2019 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; 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 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. customers approximately $340,000, effective May 1, 2019. 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. 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. 2018. Company’s New Hampshire natural gas utility. reasons noted above. the nine month period reflects lower labor and other costs of $1.7 million, resulting from the divestiture of the Company’s amortization. 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. its Therm Sales (millions) Residential Commercial / Industrial Total Gas Operating Revenues and Sales Margin (millions) Gas Operating Revenue: Residential Commercial / Industrial Total Gas Operating Revenue Cost of Gas Sales Gas Sales Margin 2018: Company’s New Hampshire natural gas utility. volumes. kWh Sales (millions) Residential Commercial / Industrial Total Electric Operating Revenues and Sales Margin (millions) Electric Operating Revenue: Residential Commercial / Industrial Total Electric Operating Revenue Cost of Electric Sales Electric Sales Margin 2018: Other Revenue (000’s) Other Total Other Revenue 2018: Financial Statements). the nine month period reflects lower labor and other costs of $1.7 million, resulting from the divestiture of the Company’s amortization. offset by property tax abatements. Taxes Other Income Taxes its accrued. Interest Expense, net (Millions) Interest Expense Long-term Debt Short-term Debt Regulatory Liabilities Subtotal Interest Expense Interest (Income) Regulatory Assets AFUDC(1) and Other Subtotal Interest (Income) Total Interest Expense, net AFUDC – Allowance for Funds Used During Construction. short-term borrowings. Limit Short-Term Borrowings Outstanding Letters of Credit Outstanding Available 2018: 2019. 2018. January 31, 2019. Operating Revenues Gas Electric Other Total Operating Revenues Operating Expenses Cost of Gas Sales Cost of Electric Sales Operation and Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Total Operating Expenses Operating Income Interest Expense, net Other Expense, net Income Before Income Taxes Income Tax Expense Net Income Net Income Per Common Share Weighted Average Common Shares Outstanding Dividends Declared Per Share of Common Stock ASSETS: Current Assets: Cash and Cash Equivalents Accounts Receivable, net Accrued Revenue Exchange Gas Receivable Materials and Supplies Prepayments and Other Total Current Assets Utility Plant: Gas Electric Common Construction Work in Progress Total Utility Plant Less: Accumulated Depreciation Net Utility Plant Other Noncurrent Assets: Regulatory Assets Other Assets Total Other Noncurrent Assets TOTAL ASSETS LIABILITIES AND CAPITALIZATION: Current Liabilities: Accounts Payable Short-Term Debt Long-Term Debt, Current Portion Regulatory Liabilities Energy Supply Obligations Capital Lease Obligations Other Current Liabilities Total Current Liabilities Noncurrent Liabilities: Retirement Benefit Obligations Deferred Income Taxes, net Cost of Removal Obligations Regulatory Liabilities Capital Lease Obligations Other Noncurrent Liabilities Total Noncurrent Liabilities Capitalization: Long-Term Debt, Less Current Portion Stockholders’ Equity: Common Equity (Authorized: 25,000,000 and Outstanding: 14,872,011, 14,119,893 and 14,815,585 Shares) Retained Earnings Total Common Stock Equity Preferred Stock Total Stockholders’ Equity Total Capitalization Commitments and Contingencies (Notes 6 & 7) TOTAL LIABILITIES AND CAPITALIZATION Operating Activities: Net Income Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: Depreciation and Amortization Deferred Tax Provision Changes in Working Capital Items: Accounts Receivable Accrued Revenue Exchange Gas Receivable Regulatory Liabilities Accounts Payable Other Changes in Working Capital Items Deferred Regulatory and Other Charges Other, net Cash Provided by Operating Activities Investing Activities: Property, Plant and Equipment Additions Cash (Used in) Investing Activities Financing Activities: Proceeds from (Repayment of) Short-Term Debt, net Repayment of Long-Term Debt Decrease in Capital Lease Obligations Net Increase in Exchange Gas Financing Dividends Paid Proceeds from Issuance of Common Stock, net Cash Provided by Financing Activities Net (Decrease) Increase in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Cash Flow Information: Interest Paid Income Taxes Paid Payments on Capital Leases Non-cash Investing Activity: Capital Expenditures Included in Accounts Payable Three Months Ended September 30, 2018 Balance at July 1, 2018 Net Income Dividends on Common Shares ($0.365 per share) Stock Compensation Plans Issuance of 5,423 Common Shares Balance at September 30, 2018 Three Months Ended September 30, 2017 Balance at July 1, 2017 Net Income Dividends on Common Shares ($0.36 per share) Stock Compensation Plans Issuance of 6,173 Common Shares Balance at September 30, 2017 shares) Nine Months Ended September 30, 2018 Balance at January 1, 2018 Net Income Dividends on Common Shares ($1.095 per share) Stock Compensation Plans Issuance of 19,700 Common Shares Balance at September 30, 2018 Nine Months Ended September 30, 2017 Balance at January 1, 2017 Net Income Dividends on Common Shares ($1.08 per share) Stock Compensation Plans Issuance of 20,564 Common Shares Balance at September 30, 2017 See additional discussion of the divestiture of Usource Other Operating Revenues ($ millions): Usource Contract Revenue Less: Revenue Sharing Payments Total Other Operating Revenues Operation and Maintenance Expense ($ millions): Operation and Maintenance Expense Other Operating Revenues ($ millions): Usource Contract Revenue Less: Revenue Sharing Payments Total Other Operating Revenues Operation and Maintenance Expense ($ millions): Operation and Maintenance Expense divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from ($ millions) Allowance for Doubtful Accounts Accrued Revenue ($ millions) Regulatory Assets – Current Unbilled Revenues Total Accrued Revenue 2018. Exchange Gas Receivable ($ millions) Northern Utilities Fitchburg Total Exchange Gas Receivable 2018. Gas Inventory ($ millions) Natural Gas Propane Liquefied Natural Gas & Other Total Gas Inventory 2018. 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 Assets consist of the following ($ millions) Retirement Benefits Energy Supply & Other Rate Adjustment Mechanisms Deferred Storm Charges Environmental Income Taxes Other Total Regulatory Assets Less: Current Portion of Regulatory Assets(1) Regulatory Assets – noncurrent Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Regulatory Liabilities consist of the following ($ millions) Rate Adjustment Mechanisms Gas Pipeline Refund (Note 6) Income Taxes (Note 8) Total Regulatory Liabilities Less: Current Portion of Regulatory Liabilities Regulatory Liabilities – noncurrent derivative accounting. ) Fair Value of Marketable Securities ($ millions) Equity Funds Fixed Income Funds Total Marketable Securities (Income), Net. Energy Supply Obligations ($ millions) Current: Exchange Gas Obligation Renewable Energy Portfolio Standards Power Supply Contract Divestitures Total Energy Supply Obligations – Current Noncurrent: Power Supply Contract Divestitures Total Energy Supply Obligations Note 1. Three Months Ended September 30, 2018 Revenues: Billed and Unbilled Revenue Rate Adjustment Mechanism Revenue Other Operating Revenue –Non-Regulated Total Operating Revenues Segment Profit (Loss) Capital Expenditures Three Months Ended September 30, 2017 Revenues Segment Profit (Loss) Capital Expenditures Nine Months Ended September 30, 2018 Revenues: Billed and Unbilled Revenue Rate Adjustment Mechanism Revenue Other Operating Revenue –Non-Regulated Total Operating Revenues Segment Profit Capital Expenditures Segment Assets Nine Months Ended September 30, 2017 Revenues Segment Profit Capital Expenditures Segment Assets As of December 31, 2017 Segment Assets ($ millions) Unitil Corporation: 6.33% Senior Notes, Due May 1, 2022 3.70% Senior Notes, Due August 1, 2026 Unitil Energy First Mortgage Bonds: 5.24% Senior Secured Notes, Due March 2, 2020 8.49% Senior Secured Notes, Due October 14, 2024 6.96% Senior Secured Notes, Due September 1, 2028 8.00% Senior Secured Notes, Due May 1, 2031 6.32% Senior Secured Notes, Due September 15, 2036 Fitchburg: 6.75% Senior Notes, Due November 30, 2023 6.79% Senior Notes, Due October 15, 2025 3.52% Senior Notes, Due November 1, 2027 7.37% Notes, Due January 15, 2029 5.90% Notes, Due December 15, 2030 7.98% Notes, Due June 1, 2031 4.32% Senior Notes, Due November 1, 2047 Northern Utilities: 6.95% Senior Notes, Due December 3, 2018 5.29% Senior Notes, Due March 2, 2020 3.52% Senior Notes, Due November 1, 2027 7.72% Senior Notes, Due December 3, 2038 4.42% Senior Notes, Due October 15, 2044 4.32% Senior Notes, Due November 1, 2047 Granite State Senior Notes: 7.15% Senior Notes, Due December 15, 2018 3.72% Senior Notes, Due November 1, 2027 Total Long-Term Debt Less: Unamortized Debt Issuance Costs Total Long-Term Debt, net of Unamortized Debt Issuance Costs Less: Current Portion Total Long-term Debt, Less Current Portion ($ millions) Estimated Fair Value of Long-Term Debt Limit Short-Term Borrowings Outstanding Letters of Credit Outstanding Available 2018: 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. 