018, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.
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The Company believes the future operating cash flows of the Company, along with its existing borrowing availability and access to financial markets for the issuance of new long-term debt, will be sufficient to meet any working capital and future operating requirements, and capital investment forecast opportunities.
The average interest rates on all short-term borrowings and intercompany money pool transactions were 3.4% and 3.3%
for the three months ended September 30, 2019 and September 30, 2018, respectively. The average interest rates on all short-term borrowings and intercompany money pool transactions were
3.6% and 3.2%
for the nine months ended September 30, 2019 and September 30, 2018, respectively. The average interest rate on all short-term borrowings for the twelve months ended December 31, 2018 was
3.3%.
As discussed previously, the Company divested of its
non-regulated
subsidiary business, Usource, in the first quarter of 2019. The Company used the net proceeds of $9.8 million from this divestiture for general corporate purposes.
On September 12, 2019, Northern Utilities issued $40 million of Notes due 2049 at 4.04%. Northern Utilities used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.2 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.
On November 30, 2018 Unitil Energy issued $30 million of First Mortgage Bonds due November 30, 2048 at 4.18%. Unitil Energy used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $0.5 million of costs associated with these issuances have been netted against long-term debt for presentation purposes on the Consolidated Balance Sheets.
In April 2014, Unitil Service Corp. entered into a financing arrangement, structured as a capital lease obligation, for various information systems and technology equipment. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. This capital lease was paid off in the second quarter of 2019.
Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services. Unitil Corporation and Granite State are currently rated “Baa2”, and Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1” by Moody’s Investors Services.
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 $8.1 million, $9.6 million and $8.4 million of natural gas storage inventory at September 30, 2019, September 30, 2018 and December 31, 2018, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2019 and payable in
October 2019 is
$0.1 million
and is recorded in Accounts Payable at September 30, 2019. The amount of natural gas inventory released in September 2018 and payable in October 2018 was
$0.1 million and was recorded in Accounts Payable at September 30, 2018. The amount of natural gas inventory released in December 2018 and payable in January 2019 was $0.9 million and was recorded in Accounts Payable at December 31, 2018.
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Guarantees
The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of September 30, 2019, there were approximately $4.3 million of guarantees outstanding.
Leases
Unitil’s subsidiaries lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements.
Total rental expense under operating leases charged to operations for the three months ended September 30, 2019 and 2018 amounted to $0.4 million and $0.4 million, respectively. Total rental expense under operating leases charged to operations for the nine months ended September 30, 2019 and 2018 amounted to $1.1 million and $1.4 million, respectively.
The balance sheet classification of the Company’s lease obligations was as follows:

|  | September 30, |  |  | December 31, |
Lease Obligations ($ millions) |  | 2019 |  |  | 2018 |  |  | 2018 |
Operating Lease Obligations: |  |  |  |  |  |  |  |  |  |  |  |
Other Current Liabilities (current portion) |  | $ | 1.2 |  |  | $ | — |  |  | $ | — |
Other Noncurrent Liabilities (long-term portion) |  |  | 3.0 |  |  |  | — |  |  |  | — |
Total Operating Lease Obligations |  |  | 4.2 |  |  |  | — |  |  |  | — |
Capital Lease Obligations: |  |  |  |  |  |  |  |  |  |  |  |
Other Current Liabilities (current portion) |  |  | 0.3 |  |  |  | 3.1 |  |  |  | 3.1 |
Other Noncurrent Liabilities (long-term portion) |  |  | 0.3 |  |  |  | 3.4 |  |  |  | 2.7 |
Total Capital Lease Obligations |  |  | 0.6 |  |  |  | 6.5 |  |  |  | 5.8 |
Total Lease Obligations |  | $ | 4.8 |  |  | $ | 6.5 |  |  | $ | 5.8 |

Cash paid for amounts included in the measurement of operating lease obligations for the nine months ended September 30, 2019 was $1.1 million and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows.
Assets under capital leases amounted to approximately $1.3 million, $15.0 million and $15.0 million as of September 30, 2019, September 30, 2018 and December 31, 2018, respectively, less accumulated amortization of $0.6 million, $2.1 million and $1.7 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.
The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of September 30, 2019. The payments for capital leases consist of $0.3​​​​​​​​​​​​​​ million of current capital lease obligations, which are included in Other​​​​​​​ Current Liabilities and $
0.3
million of noncurrent capital lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2019.
The payments for operating leases consist of $1.2 million of current operating lease obligations, which are included in Other Current Liabilities and $3.0 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of September 30, 2019.
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Lease Payments ($000’s) Year Ending December 31, |  |  |  | Operating Leases |  |  | Capital Leases |
Rest of 2019 |  |  |  | $ | 356 |  |  | $ | 80 |
2020 |  |  |  |  | 1,338 |  |  |  | 262 |
2021 |  |  |  |  | 1,168 |  |  |  | 161 |
2022 |  |  |  |  | 887 |  |  |  | 97 |
2023 |  |  |  |  | 587 |  |  |  | 55 |
2024-2028 |  |  |  |  | 400 |  |  |  | — |
Total Payments |  |  |  |  | 4,736 |  |  |  | 655 |
Less: Interest |  |  |  |  | 507 |  |  |  | 35 |
Amount of Lease Obligations Recorded on Consolidated Balance Sheets |  | $ | 4,229 |  |  | $ | 620 |

Operating lease obligations are based on the net present value of the remaining lease payments over the remaining lease term. In determining the present value of lease payments, the Company used the interest rate stated in each lease agreement. As of September 30, 2019, the weighted average remaining lease term is 4.0 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.3%.
Disclosures Related to Periods Prior to the Adoption of ASU NO. 2016-02 – Leases (See Note 1).
The payment amounts in the following table, which are as of December 31, 2018, would not differ substantially from the payment amounts as of September 30, 2018.