2018. and preferred stock 2019. Restricted Stock Units (Equity Portion) Restricted Stock Units as of December 31, 2017 Restricted Stock Units Granted Dividend Equivalents Earned Restricted Stock Units Settled Restricted Stock Units as of September 30, 2018 2018 as filed with the Securities and Exchange Commission on january 31, 2019. approximately 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. 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. with the financial position, operating results or cash flows. JANUARY 31, 2019. 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. Environmental Obligations table below. Total Balance at Beginning of Period Additions Less: Payments / Reductions Total Balance at End of Period Less: Current Portion Noncurrent Balance at End of Period Used to Determine Plan Costs Discount Rate Rate of Compensation Increase Expected Long-term rate of return on plan assets Health Care Cost Trend Rate Assumed for Next Year Ultimate Health Care Cost Trend Rate Year that Ultimate Health Care Cost Trend Rate is reached Three Months Ended September 30, Service Cost Interest Cost Expected Return on Plan Assets Prior Service Cost Amortization Actuarial Loss Amortization Sub-total Amounts Capitalized and Deferred Net Periodic Benefit Cost Recognized Nine Months Ended September 30, Service Cost Interest Cost Expected Return on Plan Assets Prior Service Cost Amortization Actuarial Loss Amortization Sub-total Amounts Capitalized and Deferred Net Periodic Benefit Cost Recognized 2019. January 31, 2019. 2019. 2020. 7/1/18 – 7/31/18 8/1/18 – 8/31/18 9/1/18 – 9/30/18 Total 2019.QUARTERLY REPORT UNDER SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Quarter Ended the quarterly period ended2018TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 New Hampshire 02-0381573 (§files)files ☐ ☒Non-accelerated filer ☐ Class 22, 201821, 2019 14,872,955 Page No.Part I. Financial Information Item 1. 21 22-23 24 25 26 27-55Item 2. 4-20Item 3. 55Item 4. 55Item 1. 56Item 1A. 56Item 2. 56Item 3. Item 4. Item 5. 57Item 6. 57 60CAUTIONARY STATEMENTthe Company’s energy brokering customers’ performance under multi-year energy brokering contracts; and i) ii) iii) 105,000105,600 electric customers and 81,30082,700 natural gas customers in their service territory.$1,022.3$1,083.9 million at September 30, 2018.2019. 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.also conductsResources is the Company’s wholly-owned operations principally throughisthe Company divested of in the first quarter of 2019, were wholly-owned bysubsidiaries of Unitil Resources Inc., a wholly-owned subsidiary of Unitil.Resources. Usource provides energyprovided brokering and advisory services to large commercial and industrial primarily in the northeastern United States. See additional discussion of the divestiture of Usource in “Divestiture of (Unitil Realty), which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire and Unitil Power Corp., which formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.has issued procedural orders directing how the tax law changes arewere to be reflected in rates, including requiring that the companies provide certain filings and calculations.rates. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC has also opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State (described below).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 mechanismsdivision recently completed a basedivision’s 2013 rate case (described below). The MPUC’s final order in that docket incorporated the lower tax rates in the calculation of rates for the Company.Similarly, in New Hampshire, Northern Utilities’ New Hampshire division recently completed a base rate case proceeding (described below). The NHPUC’s final order in that docket approved a comprehensive settlement agreement amongallowed the Company the Staff of the Public Utilities Commission and the Office of Consumer Advocate which included the effect of the tax changes in the calculation of the revenue requirement. With respect to Unitil Energy, on April 30, 2018 the NHPUC approved the Company’s annual step increase pursuantimplement a TIRA rate mechanism to the provisions of its lastadjust base rate case, which included adjustments to account for the TCJA’s income tax changes.In Massachusetts, the MDPU issued an order opening an investigation into the effect ondistribution rates of the decrease in the federal corporate income tax rate on the MDPU’s regulated utilities, and required each utility subject to its jurisdiction to submit proposals to address the effects of the TCJA and to reduce its rates as of January 1, 2018. The MDPU consolidated an earlier petition filed by the Attorney General requesting such an investigation into its order. On June 29, 2018, the MDPU issued an order accepting Fitchburg’s proposal to decrease the annual revenue requirement of both its gas and electric divisions by $0.8 million each. The MDPU will address the refund of excess accumulated deferred income taxes in phase two of its investigation. An order is pending.On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which accounted for the effects of the TCJA in its rates. The settlement was approved by FERC on June 27, 2018, and complies with and satisfies the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reduction under the TCJA.Base Rate ActivityUnitil Energy – Base Rates –On April 20, 2017 the NHPUC approved a permanent increase of $4.1 million in electric base rates, and a three year rate plan with an additional rate step adjustment, effective May 1, 2017, of $0.9 million, followed by two rate step adjustments in May of 2018 and 2019annually 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.filing. The filing incorporated the revenue requirement of $3.3 millionproviding for 2017 plant additions, a reduction of $2.2 million for the effect of the federal tax decrease pursuant to the TCJA, along with the termination of theone-year $1.4 million reconciliation adjustment which had recouped the difference between temporary rates and final rates. The net effect of the three adjustments resulted in a revenue decreaseincrease of $0.3 million.last base rate order fromrates are decoupled, and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the MDPU, issuedamount that rates may be increased in April 2016, included the approval ofany year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. While a numberOn April 3, 2019, the DPU approved Fitchburg’s cumulative revenue requirement associated with the Company’s 2015 and 2016 capital expenditures, an increase of the capital cost recovery filings may remain pending fromyear-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding.$0.4 million. The increase was effective January 1, 2018. On June 28,November 1, 2018, Fitchburg filed its compliance reportcumulative revenue requirement of $0.9 million associated with the Company’s 2015, 2016 and 2017 capital investments for calendar year 2017. This matter remains pending.Fitchburg – Electric Grid Modernization –expenditures. On May 10,December 27, 2018, the MDPU issued an order approving a three year grid modernization investment plan for Fitchburg for the period 2018 through 2020 with a spending cap of $4.4 million. The order provides for a cost recovery mechanism for incremental capital investments and operation and maintenance (O&M) expenses. The electric distribution companies in Massachusetts jointly filed compliance filings in August 2018 including 1) revised proposed performance metrics designed to addresspre-authorized grid-facing investments, 2) a proposed evaluation plan for the three-year investment term, and 3) a model tariff for cost recovery including proposed protocol for identifying and tracking incremental O&M expenses. Approval of these filings is pending. The next three year investment plan is due July 1, 2020 for the period 2021 through 2023, and is required to include a five year strategic plan for 2021 – 2025.Fitchburg – Solar Generation –On November 9, 2016, the MDPU approved Fitchburg’s petition to develop a 1.3 MW solar generation facility located on Company property in Fitchburg Massachusetts. Construction of the solar generating facility was completed and the facility began generating power on November 22, 2017. On April 2, 2018, Fitchburg submitted its first filing pursuant to its Solar Cost Adjustment tariff, by which the Company recovers its annual revenue requirement related to its investment in the solar generation facility. The filing sought a net amount of approximately $0.3 million for recovery effective June 1, 2018. The recovery of this amount in rates was approved, by the MDPU on May 31, 2018,effective January 1, 2019, subject to further investigation and reconciliation. A final orderFinal approval of the 2018 filingpending.31;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. While a number of the filings under the GSEP tariff may remain pending fromyear-to-year in any given year, theincurred (the “GREC Filing”). The Company considers these to be routine regulatory proceedings and there are no material issues outstanding. Under this tariff,$0.9$1.0 million that went into effect on May 1, 2018,2019, 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 reconciliation.Northern Utilities – Base Rates – Maine –On February 28, 2018, the MPUC issued its Final Order (Order) in Northern Utilities pending base rate case. The Order provided for an annuala revenue increase of $2.1 million before a reduction of $2.2 million to incorporate the effect of the lower federal income tax rate under the TCJA. The MPUC Order approved a return on equity of 9.5 percent and a capital structure reflecting 50 percent equity and 50 percent long-term debt. The Order also provides for a reduction in annual depreciation expense, reducing the Company’s annual operating costs by approximately $0.5 million, and addressed a number of other issues, including a change to therm billing, increases in other delivery charges, and cost recovery under the Company’s Targeted AreaBuild-out (TAB) Program and Targeted Infrastructure Replacement Adjustment (TIRA) mechanism. The new rates and other changes became effective on March 1, 2018.Northern Utilities – Targeted Infrastructure Replacement Adjustment – 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). The TIRA had an initial term of four years and covered targeted capital expenditures in 2013 through 2016. In its Order in the current base rate case (see above), the MPUC approved an extension of the TIRA mechanism, with adjustment, 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, to recover the revenue requirements for 2017 eligible facilities.Northern Utilities – Targeted AreaBuild-out Program – Maine –In December 2015, the MPUC approved a TAB program and associated rate surcharge mechanism.$1.0 million. This program is designed to allow the economic extension of natural gas mains to new, targeted service areas in Maine. It allows customers in the targeted area the ability to pay a rate surcharge, instead of a large upfront payment or capital contribution to connect to the natural gas delivery system. The initial pilot of the TAB program wasapproved for the City of Saco, and is being built out over a period of three years, with the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco area. A second TAB program was approved for the Town of Sanford, and has the potential to add 2,000 new customers and approximately $2 million in annual distribution revenue in the Sanford area. In its base rate case Order (described above), the MPUC approved the inclusion of Saco TAB investments in rate base along with a cost recovery incentive mechanism for future TAB investments.Northern Utilities – Base Rates – New Hampshire –On May 2, 2018, the NHPUC approved a settlement agreement providing for an annual revenue increase of $2.6 million, a reduction of annual revenue of $1.7 million to reflect the effect of the TCJA, and a step increase of $2.3 million to recover post-test year capital investments, all effective May 1, 2018 (with the revenue increase of $2.6 million reconciling to the date of temporary rates of August 1, 2017 and the revenue decrease for TCJA reconciling to January 1, 2018), for a net increase of approximately $3.2 million. Under the agreement, the Company may file for a second step increase for effect May 1, 2019 to recover eligible capital investments in 2018, up to a revenue requirement cap of $2.2 million. If the Company chooses the option to implement the second step increase, the next distribution base rate case will be based on an historic test year of no earlier than twelve months ending December 31, 2020.Northern Utilities – Franchise Extensions – New Hampshire –On October 3, 2018, the NHPUC granted Northern Utilities authority to expand its previously limited franchise to provide natural gas service in the Towns of Kingston and Atkinson, New Hampshire to serve new industrial, commercial and residential customers. Northern Utilities has also petitioned the NHPUC to extend its franchise into the Town of Epping, New Hampshire, where new commercial and residential developments present the Company with opportunities for growth. The franchise petition for service to the Town of Eppingmatter remains pending. The settlement also provides that Granite State may not file a general (Section 4) rate case prior to April 30, 2019.20182019 and September 30, 20172018 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).$2.8$2.3 million, or $0.19 per share,$0.15 in Earnings Per Share (EPS), for the third quarter of 2018, an increase2019, a decrease of $0.5 million, or $0.03 per share,$0.04 in EPS, compared to the third quarter of 2017.2018. For the nine months ended September 30, 2018,2019, the Company reported Net Income of $22.0$32.8 million, or $1.49 per share,$2.20 in EPS, an increase of $4.2$10.8 million, or $0.22 per share,$0.71 in EPS, compared to the same nine month period in 2017. The increases2018. In the first quarter of 2019, the Company recognized a2018the first nine months 2019 were driven by higher natural gas and electric sales margins, reflecting: customer growth, favorable impactsmargins. Earnings for the Company’s utility operations were Net Income of weather on unit sales and new distribution rates. Also, earnings per share reflect a higher number$23.0 million, or $1.54 in EPS, for the first nine months of shares outstanding due2019, an increase of $1.0 million in Net Income, or $0.05 in EPS, compared to the issuancefirst nine months of 690,000 common shares on December 14, 2017, discussed below in Note 5 to the Consolidated Financial Statements.$17.6$18.7 million and $80.4$85.5 million in the three and nine months ended September 30, 2018,2019, respectively, increases of $0.8$1.1 million and $5.1 million, respectively, compared to the same periods in 2017.2018. Gas sales marginmargins in the first nine monthsthird quarter of 2018 was2019 were positively affected by higher natural gas distribution revenuesrates of $5.9$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.lower revenues of $2.9 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. As a result of the final base rate awardabsence in the Company’s New Hampshire gas utility, the Company recognized concurrentnon-recurring adjustments to increase both Gas Operating Revenues and Operation and Maintenance (O&M) expenses bycurrent period of a $1.2 millionreconcile permanent rates and deferred costs toincrease gas revenue in connection with a then ongoing base rate case for the temporary rates which were effective July 1, 2017. Gas margin in the first nine months of 2018 also reflects the positive effect of colder winter weather and customer growth on sales volume of $2.1 million.decreased 2.9%increased 4.2% and increased 5.5%2.5% in the three and nine month periods ended September 30, 2018,2019, respectively, compared to the same periods in 2017.2018. The increase in gas therm sales in the Company’s service areas in the nine month period was driven by customer growth and a colder winter in 2018 compared to 2017. Based on weather data collected in the Company’s naturalincreased average consumption by C&I and Residential customers. The Company estimates that weather-normalized gas service areas, theretherm sales, excluding decoupled sales, were 9% more Heating Degree Days (HDD)up 5.5% in the first nine months of 20182019 compared to the same period in 2017.2018. As of September 30, 2018,2019, the number of total natural gas customers served has increased by approximately 1,2001,468 over the last year.