Lease Payments ($000’s) Year Ending December 31, |  |  |  | Operating Leases |  |  | Capital Leases |
2019 |  |  |  | $ | 1,372 |  |  | $ | 3,069 |
2020 |  |  |  |  | 1,138 |  |  |  | 2,535 |
2021 |  |  |  |  | 969 |  |  |  | 93 |
2022 |  |  |  |  | 689 |  |  |  | 32 |
2023 |  |  |  |  | 390 |  |  |  | 14 |
2024-2028 |  |  |  |  | 120 |  |  |  | — |
Total Payments |  |  |  | $ | 4,678 |  |  | $ | 5,743 |

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 14,872,011, 14,876,955 and 14,925,898 shares of common stock outstanding at September 30, 2018, December 31, 2018 and September 30, 2019, respectively.
Dividend Reinvestment and Stock Purchase Plan –
During the first nine months of 2019, the Company sold 15,793 shares of its common stock, at an average price of $56.29 per share, in
connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $889,000. 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.
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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. The Company may deduct or withhold, or require a participant to remit to the Company, an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with an Award. For purposes of compensation expense, Restricted Shares vest immediately upon a participant becoming eligible for retirement, as defined in the Stock Plan. 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 29, 2019, 33,150 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.6 million. There were 50,917 and 49,581
non-vested
shares under the Stock Plan as of September 30, 2019 and 2018, respectively. The weighted average grant date fair value of these shares was $46.41 and $41.96, respectively. The compensation expense associated with the issuance of shares under the Stock
Plan is being recognized over the vesting period and was $2.2 million and $2.1 million for the nine months ended September 30, 2019 and 2018, respectively. At September 30, 2019, there was approximately $
0.8
million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.7 years. There were
no
forfeitures and no cancellations under the Stock Plan during the nine months ended September 30, 2019.
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Restricted Stock Units
Non-management
members of the Company’s Board of Directors (Directors) may elect to receive the equity portion of their annual retainer in the form of 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, 2019 in conjunction with the Stock Plan is presented in the following table:

Restricted Stock Units (Equity Portion) |
|  | Units |  |  | Weighted Average Stock Price |
Restricted Stock Units as of December 31, 2018 |  |  | 61,789 |  |  | $ | 38.25 |
Restricted Stock Units Granted |  |  | — |  |  |  | — |
Dividend Equivalents Earned |  |  | 1,210 |  |  | $ | 57.08 |
Restricted Stock Units Settled |  |  | — |  |  |  | — |
Restricted Stock Units as of September 30, 2019 |  |  | 62,999 |  |  | $ | 38.61 |

There were 53,454 Restricted Stock Units outstanding as of September 30, 2018 with a weighted average stock price of $36.47.
On October 1, 2019, there were 9,918 fully-vested Restricted Stock Units issued to members of the Company’s Board of Directors.
Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of September 30, 2019, September 30, 2018 and December 31, 2018 is $1.7 million, $1.2 million and $1.3 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.
Preferred Stock
There was $0.2 million, or 1,887 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2019.
There was $0.2 million,
or 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2018 and December 31, 2018. 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, 2019 and September 30, 2018, 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, 2018 as filed with the Securities and Exchange Commission on january 31, 2019.
Tax Cuts and Jobs Act of 2017
On December
22
,
2017
, the Tax Cuts and Jobs Act of
2017
(TCJA) was signed into law. Among other things, the TCJA substantially reduced the corporate income tax rate to
21
percent, effective January
1
,
2018
.
Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, issued orders directing how the tax law changes were to be reflected in rates. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State. More recently, on November 15, 2018, the FERC issued a Notice of Proposed Rulemaking and a Policy Statement to address the TCJA’s effects on the Accumulated Deferred Income Taxes (ADIT) on transmission rates. Under the proposed rules all public utilities with transmission formula rates, including Fitchburg, would be required to: (1) include mechanisms to deduct any excess ADIT from or add any deficient ADIT to their rate bases; (2) include mechanisms in those rates that would raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (3) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. The Company believes that these matters are substantially resolved and will not have a material impact on its financial position, operating results, or cash flows.
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Rate Case Activity
Northern Utilities – Base Rates – Maine –
On June 28, 2019, Northern Utilities filed a petition with the MPUC seeking an increase to annual base operating revenues of $7.0 million. If approved as filed, the requested increase will result in a 7
percent increase over the Company’s test-year operating revenues. The intended rate effective date is April 1, 2020. In addition, Northern Utilities is requesting approval to implement a multi-year alternative rate mechanism (“Capital Investment Recovery Adjustment” or “CIRA”) that will allow for future changes to the Company’s distribution rates and mitigate the need to file a general rate case. The CIRA is designed to recover the costs of replacing, relocating and abandoning existing facilities and other operational and safety-related system improvements. The first annual adjustment is proposed for November 1, 2020, to recover the Company’s 2019 investment cost of eligible facilities and improvements. This matter remains pending.
Northern Utilities – Targeted Infrastructure Replacement Adjustment (TIRA) – Maine –
The settlement in Northern Utilities’ Maine division’s 2013 rate case allowed the Company to implement a 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, including the Company’s Cast Iron Replacement Program (CIRP).
In its Final Order issued on February 28, 2018 for Northern Utilities’ last base rate case, the MPUC approved an extension of the TIRA mechanism, for an additional
eight
-year period, which will allow for annual rate adjustments through the end of the CIRP program. On May 7, 2018, the MPUC approved the Company’s request to increase its annual base rates by 2.4%, or $1.1 million, effective May 1, 2018, to recover the revenue requirements for 2017 eligible facilities. On April 17, 2019, the MPUC approved the Company’s request to increase its annual base rates by 2.1%, or $1.0 million, effective May 1, 2019, to recover the revenue requirements for 2018 eligible facilities.
Northern Utilities – Base Rates – New Hampshire
–
On May 2, 2018, the NHPUC approved a settlement agreement providing for a net annual revenue increase of $3.2 million, incorporating the effect of the TCJA, and an initial step increase to recover post-test year capital investments. The Company’s second step increase of approximately $1.4 million of annual revenue was approved by the NHPUC, effective May 1, 2019, to recover eligible capital investments in 2018. According to the terms of the settlement agreement, Northern Utilities’ next distribution base rate case shall be based on an historic test year of no earlier than twelve months ending December 31, 2020.
Unitil Energy – Base Rates –
On April 20, 2017 the NHPUC issued its final order providing for a permanent increase of $4.1 million,
effective May 1, 2017, followed by two annual rate step adjustments to recover the revenue requirements associated with certain capital expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s first step increase, effective May 1, 2018. On April 22, 2019, the NHPUC approved Unitil Energy’s second and final step adjustment, providing for a revenue increase of approximately
$340,000
,
effective May 1, 2019.
Fitchburg – Base Rates – Electric –
Fitchburg’s base rates are decoupled, and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On April 3, 2019, the DPU approved Fitchburg’s cumulative revenue requirement associated with the Company’s 2015 and 2016 capital expenditures, an increase of
$0.4 million.
The increase was effective January 1, 2018. On
November 1, 2018
, Fitchburg filed its cumulative revenue requirement of $0.9 million associated with the Company’s 2015, 2016 and 2017 capital expenditures. On December 27, 2018, the filing was approved, effective January 1, 2019, subject to further investigation and reconciliation. Final approval of the 2018 filing remains pending.
On September 5, 2019, Fitchburg’s electric division filed with the MDPU a letter of intent to file for a general increase in base rates. Under MDPU precedent, a utility company is required to provide no less than a 30 day advance notice of its intent to file for a base rate increase. At this time, Fitchburg anticipates that the filing will be made during the fourth quarter 2019.
Fitchburg – Base Rates – Gas –
Pursuant to the Company’s revenue decoupling adjustment clause tariff, as approved in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather and energy efficiency impacts to the Company’s revenues. The MDPU has consistently found that the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that
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they result in just and reasonable rates. On September 5, 2019, Fitchburg’s gas division filed with the MDPU a letter of intent to file for a general increase in base rates. Under MDPU precedent, a utility company is required to provide no less than a 30 day advance notice of its intent to file for a base rate increase. At this time, Fitchburg anticipates that the filing will be made during the fourth quarter 2019.
Fitchburg – Gas System Enhancement Program –
Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31 (the “GSEP Filing”); and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred (the “GREC Filing”). The Company considers these to be routine regulatory proceedings and there are no material issues outstanding.
In an Order issued on April 30, 2019, the MDPU approved Fitchburg’s 2018 GSEP Filing and increased the annual cap on recovery. Because the amount approved for recovery, $1.6 million, still exceeded the annual cap, the Order resulted in a revenue increase of $1.0 million that went into effect on May 1, 2019, subject to reconciliation. The amount that exceeded the cap, $0.6
million, has been deferred to be recovered in a later proceeding. On May 1, 2019, the Company made its 2019 GREC Filing, seeking a waiver of the annual cap and a revenue increase of
$1.0
million. This matter remains pending.
Granite State – Base Rates –
On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which provided for no change in rates, and accounted for the effects of a capital step adjustment offset by the effect of the TCJA. The settlement was approved by FERC on June 27, 2018, and complies with the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reductions under the TCJA.
Other Matters
Fitchburg – Independent Statewide Examination of the Safety of the Commonwealth’s Gas Distribution System –
The MDPU has engaged a third-party evaluator to conduct an independent statewide examination of the safety of the gas distribution system to complement the investigation of the National Transportation Safety Board which focuses on the gas incident on September 13, 2018 in the Merrimack Valley and its potential causes. The evaluator will examine the following areas: (1) the physical integrity and safety of the gas distribution system; and (2) the operation and maintenance policies and practices of the gas companies and municipal gas companies, with respect to the Commonwealth’s gas distribution system, including recommendations for improvements. The evaluator issued a Phase 1 summary report including preliminary recommendations for the MDPU’s consideration on May 13, 2019. The investigation is
on-going
and the evaluator will produce a final report at the end of the process. The Company believes that this examination will not result in a material impact on its financial position, operating results or cash flows.
Northern Utilities / Granite State – Firm Capacity Contract
–
Northern Utilities relies on the transport of gas supply over its affiliate Granite State pipeline to serve its customers in the Maine and New Hampshire service territories, as Granite State facilitates critical upstream interconnections with interstate pipelines and third party suppliers essential to Northern Utilities’ service to its customers. Northern Utilities reserves firm capacity through a contract with Granite State, which is renewed annually. Pursuant to statutory requirements in Maine as well as the orders of the MPUC, Northern Utilities submits an annual informational report requesting approval of a
one​​​​​​​-year
extension of its
12-month