$25.9$25.1 million and $70.5$70.6 million in the three and nine months ended September 30, 2018,2019, respectively, increasesa decrease of $1.1$0.8 million and $0.4an increase of $0.1 million, respectively, compared to the same periods in 2017.2018. 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 marginmargins in the first nine months of 2018 was2019 were positively affected by higher electric distribution revenuesrates of $2.5$1.4 million, partially offset by a decrease of $1.3 million from lower revenues of $2.1 million in 2018 to accountkWh sales, for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. Electric sales margin in the current period was also positively affected by warmer-than-average summer temperatures and customer growth of $1.4 million. These positive impacts on electric sales margin were partially offset by the absence in the current period of aone-year $1.4 million temporary rate reconciliation adjustment recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.increased 3.4%decreased 5.3% and 4.2%5.2%, respectively in the three and nine month periods ended September 30, 20182019 compared to the same periods in 2017. The increase2018. For the third quarter, the decrease reflects milder summer weather in the nine month period reflects customer growth, the favorable impacts of weather on unit sales and higher usage by industrial customers for production purposes.2019 compared to 2018. Based on weather data collected in the Company’s electric service areas, there were 48.7% more19% fewer Cooling Degree Days (CDD) in the third quarter of 20182019 compared to the same period in 2017.2018. 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, 2018,2019, the number of total electric customers served has increased by approximately 575554 over the last year.O&M$0.5$0.9 million and increased $2.1$1.6 million for thein three and nine months ended September 30, 2018,2019, respectively, compared to the same periods in 2017. The decrease in the three month period reflects lower professional fees of $0.5 million and lower labor costs of $0.3 million, partially offset by higher utility operating costs of $0.3 million. The increase in the nine month period reflects higher labor costs of $1.5 million and higher utility operating costs of $1.9 million, offset by lower professional fees of $1.3 million. The higher utility operating costs in the nine month period include2018. Excluding a temporary rate which wasin 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’sa corresponding increasehigher compensation and benefit costs of $0.3 million. The decrease in gas revenue.$1.6$0.4 million and $2.2$1.6 million in the three and nine months ended September 30, 2018,2019, respectively, compared to the same periods in 2017.2018. These increases reflect increased depreciation on higher levels of utility plant in service, and higher amortization of information technology costs, partially offset by lower amortization of deferred major storm costs which were being amortized for recovery over multi-year periods.increased $0.6 million and $0.9 million in the three and nine months ended September 30, 2018, respectively,2019 was essentially unchanged compared to the same periodsperiod in 2017, primarily2018, reflecting higher local property tax rates on higher levels of utility plant assets 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.payroll taxes.$0.2by $0.5 million and $0.8$5.2 million infor the three and nine months ended September 30, 2018,2019, respectively, compared to the same periods in 2017. These increases primarily reflect interest on higher levels2018. The increase in the nine month period reflects income taxes associated with the Company’s divestiture of long-term debt.2018,2019, April 2018,2019, July 20182019 and October 20182019 meetings, Unitil’sthe Unitil Corporation Board of Directors declared quarterly dividends on the Company’s common stock of $0.365$0.37 per share. These quarterly dividends result in a current effective annualized dividend rate of $1.46$1.48 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.20182019 is presented below.decreased 2.9%increased 4.2% and increased 5.5%2.5% in the three and nine month periods ended September 30, 2018,2019, respectively, compared to the same periods in 2017.2018. In the third quarter of 2018,2019, sales to Residential and C&I customers decreased 10.7%increased 4.0% and 2.0%4.2%, respectively, compared to the same period in 2017, reflecting warmer late summer and early fall weather in 2018, partially offset by customer growth.2018. For the nine months ended September 30, 2018,2019, sales to Residential and C&I customers increased 7.2%0.8% and 5.0%2.9%, respectively, compared to the same period in 2017.2018. The increase in gas therm sales in the Company’s service areas in the nine month period was driven by customer growth and a colder winter in 2018 compared to 2017. Based on weather data collected in the Company’s natural gas service areas, there were 9% more HDD in the first nine months of 2018 compared to the same period in 2017.increased average consumption by C&I and Residential customers. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 2.0%5.5% in the first nine months of 20182019 compared to the same period in 2017.2018. As of September 30, 2018,2019, the number of total natural gas customers served has increased by approximately 1,2001,468 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.20182019 and 2017,2018, by major customer class: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 Change % Change 2018 2017 Change % Change 2.5 2.8 (0.3 ) (10.7 %) 35.9 33.5 2.4 7.2 % 23.9 24.4 (0.5 ) (2.0 %) 132.3 126.0 6.3 5.0 % 26.4 27.2 (0.8 ) (2.9 %) 168.2 159.5 8.7 5.5 % % % % % % % 20182019 and 2017: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 $ Change % Change 2018 2017 $ Change % Change $ 9.2 $ 9.1 $ 0.1 1.1 % $ 58.9 $ 53.4 $ 5.5 10.3 % 16.5 16.0 0.5 3.1 % 88.5 78.5 10.0 12.7 % $ 25.7 $ 25.1 $ 0.6 2.4 % $ 147.4 $ 131.9 $ 15.5 11.8 % $ 8.1 $ 8.3 $ (0.2 ) (2.4 %) $ 67.0 $ 56.6 $ 10.4 18.4 % $ 17.6 $ 16.8 $ 0.8 4.8 % $ 80.4 $ 75.3 $ 5.1 6.8 % $ $ ) %) $ $ ) %) ) %) ) %) $ $ ) %) $ $ ) %) $ $ ) %) $ $ ) %) $ $ % $ $ % $17.6$18.7 million and $80.4$85.5 million in the three and nine months ended September 30, 2018,2019, respectively, increases of $0.8$1.1 million and $5.1 million, respectively, compared to the same periods in 2017.2018. Gas sales marginmargins in the third quarter of 2018 was2019 were positively affected by higher natural gas distribution revenuesrates of $1.1$0.8 million partially offsetand by lower revenue of $0.4$0.3 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. The reduction in revenues related to the TCJA also reflects a lower provision for income taxes in the period. from higher therm sales, reflecting customer growth and increased average consumption by C&I and Residential customers.margin in the third quarter of 2018 also reflects the effect of customer growth on sales volume of $0.1 million.Gas sales marginmargins in the first nine months of 2018 was2019 were positively affected by higher natural gas distribution revenuesrates of $5.9$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 lower revenue of $2.9 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. As a result of the final base rate awardabsence in the Company’s New Hampshire gas utility, the Company recognized concurrentnon-recurring adjustments to increase both Gas Operating Revenues and O&M expenses bycurrent period of a $1.2 millionreconcile permanent rates and deferred costs toincrease gas revenue in connection with a then ongoing base rate case for the temporary rates which were effective July 1, 2017. Gas margin in the first nine months of 2018 also reflects the positive effect of colder winter weather and customer growth on sales volume of $2.1 million.increasedecreases in Total Gas Operating Revenues of $0.6$0.8 million and $3.5 million in the three and nine months ended September 30, 20182019, respectively, compared to the same periodperiods in 2017 reflects higher natural gas distribution rates and customer growth, partially offset by lower natural gas sales volumes, lower