contract for firm pipeline capacity reservation, with an evergreen provision and three-month termination notification requirement. On July 11, 2019, the MPUC approved Northern Utilities’ request to extend its contract for firm transmission on its affiliate Granite State pipeline for another year, extending the current contract for the period of November 1, 2019 through October 31, 2020. The next request to the MPUC for approval to extend the transmission contract will be filed in July 2020. In New Hampshire, pursuant to statute, Northern Utilities advises the NHPUC of its annual contract renewal with Granite State, though it is not required to seek approval of the renewal.
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Reconciliation Filings –
Fitchburg, Unitil Energy and Northern Utilities each have a number of regulatory reconciling accounts which require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile costs and revenues and seek approval of any rate changes. These filings include: annual electric reconciliation filings by Fitchburg and Unitil Energy for a number of items, including default service, stranded cost changes and transmission charges; costs associated with energy efficiency programs in New Hampshire and Massachusetts, as directed by the NHPUC and MDPU; recovery of the ongoing costs of storm repairs incurred by Unitil Energy; and the actual ​​​​​​​wholesale energy costs for electric power and natural gas incurred by each of the three companies. Fitchburg, Unitil Energy and Northern Utilities have been, and remain in full compliance with all directives and orders regarding these filings. The Company considers these to be routine regulatory proceedings and there are no material issues outstanding.
Fitchburg – Massachusetts RFPs –
Pursuant to a comprehensive energy law enacted in 2016, “An Act to Promote Energy Diversity,” under Section 83C, the Massachusetts electric distribution companies (EDCs), including Fitchburg, are required to jointly solicit proposals for long term contracts for at least 400 MW’s of offshore wind energy generation by June 30, 2017, as part of a total of 1,600 MW of offshore wind the EDCs are directed to procure by June 30, 2027. Under Section 83D of the Act, the EDCs are required to jointly seek proposals for cost effective clean energy (hydro, solar and land-based wind) long-term contracts via one or more staggered solicitations for a total of 9,450,000 megawatt-hours by December 31, 2022. Unitil’s pro rata share of each of these contracts is approximately
one
percent.
The EDCs issued the RFP for Section 83D Long-Term Contracts for Qualified Clean Energy Projects in March 2017, and after selection of final projects and negotiation, final contracts for 9,554,940 MWh of Qualified Clean Energy and associated Environmental Attributes from hydroelectric generation were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the power purchase agreements, including the EDCs’ proposal to sell the energy procured under the contract into the
ISO-NE
wholesale market and to credit or charge the difference between the contract costs and the
ISO-NE
market costs to customers. The MDPU
also determined that the EDCs’ request for remuneration equal to 2.75 percent is reasonable and in the public interest. Also, the MDPU approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes that the power purchase obligations under these long-term contracts will have a material impact on the contractual obligations and regulatory assets of Fitchburg, once certain conditions and contingencies are met.
The EDCs issued the RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation in June 2017. Final selection of projects was made in May 2018, contracts were signed in July 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed two long-term contracts, each for 400MW of offshore wind energy generation with MDPU for approval. On April 12, 2019, the MDPU approved the Offshore Wind Energy Generation power purchase agreements, including the EDCs’ proposal to sell the energy procured under the contract into the
ISO-NE
wholesale market and to credit or charge the difference between the contract costs and the
ISO-NE
market costs to customers. The MDPU also determined that the EDCs’ request for remuneration equal to
2.75
percent is reasonable and in the public interest. Also, the MDPU approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes that the power purchase obligations under these long-term contracts will have a material impact on the contractual obligations and regulatory assets of Fitchburg.
The EDCs issued an RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation on May
23
, 2019. This is the second solicitation pursuant to Section 83C and with the Department’s approval of the Vineyard Wind contracts for 800 MW of offshore wind energy generation as a result of the first solicitation, the remaining obligation under 83C is to procure an additional 800 MW of offshore wind energy generation. The EDCs intend to purchase at least
400
MW of the remaining 800 MW obligation under this RFP.
Proposals were received on August 23, 2019, and selection is to occur on November 8, 2019, contracts are to be executed by December 13, 2019, and filed with the Department on January 10, 2020.
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Northern Utilities Gas Supply Cost Investigation –
The MPUC has opened an investigation into the gas supply and procurement activities of Maine local distribution companies. Northern Utilities is the first company to have its procurement practices examined, and the Company is cooperating with a consultant engaged by the MPUC to conduct this ongoing investigation. The Company believes that this investigation will not result in a material impact on its financial position, operating results or cash flows.
FERC Transmission Formula Rate Proceedings –
Pursuant to Section 206 of the Federal Power Act, there are several pending proceedings before the FERC concerning the justness and reasonableness of the Return on Equity (ROE) component of the
ISO-New
England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates. On April 14, 2017, the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating a decision of the FERC with respect to the ROE, and remanded it for further proceedings. The FERC had found that the Transmission Owners existing ROE was unlawful, and had set a new ROE. The Court found that the FERC had failed to articulate a satisfactory explanation for its orders. At this time, the ROE set in the vacated order will remain in place until further FERC action is taken. Separately, on March 15, 2018, the Transmission Owners filed a petition for review with the Court of certain orders of the FERC setting for hearing other complaints challenging the allowed return on equity component of the formula rates.
Also pending at FERC is a Section 206 proceeding concerning the justness and reasonableness of
ISO-New
England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates. On August 17, 2018 a joint settlement agreement among a number of the parties was filed with the FERC. FERC rejected the settlement agreement on May 22, 2019 and remanded the proceeding
to the Chief Administrative Law Judge to resume hearing procedures. On May
24
,
2019
the judge appointed a Dispute Resolution Facilitator to aid parties in settlement negotiations. The procedural schedule was suspended September
24
,
2019
in order to allow participants to focus on settlement negotiations. The initial decision has been rescheduled to be issued on November
2
,
2020
. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that these proceedings result in any changes to the rates being charged, a retroactive reconciliation may be required. The Company does not believe that these proceedings will have a material adverse impact on the Company’s financial condition or results of operations.
Legal Proceedings
The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these claims will not have a material impact on its financial position, operating results or cash flows.
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, 2018 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 31, 2019.
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 is in material compliance with applicable environmental and safety laws and regulations and, as of September 30, 2019, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company cannot assure 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. 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.
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Northern Utilities Manufactured Gas Plant Sites –
Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites, which were operated from the
mid-1800s
through the
mid-1900s.
In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough.
Northern Utilities has worked with the Maine Department of Environmental Protection and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have completed remediation activities at all sites; however, on site monitoring continues at several sites which may result in future remedial actions as directed by the applicable regulatory agency. In July 2019, the NH DES requested that Northern Utilities review modeled expectations for groundwater contaminants against observed data at Rochester. The results of the review, along with any recommendations, will be submitted to the NH DES in January 2020. The Company has accrued $0.7 million for estimated costs to complete the remediation at the Rochester site, which is included in the Environmental Obligations table below.
The NHPUC and MPUC have approved regulatory mechanisms for the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding
seven
-year periods. For Northern Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding
five
-year periods.
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 has worked with the Massachusetts Department of Environmental Protection to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring will continue and it is possible that future activities may be required.
The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated and periodic, regulatory review costs for the completed permanent remediation of the Sawyer Passway site. A corresponding Regulatory Asset was recorded to reflect that the recovery of these environmental remediation costs is probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods.
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The following table sets forth a summary of changes in the Company’s liability for the current and long-term portions of the Company’s environmental obligations, which are included in Other Current Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s ​​​​​​​Consolidated Balance Sheets as of September 30, 2019 and 2018.

Environmental Obligations

|  | ($ millions) |
|  | Fitchburg |  |  | Northern Utilities |  |  | Total |
|  | Nine months ended September 30, |
|  | 2019 |  |  | 2018 |  |  | 2019 |  |  | 2018 |  |  | 2019 |  |  | 2018 |
Total Balance at Beginning of Period |  | $ | — |  |  | $ | 0.1 |  |  | $ | 2.0 |  |  | $ | 2.0 |  |  | $ | 2.0 |  |  | $ | 2.1 |
Additions |  |  | — |  |  |  | — |  |  |  | 1.0 |  |  |  | 0.6 |  |  |  | 1.0 |  |  |  | 0.6 |
Less: Payments / Reductions |  |  | — |  |  |  | 0.1 |  |  |  | 0.2 |  |  |  | 0.5 |  |  |  | 0.2 |  |  |  | 0.6 |
Total Balance at End of Period |  |  | — |  |  |  | — |  |  |  | 2.8 |  |  |  | 2.1 |  |  |  | 2.8 |  |  |  | 2.1 |
Less: Current Portion |  |  | — |  |  |  | — |  |  |  | 0.6 |  |  |  | 0.6 |  |  |  | 0.6 |  |  |  | 0.6 |
Noncurrent Balance at End of Period |  | $ | — |  |  | $ | — |  |  | $ | 2.2 |  |  | $ | 1.5 |  |  | $ | 2.2 |  |  | $ | 1.5 |