revenue related to the TCJA, discussed above, and2019, reflect lower cost of gas sales, which are tracked and reconciled costs as a pass-throughthat are passed through directly to customers. The increase in Total Gas Operating Revenues of $15.5 millioncustomers, and for the nine month period, thenine months ended September 30, 2018 compared to the same period in 2017 reflects higher natural gas distribution rates, customer growth,second quarter of 2019, discussed above, partially offset by higher natural gas sales volumes and higher cost of gas sales, which are tracked and reconciled costs as a pass-through to customers, partially offset by lower revenue related to the TCJA, discussed above.increased 3.4%decreased 5.3% and 4.2%5.2%, respectively in the three and nine month periods ended September 30, 20182019 compared to the same periods in 2017. In the third quarter of 2018, sales2018. Sales to Residential customers decreased 7.2% and C&I customers increased 9.2% and decreased 0.4%5.6%, respectively, in the three and nine month periods ended September 30, 2019 compared to the same periodperiods in 2017, reflecting warmer-than-average summer temperatures2018. Sales to C&I customers decreased 4.0% and 4.9%, respectively, in 2018the three and customer growth. For the nine monthsmonth periods ended September 30, 2018, sales to Residential and C&I customers increased 6.3% and 2.7%, respectively,2019 compared to the same periodperiods in 2017, reflecting customer growth,2018. For the favorable impacts ofthird quarter, the decrease reflects milder summer weather on unit sales and higher usage by industrial customers for production purposes.in 2019 compared to 2018. Based on weather data collected in the Company’s electric service areas, there were 48.7% more CDD19% fewer Cooling Degree Days in the third quarter of 20182019 compared to the same period in 2017 and 9.0% more HDD2018. The decreases in the firstthree and nine months of 2018 comparedmonth periods also reflect overall lower average usage due to the same period in 2017.both energy efficiency purposes and aforementioned reduced usage by some industrial customers, but were partially offset by overall customer growth. As of September 30, 2018,2019, the number of total electric customers served has increased by approximately 575554 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.20182019 and 20172018 by major customer class: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 Change % Change 2018 2017 Change % Change 195.0 178.5 16.5 9.2 % 527.8 496.4 31.4 6.3 % 268.3 269.5 (1.2 ) (0.4 %) 755.9 735.9 20.0 2.7 % 463.3 448.0 15.3 3.4 % 1,283.7 1,232.3 51.4 4.2 % ) %) ) %) ) %) ) %) ) %) ) %) 20182019 and 2017: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 $ Change % Change 2018 2017 $ Change % Change $ 35.5 $ 32.2 $ 3.3 10.2 % $ 95.7 $ 86.9 $ 8.8 10.1 % 25.9 25.3 0.6 2.4 % 71.9 67.5 4.4 6.5 % $ 61.4 $ 57.5 $ 3.9 6.8 % $ 167.6 $ 154.4 $ 13.2 8.5 % $ 35.5 $ 32.7 $ 2.8 8.6 % $ 97.1 $ 84.3 $ 12.8 15.2 % $ 25.9 $ 24.8 $ 1.1 4.4 % $ 70.5 $ 70.1 $ 0.4 0.6 % $ $ $ ) %) $ $ $ % % % $ $ $ ) %) $ $ $ % $ $ $ ) %) $ $ $ % $ $ $ ) %) $ $ $ % $25.9$25.1 million and $70.5$70.6 million in the three and nine months ended September 30, 2018,2019, respectively, increasesa decrease of $1.1$0.8 million and $0.4an increase of $0.1 million, respectively, compared to the same periods in 2017. Electric2018. The decrease in electric sales marginmargins in the third quarter waswere 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 revenuesrates of $0.8$1.4 million, partially offset by a decrease of $1.3 million from lower revenue of $0.6kWh sales, for the reasons noted above.2018 to account for the reduction in rates duethree months ended September 30, 2019, respectively, compared to the same period in 2018 reflecting lower corporate income tax ratesales of 21% under the TCJA. The reduction in revenues related to the TCJA also reflects a lower provision for income taxes in the period. Electric sales margin in the current period was also positively affected by warmer-than-average summer temperatures and customer growth on sales volume of $0.9 million.Electric sales margin in the first nine months of 2018 was positively affected by higher electric distribution revenues of $2.5 million,electricity, partially offset by lower revenues of $2.1 million in 2018 to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. Electric sales margin in the current period was also positively affected by warmer-than-average summer temperatures and customer growth of $1.4 million. These positive impacts on electric sales margin were partially offset by the absence in the current period of aone-year $1.4 million temporary rate reconciliation adjustment recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.The increase in Total Electric Operating Revenues of $3.9 million in the third quarter of 2018 reflects higher electric distribution rates and higher cost of electric sales, which are tracked and reconciled to costs as a pass-throughthat are passed through directly to customers, partially offset by lower revenue related to the TCJA, discussed above.The increase incustomers. Total Electric Operating Revenues of $13.2increased $9.4 million in the first nine months ofended September 30, 2019, respectively, compared to the same period in 2018 reflects higher electric distribution rates andreflecting higher cost of electric sales, which are tracked and reconciled to costs as a pass-through to customers, partially offset by anon-recurring adjustment in the second quarterlower sales of 2017 to increase revenue by $1.4 million related to the completionelectricity.20182019 and 2017: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 $ Change % Change 2018 2017 $ Change % Change $ 1.1 $ 1.4 $ (0.3 ) (21.4 %) $ 3.5 $ 4.5 $ (1.0 ) (22.2 %) $ 1.1 $ 1.4 $ (0.3 ) (21.4 %) $ 3.5 $ 4.5 $ (1.0 ) (22.2 %) $ $ $ ) $ $ $ ) %) $ $ $ ) $ $ $ ) %) Usource. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from those suppliers under term contracts brokered by Usource.Usource’s revenuesUsource, decreased $0.3 million, or 21.4%, and $1.0 million, or 22.2%, in the three and nine months ended June 30, 2018, respectively, compared to the same periods in 2017, primarily as a result of the adoption of a new accounting standard.In the first quarter of 2018, the Company adopted Accounting Standards Update (ASU)2014-09, and its subsequent clarifications and amendments outlined in ASU2015-14, ASU2016-08, ASU2016-10 and ASU2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018. ASU2014-09 requires that payments made by Usource to third parties (“Channel Partners”) for revenue sharing agreements are recognized as a reduction from revenue, where those payments were previously recognized as an operating expense. Therefore, beginning in 2018 and going forward, payments made by Usource to third parties for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU2014-09, payments by Usource to Channel Partners for revenue sharing agreements are included as “Operation and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. Those Channel Partner payments were $0.3$1.1 million and $0.3$2.6 million, respectively, in the three months ended September 30, 2018 and 2017, respectively. Channel Partner payments were $0.8 million and $0.8 million in the nine months ended September 30, 2018 and 2017, respectively.If ASU2014-09 had been in effect for the three and nine months ended September 30, 2017,2019, compared to the result would have been corresponding reductionssame periods in 2018, reflecting the Company’s divestiture of $0.3 million and $0.8 million, respectively, in both “Other”Usource in the “Operating Revenues” sectionfirst quarter of 2019 (See “Divestiture ofStatements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings.$0.2$1.9 million, or 2.4%23.5%, and increased $10.4$8.6 million, or 18.4%12.8%, in the three and nine months ended September 30, 2018,2019, respectively, compared to the same periods in 2017. The decrease in the three month period primarily reflects lower sales of natural gas and2018. These decreases reflect lower wholesale natural gas prices, partially offset by a decrease in the amount of natural gas purchased by customers directly from third-party suppliers. The increase in the nine month period reflects higher sales of natural gas and higher wholesale natural gas prices.