Note 8: INCOME TAXES
In June 2019 the Company received notice that the Internal Revenue Service (IRS) completed​​​​​​​ all fieldwork for the tax years December 31, 2015 and December 31, 2016 income tax audit and closed the audit with no adjustment. Income tax filings for the year ended December 31, 2018 have been filed with the IRS, Massachusetts Department of Revenue, the Maine Revenue Service, and the New Hampshire Department of Revenue Administration. The Company evaluated its tax positions at September 30, 2019
in accordance with the FASB Codification, and has concluded that no adjustment for recognition,
de-recognition,
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 Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2016; December 31, 2017; and December 31, 2018.
In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction to the corporate federal income tax rate to 21% effective January 1, 2018, was signed into law. In accordance with GAAP Accounting Standard 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) at the new 21% tax rate at which the ADIT will be reversed in future periods. The Company recorded a net Regulatory Liability in the amount of $48.9 million at December 31, 2017 as a result of the ADIT revaluation.
The MDPU issued a multi-utility Order D.P.U.
18-15-E
(the “Order”) on December 21, 2018. The Order clarified the categories of Excess ADIT for Massachusetts ratemaking: 1) Excess protected ADIT directly related to utility plant fixed assets (rate base), 2) other
non-plant
excess ADIT amounts (unprotected), and 3) excess ADIT created through reconciling mechanisms. In the Order, all Massachusetts utilities were ordered to begin flow back of protected and unprotected excess ADIT on February 1, 2019 and to reconcile excess ADIT amounts previously collected from ratepayers through reconciliation mechanisms in the next filing of each of those individual reconciling mechanisms. Fitchburg was ordered to begin flowing back to customers excess ADIT of $10.1 million and $10.4 million to electric and gas ratepayers, respectively, over approximately fifteen years. Fitchburg filed its compliance filing under
D.P.U.18-15-E
on January 4, 2019 for rates effective February 1, 2019. The MDPU approved this filing on January 16, 2019. The filing will be updated and the balances of excess ADIT will be reconciled annually.
On November 15, 2018 the FERC issued two pronouncements regarding the accounting for income taxes due to the TCJA; 1) Notice of Proposed Rulemaking Docket No. RM
19-5-000
and 2) Policy Statement PL
19-2-000
providing specific guidance on the flow back of excess ADIT created by the implementation of the TCJA. Final rules are expected to be issued in the second quarter of 2019. According to the FERC guidance; the amount of the reduction to ADIT that was previously collected from customers but is no longer payable to the IRS is excess ADIT and should be flowed back to ratepayers under general ratemaking principles.
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Based on communications received by the Company from its state regulators in rate cases and other regulatory proceedings in the first quarter of 2018 and as prescribed in the TCJA, the recent FERC guidance noted above and IRS normalization rules; the benefit of these protected excess ADIT amounts will be subject to flow back to customers in future utility rates according to the Average Rate Assumption Method (ARAM). ARAM reconciles excess ADIT at the reversal rate of the underlying book/tax temporary timing differences. The Company estimates the ARAM flow back period for protected and unprotected excess ADIT to be between fifteen and twenty years, over the remaining life of the related utility plant. Subject to regulatory approval, the Company expects to flow back to customers a net $47.1 million of protected excess ADIT created as a result of the lowering of the statutory tax rate by the TCJA over periods estimated to be fifteen to twenty years.
In addition to the protected excess $47.1 million ADIT amounts the Company expects to flow through to customers in utility rates, as noted above, there is approximately $1.8 million of excess ADIT created through reconciling mechanisms at December 31, 2017, related to the implementation of the new federal tax rate of the TCJA, which had not been previously collected from customers through utility rates. The Company will reconcile these excess ADIT amounts through the specific reconciliation mechanisms in the next filing of each of those individual reconciling mechanisms which will be subject to the review of state regulators.
In addition to the $48.9 million of net excess ADIT noted above; there
wa
s $5.8 million of excess ADIT at December 31, 2017, created by the recognition of Net Operating Loss Carryforward assets (NOLC), discussed below, and related to the implementation of the new federal tax rate of the TCJA, which had not been previously included in utility rates. The Company is recognizing the benefit of this excess ADIT in accordance with the regulatory treatment of excess ADIT for each of jurisdiction. In 2018 the Company recognized $2.4 million of this tax benefit provision due to the turning of book/tax temporary differences associated with this excess ADIT. The Company
has recognized
$1.4
million in the first nine months of 2019. Of the remaining amount, the Company expects to recognize $0.4 million in the fourth quarter of 2019 and $1.6 million in 2020, in accordance with regulatory guidance as discussed above.
In the fourth quarter of 2018 the Company was ordered in D.P.U.
18-15-E
to begin the flowback of excess ADIT to ratepayers starting February 1, 2019. The Company complied with the Order and subsequently started flowing back excess ADIT to its Massachusetts ratepayers. The Company has not yet received regulatory orders in all of its jurisdictions regarding the flow-back of excess deferred taxes. The Company’s regulators are expected to issue additional ratemaking guidance in future periods​​​​​​​ that will determine the final disposition of the
re-measurement
of regulatory deferred tax balances. At this time, the Company has applied a reasonable interpretation of the TCJA and a reasonable estimate of the regulatory resolution. Future clarification of TCJA matters with the Company’s regulators may change the amounts estimated.
Under the Company’s Tax Sharing Agreement (the “Agreement”) which was approved upon the formation of Unitil as a PUHC; the Company files consolidated Federal and State tax returns and Unitil Corporation and each of its utility operating subsidiaries recognize the results of their operations in its tax returns as if it were a stand-alone taxpayer. The Agreement provides that the Company will account for income taxes in compliance with U.S. GAAP and regulatory accounting principles. The Company filed its tax returns for the year ended December 31, 201
8
with the Internal Revenue Service in September 201
9
and
utilized federal
NOLC assets of $5.7 million principally due to pension cost deductions, tax repair deductions, tax depreciation and research and development deductions.
As of
September 30, 2019, the Company
had recorded cumulative federal and state NOLC assets of $11.9 million
, on its filed tax returns
to offset against taxes payable in future periods. If unused, the Company’s NOLC carryforward assets will begin to expire in 2029. In addition, at December 31, 201
8
, the Company had $3.1 million of cumulative alternative minimum tax credits, general business tax credit and other state tax credit carryforwards to offset future income taxes payable.
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In assessing the near-term use of NOLCs and tax credits, the Company evaluates the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income available in carryback years. Based on all available evidence, both positive and negative, and the weight of that evidence to the extent such evidence can be objectively verified, the Company expects to utilize all of its NOLCs by December 31, 2020 prior to their expiration in 2029.
The Company bills its customers for sales tax in Massachusetts and Maine. 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 Plan) 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, 2018 as filed with the SEC on January 31, 2019 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:

Used to Determine Plan Costs |  | 2019 |  |  | 2018 |
Discount Rate |  |  | 4.25 | % |  |  | 3.60 | %
Rate of Compensation Increase |  |  | 3.00 | % |  |  | 3.00 | %
Expected Long-term rate of return on plan assets |  |  | 7.75 | % |  |  | 7.75 | %
Health Care Cost Trend Rate Assumed for Next Year |  |  | 7.00 | % |  |  | 7.50 | %
Ultimate Health Care Cost Trend Rate |  |  | 4.50 | % |  |  | 4.50 | %
Year that Ultimate Health Care Cost Trend Rate is reached |  |  | 2024 |  |  |  | 2024 |

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

|  | Pension Plan |  |  | PBOP Plan |  |  | SERP Plan |
Three Months Ended September 30, |  | 2019 |  |  | 2018 |  |  | 2019 |  |  | 2018 |  |  | 2019 |  |  | 2018 |
Service Cost |  | $ | 776 |  |  | $ | 848 |  |  | $ | 576 |  |  | $ | 733 |  |  | $ | 62 |  |  | $ | 122 |
Interest Cost |  |  | 1,621 |  |  |  | 1,469 |  |  |  | 857 |  |  |  | 852 |  |  |  | 142 |  |  |  | 101 |
Expected Return on Plan Assets |  |  | (2,119 | ) |  |  | (1,946 | ) |  |  | (412 | ) |  |  | (409 | ) |  |  | — |  |  |  | — |
Prior Service Cost Amortization |  |  | 80 |  |  |  | 81 |  |  |  | 304 |  |  |  | 327 |  |  |  | 14 |  |  |  | 47 |
Actuarial Loss Amortization |  |  | 1,081 |  |  |  | 1,447 |  |  |  | 56 |  |  |  | 346 |  |  |  | 157 |  |  |  | 121 |
Sub-total |  |  | 1,439 |  |  |  | 1,899 |  |  |  | 1,381 |  |  |  | 1,849 |  |  |  | 375 |  |  |  | 391 |
Amounts Capitalized and Deferred |  |  | (650 | ) |  |  | (962 | ) |  |  | (650 | ) |  |  | (930 | ) |  |  | (107 | ) |  |  | (113 | )
Net Periodic Benefit Cost Recognized |  | $ | 789 |  |  | $ | 937 |  |  | $ | 731 |  |  | $ | 919 |  |  | $ | 268 |  |  | $ | 278 |

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Table of Contents

|  | Pension Plan |  |  | PBOP Plan |  |  | SERP Plan |
Nine Months Ended September 30, |  | 2019 |  |  | 2018 |  |  | 2019 |  |  | 2018 |  |  | 2019 |  |  | 2018 |
Service Cost |  | $ | 2,328 |  |  | $ | 2,544 |  |  | $ | 1,728 |  |  | $ | 2,199 |  |  | $ | 185 |  |  | $ | 366 |
Interest Cost |  |  | 4,863 |  |  |  | 4,407 |  |  |  | 2,569 |  |  |  | 2,554 |  |  |  | 426 |  |  |  | 303 |
Expected Return on Plan Assets |  |  | (6,356 | ) |  |  | (5,838 | ) |  |  | (1,234 | ) |  |  | (1,227 | ) |  |  | — |  |  |  | — |
Prior Service Cost Amortization |  |  | 240 |  |  |  | 243 |  |  |  | 910 |  |  |  | 981 |  |  |  | 42 |  |  |  | 141 |
Actuarial Loss Amortization |  |  | 3,243 |  |  |  | 4,341 |  |  |  | 170 |  |  |  | 1,038 |  |  |  | 471 |  |  |  | 365 |
Sub-total |  |  | 4,318 |  |  |  | 5,697 |  |  |  | 4,143 |  |  |  | 5,545 |  |  |  | 1,124 |  |  |  | 1,175 |
Amounts Capitalized and Deferred |  |  | (1,659 | ) |  |  | (2,590 | ) |  |  | (1,730 | ) |  |  | (2,557 | ) |  |  | (322 | ) |  |  | (339 | )
Net Periodic Benefit Cost Recognized |  | $ | 2,659 |  |  | $ | 3,107 |  |  | $ | 2,413 |  |  | $ | 2,988 |  |  | $ | 802 |  |  | $ | 836 |