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.increased $2.8decreased $0.2 million, or 8.6%0.6%, and $12.8increased $9.3 million, or 15.2%9.6%, in the three and nine months ended September 30, 20182019, respectively, compared to the same periods in 2017.2018. The increasedecrease in the three month period reflects lower sales of electricity, partially offset by higher electric saleswholesale 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 electric sales, higher wholesale electricity prices and a decrease in the amount of electricity purchased by customers directly from third-party suppliers.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.costscost of the Company’s corporate and other business activities. Total O&M expensesexpense decreased $0.5$0.9 million, or 5.5%, and increased $2.1$1.6 million, for theor 3.1%, in three and nine months ended September 30, 2018,2019, respectively, compared to the same periods in 2017. The decrease in the three month period reflects lower professional fees of $0.5 million and lower labor costs of $0.3 million, partially offset by higher utility operating costs of $0.3 million. The increase in the nine month period reflects higher labor costs of $1.5 million and higher utility operating costs of $1.9 million, offset by lower professional fees of $1.3 million. The higher utility operating costs in the nine month period include2018. Excluding a temporary rate which wasin 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’sa corresponding increasehigher compensation and benefit costs of $0.3 million. The decrease in gas revenue.14.8%, and $2.2 million, or 6.3%4.3%, in the three and nine months ended September 30, 2018,2019, respectively, compared to the same periods in 2017.2018. These increases reflect increased depreciation on higher levels of utility plant in service, and higher amortization of information technology costs, partially offset by lower amortization of deferred major storm costs which were being amortized for recovery over multi-year periods.increased $0.6 million, or 12.2% and $0.9 million, or 5.8% in the three and nine months ended September 30, 2018, respectively,2019 was essentially unchanged compared to the same periodsperiod in 2017, primarily2018, reflecting higher local property tax rates on higher levels of utility plant assets in service, and higher payroll taxes.Expense, net –Other Expense, netThan Income Taxes increased $0.2$0.5 million, or 22.2%, and $0.4 million, or 10.8%3.0%, in the three and nine months ended September 30, 2018, respectively,2019 compared to the same periodsperiod in 2017. In the first quarter of 2018, the Company adopted ASUNo. 2017-07, “Compensation – Retirement Benefits (Topic 715)” which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components2018. The increase in the income statement.Accordingly, for all periods presentednine month period reflects higher local property tax rates on higher levels of utility plant in the Consolidated Financial Statements in this Form10-Q for the quarter ended September 30, 2018, the service, cost component of the Company’s net periodic benefit costs is reported in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings while the other components of net periodic benefit costs are reported in the “Otherpartially offset by property tax abatements.net” section of the Consolidated Statements of Earnings. Prior to adoption, the Company reported all components of its net periodic benefit costs in “Operations andMaintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. There are $1.2 million and $0.8 million ofnon-service cost net periodic benefit costs reported in “OtherNet –net”Net decreased by $0.1 million for the three months ended September 30, 2018 and September 30, 2017, respectively, net2019 compared to the same period in 2018. Other Expense (Income), Net changed from an expense of amounts deferred as regulatory assets for future recovery. There are $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 aofnon-service cost net periodic benefit costs reportedprovision is included in “Other Expense (Income), net”the Company’s income tax expense for the nine months ended September 30, 2018 and September 30, 2017, respectively, net of amounts deferred as regulatory assets2019.future recovery.decreasedincreased by $1.0$0.5 million and $6.1$5.2 million for the three and nine months ended September 30, 2018,2019, respectively, compared to the same periods in 2017. The decrease in the three month period reflects the lower tax rate onpre-tax earnings from the TCJA in 2018. The decreaseincrease in the nine month period reflects $5.0 million fromincome taxes associated with the lower tax rate onpre-tax earnings in 2018 and the current tax benefitCompany’s divestiture of $1.1 million of book/tax temporary differences turning at the lower income tax rate from the TCJA in 2018.netNet –calculated. adjustment mechanisms to recover specifically identified costs on a pass through basis. These reconciling rate adjustment 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. Three Months Ended
September 30, Nine Months Ended
September 30, 2018 2017 Change 2018 2017 Change $ 5.7 $ 5.3 $ 0.4 $ 17.3 $ 15.9 $ 1.4 0.7 0.8 (0.1 ) 1.6 1.9 (0.3 ) 0.2 0.3 (0.1 ) 0.5 0.8 (0.3 ) 6.6 6.4 0.2 19.4 18.6 0.8 (0.2 ) (0.2 ) — (0.6 ) (0.5 ) (0.1 ) (0.4 ) (0.4 ) — (0.9 ) (1.0 ) 0.1 (0.6 ) (0.6 ) — (1.5 ) (1.5 ) — $ 6.0 $ 5.8 $ 0.2 $ 17.9 $ 17.1 $ 0.8
September 30,
September 30, $ $ $ $ $ $ ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) $ $ $ ) $ $ $ (1) net increasedNet decreased $0.2 million and $0.8 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, 2018, respectively,2019, Interest Expense, Net was essentially unchanged compared to the same periodsperiod in 2017. These increases primarily reflect2018, reflecting lower interest on long-term debt and higher interest income on AFUDC, offset by interest on higher levels of long-term debt.CAPITAL REQUIREMENTS2018,2019, September 30, 20172018 and December 31, 2017,2018, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.$202.5$187.1 million for the nine months ended September 30, 2018.2019. Total gross repayments were $171.7$220.7 million for the nine months ended September 30, 2018.2019. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30, 2018,2019, September 30, 20172018 and December 31, 2017: Credit Facility ($ millions) September 30, December 31, 2018 2017 2017 $ 120.0 $ 120.0 $ 120.0 69.1 111.9 38.3 — 1.1 — $ 50.9 $ 7.0 $ 81.7 $ $ $ $ $ $ 2018,2019, September 30, 20172018 and December 31, 2017,2018, 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.)November 1, 2017,September 12, 2019, Northern Utilities issued $20$40 million of Notes due 20272049 at 3.52% and $30 million of Notes due 2047 at 4.32%. Fitchburg issued $10 million of Notes due 2027 at 3.52% and $15 million of Notes due 2047 at 4.32%. Granite State issued $15 million of Notes due 2027 at 3.72%4.04%. Northern Utilities Fitchburg and Granite State used the net proceeds from these offerings to refinance higher cost long-term debt that matured in 2017,this offering to repay short-term debt and for general corporate purposes. Approximately $0.7$0.2 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.TheThis capital lease matures on September 30, 2020. Aswas paid in full in the second quarter of September 30, 2018, there are $2.7 million of current and $3.0 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.2018,2019, there were approximately $5.6$4.3 million of guarantees outstanding.$9.0 million and $8.5$8.4 million of natural gas storage inventory at September 30, 2018,2019, September 30, 20172018 and December 31, 2017,2018, 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 iswas $0.1 million and iswas recorded in Accounts Payable at September 30, 2018. The amount of natural gas inventory released in September 2017 and payable in October 2017 was $0.1 million and was recorded in Accounts Payable at September 30, 2017. The amount of natural gas inventory released in December 20172018 and payable in January 20182019 was $3.1$0.9 million and was recorded in Accounts Payable at December 31, 2017.The Company also guarantees the payment of principal, interest and other amounts payable on the 7.15% notes issued by Granite State. As of September 30, 2018, the principal amount outstanding for the 7.15% Granite State notes was $3.3 million.2018,2019, there were approximately $5.6$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 POLICIESFebruary 1, 2018.2018,2019, the Company and its subsidiaries had 513503 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.2018,2019, a total of 165162 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, 2018:2019:Employees CoveredCBA ExpirationFitchburg47 05/31/2019Northern Utilities NH Division34 06/05/2020 Northern Utilities ME Division 39 03/20212022 Granite State 3 03/31/2021 Unitil Energy 37 05/20232021 Unitil Service 5 the CompanyUnitil 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, 20182019 and September 30, 2018 were 3.3%3.4% and 2.5%3.3%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 20182019 and September 30, 20172018 were 3.2%3.6% and 2.3%3.2%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 20172018 was 2.4%3.3%.Unitil Corporation’sUnitil’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.REGULATORY MATTERS Three Months Ended