Employer Contributions
As of September 30, 2019, the Company had made $6.9 million and $2.8 million of contributions to its Pension and PBOP Plans, respectively, in 2019. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2019 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.
As of September 30, 2019, the Company had made $0.4 million of benefit​​​​​​​ payments under the SERP Plan in 2019. The Company presently anticipates making an additional $0.2 million of benefit payments under the SERP Plan in 2019.
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, 2019. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of September 30, 2019 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 control 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 control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. Certain specific matters are discussed in Notes 6 and 7 to the Consolidated Financial Statements. In the opinion of Management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company’s financial position.
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Table of Contents
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, 2018 as filed with the SEC on January 31, 2019.
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, 2019.
Issuer Purchases of Equity Securities
Pursuant to the written trading plan under Rule
10b5-1
under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted and announced by the Company on May 1, 2019, the Company will periodically repurchase shares of its Common Stock on the open market related to the stock portion of the Directors’ annual retainer for those Directors who elected to receive common stock. There is no pool or maximum number of shares related to these purchases; however, the trading plan will terminate when $195,000 in value of shares have been purchased or, if sooner, on May 1, 2020.
The Company may suspend or terminate this trading plan at any time, so long as the suspension or termination is made in good faith and not as part of a plan or scheme to evade the prohibitions of Rule
10b-5
under the Exchange Act, or other applicable securities laws.
The following table shows information regarding repurchases by the Company of shares of its common stock pursuant to the trading plan for each month in the quarter ended September 30, 2019.

|  | Total Number of Shares Purchased |  |  | Average Price Paid per Share |  |  | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |  |  | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs |
7/1/19 – 7/31/19 |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 195,000 |
8/1/19 – 8/31/19 |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 195,000 |
9/1/19 – 9/30/19 |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 195,000 |
Total |  |  | — |  |  |  | — |  |  |  | — |  |  |  |  |

Item 5. Other Information
On October 24, 2019, the Company issued a press release announcing its results of operations for the three and nine month periods ended September 30, 2019. The press release is furnished with this Quarterly Report on Form
10-Q
as Exhibit 99.1.
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Table of Contents
Item 6. Exhibits
(a) Exhibits

Exhibit No. |  |  | Description of Exhibit |  | Reference (1) |
| 4.1 |  |  | Note Purchase Agreement dated September 12, 2019 by and among Northern Utilities, Inc. and the several purchasers named therein. |  |  | Exhibit 4.1 to Form 8-K dated September 12, 2019 (SEC File No. 1-8858 | )
| 4.2 (2) |  |  | 4.04% Senior Note, Series 2019, due September 12, 2049, issued by Northern Utilities, Inc. to Pacific Life Insurance Company. |  |  | Exhibit 4.2 to Form 8-K dated September 12, 2019 (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 24, 2019 Announcing Earnings For the Quarter Ended September 30, 2019. |  |  | Filed herewith |
| 101.INS |  |  | XBRL Instance Document—the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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 |

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| 101.LAB |  |  | XBRL Taxonomy Extension Label Linkbase Document. |  |  | Filed herewith |
| 101.PRE |  |  | XBRL Taxonomy Extension Presentation Linkbase Document. |  |  | Filed herewith |
| 104 |  |  | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101). |  |  | Filed herewith |

(1) The exhibits referred to in this column by specific designations and dates have heretofore been filed with the Securities and Exchange Commission under such designations and are hereby incorporated by reference.
(2) This Note is substantially identical in all material respects to other Notes that are otherwise required to be filed as exhibits, except as to the registered payee of such Note, the identifying number of such Note, and the principal amount of such Note. In accordance with instruction no. 2 to Item 601 of Regulation
S-K,
the registrant has filed a copy of only one of such Notes, with a schedule identifying the other Notes omitted and setting forth the material details in which such Notes differ from the Note that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any Note so omitted.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

|  |  |  | UNITIL CORPORATION
|  |  |  | (Registrant)
Date: October 24, 2019 |  |  |  | /s/ Christine L. Vaughan
|  |  |  | Christine L. Vaughan
|  |  |  | Chief Financial Officer
Date: October 24, 2019 |  |  |  | /s/ Laurence M. Brock
|  |  |  | Laurence M. Brock
|  |  |  | Chief Accounting Officer

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES
COMPUTATION OF EARNINGS PER WEIGHTED AVERAGE COMMON SHARE OUTSTANDING
(Millions except common shares and per share data)
(UNAUDITED)

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2019 |  |  | 2018 |  |  | 2019 |  |  | 2018 |
Net Income |  | $ | 2.3 |  |  | $ | 2.8 |  |  | $ | 32.8 |  |  | $ | 22.0 |
Weighted Average Number of Common Shares Outstanding – Basic (000’s) |  |  | 14,898 |  |  |  | 14,829 |  |  |  | 14,889 |  |  |  | 14,818 |
Dilutive Effect of Stock Options and Restricted Stock (000’s) |  |  | 8 |  |  |  | 5 |  |  |  | 6 |  |  |  | 5 |
Weighted Average Number of Common Shares Outstanding – Diluted (000’s) |  |  | 14,906 |  |  |  | 14,834 |  |  |  | 14,895 |  |  |  | 14,823 |
Earnings Per Share – Basic and Diluted |  | $ | 0.15 |  |  | $ | 0.19 |  |  | $ | 2.20 |  |  | $ | 1.49 |

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