September 30, Nine Months Ended
September 30, 2018 2017 2018 2017 $ 25.7 $ 25.1 $ 147.4 $ 131.9 61.4 57.5 167.6 154.4 1.1 1.4 3.5 4.5 88.2 84.0 318.5 290.8 8.1 8.3 67.0 56.6 35.5 32.7 97.1 84.3 16.4 16.9 51.5 49.4 12.4 10.8 37.4 35.2 5.5 4.9 16.5 15.6 77.9 73.6 269.5 241.1 10.3 10.4 49.0 49.7 6.0 5.8 17.9 17.1 1.1 0.9 4.1 3.7 3.2 3.7 27.0 28.9 0.4 1.4 5.0 11.1 $ 2.8 $ 2.3 $ 22.0 $ 17.8 $ 0.19 $ 0.16 $ 1.49 $ 1.27 14.8 14.1 14.8 14.1 $ 0.365 $ 0.36 $ 1.095 $ 1.08 $ $ $ $ ) $ $ $ $ $ $ $ $
September 30, December 31, 2018 2017 2017 $ 6.3 $ 10.9 $ 8.9 52.3 45.8 67.4 36.0 39.2 53.3 10.1 9.5 5.8 7.2 7.3 6.9 8.7 9.3 9.0 120.6 122.0 151.3 712.7 646.7 699.6 485.6 454.6 476.7 82.1 36.0 67.4 68.4 113.0 35.5 1,348.8 1,250.3 1,279.2 326.5 303.6 307.7 1,022.3 946.7 971.5 111.6 102.0 109.6 10.0 9.2 9.5 121.6 111.2 119.1 $ 1,264.5 $ 1,179.9 $ 1,241.9 $ $ $ $ $ $ September 30, December 31, 2018 2017 2017 $ 27.4 $ 24.1 $ 41.5 69.1 111.9 38.3 31.8 29.8 29.8 12.2 15.0 9.2 15.0 12.9 9.7 3.1 3.1 3.1 21.9 19.5 19.4 180.5 216.3 151.0 142.4 155.0 150.1 86.4 109.2 82.9 91.2 84.8 84.3 47.9 — 48.9 3.4 6.4 5.7 6.6 6.3 5.9 377.9 361.7 377.8 361.1 303.6 376.3 278.3 243.4 275.8 66.5 54.7 60.8 344.8 298.1 336.6 0.2 0.2 0.2 345.0 298.3 336.8 706.1 601.9 713.1 $ 1,264.5 $ 1,179.9 $ 1,241.9 $ $ $ $ $ $ Nine Months Ended
September 30, 2018 2017 $ 22.0 $ 17.8 37.4 35.2 4.6 11.2 15.1 7.1 17.3 10.3 (4.3 ) (1.2 ) 3.0 4.6 (14.1 ) (8.3 ) 3.7 (2.6 ) (5.7 ) (5.1 ) (9.0 ) 5.7 70.0 74.7 (76.3 ) (84.2 ) (76.3 ) (84.2 ) 30.8 30.0 (13.5 ) (0.4 ) (2.3 ) (1.8 ) 4.1 1.1 (16.3 ) (15.3 ) 0.9 1.0 3.7 14.6 (2.6 ) 5.1 8.9 5.8 $ 6.3 $ 10.9 $ 15.6 $ 15.2 $ 0.4 $ — $ 2.3 $ 2.5 $ 1.2 $ 1.8 $ $ ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) $ $ $ $ $ $ $ $ $ $ $ $ Common
Equity Retained
Earnings Total $ 277.9 $ 69.1 $ 347.0 2.8 2.8 (5.4 ) (5.4 ) 0.1 0.1 0.3 0.3 $ 278.3 $ 66.5 $ 344.8 $ 242.7 $ 57.5 $ 300.2 2.3 2.3 (5.1 ) (5.1 ) 0.4 0.4 0.3 0.3 $ 243.4 $ 54.7 $ 298.1
Earnings $ $ $ ) ) $ $ $ $ $ $ ) ) $ $ $ shares and per share data) Common
Equity Retained
Earnings Total $ 275.8 $ 60.8 $ 336.6 22.0 22.0 (16.3 ) (16.3 ) 1.5 1.5 1.0 1.0 $ 278.3 $ 66.5 $ 344.8 $ 240.7 $ 52.2 $ 292.9 17.8 17.8 (15.3 ) (15.3 ) 1.7 1.7 1.0 1.0 $ 243.4 $ 54.7 $ 298.1
Earnings $ $ $ ) ) $ $ $ $ $ $ ) ) $ $ $ NOTE SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES are, which the Company sold in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. three three are, which the Company divested of in the first quarter of 2019, were wholly-owned subsidiaries of Unitil Resources. Usource providesprovided brokering and advisory services to large commercial and industrial customers in the northeastern United States.20182019 are not necessarily indicative of results to be expected for the year ending December 31, 2018.2019. 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 Form2017,2018, as filed with the Securities and Exchange Commission (SEC) on February 1, 2018,January 31, 2019, for a description of the Company’s Basis of Presentation. -In the first quarter of 2018, the Company adopted Accounting Standards Update (ASU)2014-09, and its subsequent clarifications and amendments outlined in ASU2015-14, ASU2016-08, ASU2016-10 and ASU2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018, with the cumulative impact on contracts not yet completed as of December 31, 2017 recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the three and nine months ended September 30, 2018. As discussed below, the Company plans to disclose billed and unbilled revenue separately from rate adjustment mechanism revenue in the Notes to the Consolidated Financial Statements for periods in 2018 going forward, and will also provide this disclosure for prior periods for informational purposes. The lower revenues reported in the three and nine months ended 2018 to account for the reduction in the corporate income tax rate under the Tax Cuts and Jobs Act $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ ) ) $ $ $ $ $ $ ) ) ) $ $ $ MDPU.Massachusetts Department of Public Utilities (MDPU). The Company estimates that revenue decoupling applies to approximatelyconductswhich, as discussed previously, the Company divested of on March 1, 2019. Usource conducted its business activities as a broker of competitive energy services. Usource doesdid not take title to the electric and gas commodities which arewere the subject of the brokerage contracts. The Company recordsrecorded energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource partnerspartnered with certain entities to facilitate these brokerage services and payspaid these entities a fee under revenue sharing agreements.As discussed above, the Company adopted ASU2014-09 in the first quarter of 2018. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. ASU2014-09 requires that payments made by Usource to third parties (Channel Partners) for revenue sharing agreements are recognized net, as a reduction from revenue, where those payments were previously recognized gross as an operating expense. Therefore, beginning in 2018 and going forward, payments made by Usource to Channel Partners for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU2014-09, payments by Usource to third parties for revenue sharing agreements are included as “Operation and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. Those Channel Partner payments were $0.3 million and $0.3 million in the three months ended September 30, 2018 and 2017, respectively. Channel Partner payments were $0.8 million and $0.8 million in the nine months ended September 30, 2018 and 2017, respectively.If ASU2014-09 had been in effect for the three and nine months ended September 30, 2017, the result would have been corresponding reductions of $0.3 million and $0.8 million, respectively, in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings as shown in the tables below. Three Months Ended September 30, As
Reported If ASU2014-09
Had Been in
Effect 2018 2017 $ 1.4 $ 1.4 0.3 0.3 $ 1.1 $ 1.1 Three Months Ended September 30, As
Reported If ASU2014-09
Had Been in
Effect 2018 2017 $ 16.4 $ 16.6 Nine Months Ended September 30, As
Reported If ASU2014-09
Had Been in
Effect 2018 2017 $ 4.3 $ 4.5 0.8 0.8 $ 3.5 $ 3.7 Nine Months Ended September 30, As
Reported If ASU2014-09
Had Been in
Effect 2018 2017 $ 51.5 $ 48.6 Retirement Benefit Costs – The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan) and the Unitil Corporation Supplemental Executive Retirement Plan (SERP).The net periodic benefit costs associated with these benefit plans consist of service cost and other components (See Note 9 to the Consolidated Financial Statements). In the first quarter of 2018, the Company adopted ASUNo. 2017-07, “Compensation – Retirement Benefits (Topic 715) which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement.Accordingly, for all periods presented in the Consolidated Financial Statements in this Form10-Q for the quarter ended September 30, 2018, the service cost component of the Company’s net periodic benefit costs is reported in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings while the other components of net periodic benefit costs are reported in the “Other Expense (Income), net” section of the Consolidated Statements of Earnings. Prior to adoption, the Company reported all components of its net periodic benefit costs in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. The change in presentation for three and nine months ended September 30, 2018 resulted in a reduction of “Operations and Maintenance” and an increase in “Other Expense (Income), net” on the Consolidated Statements of Earnings for the prior periods. There are $1.2 million and $0.9 million ofnon-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the three months ended September 30, 2018 and September 30, 2017, respectively, net of amounts deferred as regulatory assets for future recovery. There are $4.1 million and $3.6 million ofnon-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the nine months ended September 30, 2018 and September 30, 2017, respectively, net of amounts deferred as regulatory assets for future recovery.2018,2019, September 30, 20172018 and December 31, 2017,2018, the Unitil subsidiaries had deposited $3.5 million, $3.2 million $4.8 million and $2.9$3.5 million, respectively to satisfy their In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of September 30, 2018, September 30, 2017 and December 31, 2017.2018,2019, September 30, 20172018 and December 31, 2017,2018, which is included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows: September 30, December 31, 2018 2017 2017 $ 1.2 $ 1.5 $ 1.6 $ $ $ 2018,2019, September 30, 2018 and December 31, 2017. September 30, December 31, 2018 2017 2017 $ 26.4 $ 31.3 $ 39.5 9.6 7.9 13.8 $ 36.0 $ 39.2 $ 53.3 $ $ $ $ $ $ 2018,2019, September 30, 20172018 and December 31, 2017. September 30, December 31, 2018 2017 2017 $ 9.5 $ 8.9 $ 5.4 0.6 0.6 0.4 $ 10.1 $ 9.5 $ 5.8 $ $ $ $ $ $ gas inventoryGas Inventory as of September 30, 2018,2019, September 30, 20172018 and December 31, 2017 which are recorded on the Consolidated Balance Sheets in Prepayments and Other. September 30, December 31, 2018 2017 2017 $ 0.4 $ 0.4 $ 0.4 0.4 0.2 0.1 0.1 0.1 0.1 $ 0.9 $ 0.7 $ 0.6 $ $ $ $ $ $ 2018,2019, September 30, 20172018 and December 31, 2017,2018, 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, $84.8and $90.7 million, respectively.$84.3liabilities 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 respectively. September 30, December 31, 2018 2017 2017 $ 88.0 $ 76.2 $ 84.5 24.8 28.2 36.0 6.3 6.8 7.2 8.9 9.9 9.5 5.9 6.7 6.5 4.1 5.5 5.4 138.0 133.3 149.1 26.4 31.3 39.5 $ 111.6 $ 102.0 $ 109.6 $ $ $ $ $ $ September 30, December 31, 2018 2017 2017 $ 12.2 $ 11.6 $ 6.9 — 3.4 2.3 47.9 — 48.9 60.1 15.0 58.1 12.2 15.0 9.2 $ 47.9 $ — $ 48.9 $ $ $ $ $ $ Included in Regulatory Assets asAs of September 30, 20182019 there are $6.1 years. Regulatorsyears which regulators have authorized recovery of, these expenditures, 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.other than the regulatory approved hedging program, described below, qualifiescurrently qualify as a derivative instrument under the guidance set forth in the FASB Codification.hasbelieves that the power purchase obligations under these long-term contracts will have a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service. Under the program, the Company may purchase call option contracts on NYMEX natural gas futures contracts for future winter period months.Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically basedmaterial impact on the NYMEX closing pricescontractual obligations and regulatory assets of Fitchburg, once they qualify for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Clause.As of September 30, 2018, September 30, 2017 and December 31, 2017 the Company had zero, 1.2 billion and 0.6 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.As of September 30, 2018, September 30, 2017 and December 31, 2017, the Company’s derivatives that are not designated as hedging instruments under FASB ASC815-20 have a fair value of $0, $0.1 million and less than $0.1 million, respectively. In 2015, theestablishedhas 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 Supplemental Executive RetirementSERP Plan (“SERP”) (See further discussion of the SERP Plan in Note 9.2018,2019, September 30, 20172018 and December 31, 2017,2018, 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 $3.4 million and $3.6$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 net. September 30, December 31, 2018 2017 2017 $ 3.0 $ 1.9 $ 2.1 2.3 1.5 1.5 $ 5.3 $ 3.4 $ 3.6 $ $ $ $ $ $ $ $ $ $ $ as current and noncurrent Energy Supply Obligations on the Company’s Consolidated Balance Sheets. The noncurrentcurrent portion of these obligations is recorded as Energy Supply Obligations and the noncurrent portion is recordedincluded in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets. September 30, December 31, 2018 2017 2017 $ 9.5 $ 8.9 $ 5.4 5.2 3.7 4.0 0.3 0.3 0.3 15.0 12.9 9.7 0.7 1.0 0.9 $ 15.7 $ 13.9 $ 10.6 $ $ $ $ $ $ maintain accrued revenuedefer 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.electricthe purchase of clean energy and/or renewable energy creditscertificates (RECs) pursuant to Massachusetts legislation, specifically, theAn Act Relative to Green Communities of 2008 and the(“Green Communities Act”, 2008), An Act Relative to Competitively Priced Electricity (2012) in the Commonwealth (2012) and the MDPU’s regulations implementing the legislation.An Act to Promote Energy Diversity (“Energy Diversity Act”, 2016). The generating facilities associated with threefour of these contracts have been constructed and are now operating. A recent round of long-term renewable energySince 2017, the Company has participated in two major statewide procurements was conducted during 2016which resulted in contracts for imported hydroelectric power and severalassociated transmission and for offshore wind generation. The contracts were finalized and submitted toapproved by the MDPU in September, 2017 for approval. the second quarter of 2019.procurements have been issuedlong-term clean energy contracts are expected in compliance with the Energy Diversity Act and An Act to Promote a Clean Energy Diversity (2016)Future (2018). Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.In August 2018, the FASB issued Accounting Standards Update (ASU)No. 2018-14, “Compensation – Retirement Benefits – Defined Benefit Plans – General (Sutopic715-20)” which amends existing guidance to add, remove and clarify disclosure requirements related to defined benefit pension and other postretirement plans. The ASU is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The Company plans to adopt this ASU in the first quarter of 2020 and does not expect that it will have a material impact on the Company’s Consolidated Financial Statements.In June 2018, the FASB issued ASUNo. 2018-07, “Compensation – Stock Compensation (Topic 718)” which amends the existing guidance relating to the accounting for nonemployee share-based payments. Under this ASU, most of the guidance on share-based payments to nonemployees will be aligned with the requirements for share-based payments granted to employees. The ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted this ASU in the second quarter of 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.In March 2017, the FASB issued ASUNo. 2017-07, “Compensation – Retirement Benefits (Topic 715)” which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU became effective for the Company on January 1, 2018. The change in capitalization of retirement benefits did not have a material impact on the Company’s Consolidated Financial Statements. “LeasesLeases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company plans to adoptadopted the standard as of January 1, 2019. The Company will elect 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 will also elect 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 will make an accounting policy election to keep leases with an initial term of 12 months or less off of the balance sheet. The Company will recognize those lease paymentsSee “Leases” above in the Consolidated Statements of Earnings on a straight-line basis over the lease term. The Company expects that adoption of the standard will result in recognition of additional net lease assets and lease liabilities as of January 1, 2019. The Company does not believe the standard will have a material effect on its Consolidated Statements of Earnings and Consolidated Statements of Cash Flows.In May 2014, the FASB issued ASUNo. 2014-09, “Revenue from Contracts with Customers (Topic 606)”, which amends existing revenue recognition guidance, effective January 1, 2018. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements.The majority of the Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue recognition for such sales.The Company used the modified retrospective method when adopting the new standard on January 1, 2018. The new guidance did not have a material impact to the Consolidated Financial Statements. (See “Utility Revenue Recognition” and “Other Operating Revenue –Non-regulated” above.)In January 2016, the FASB issued Accounting Standards Update (ASU)2016-01 which addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. A financial instrument is defined as cash, evidence of ownership interest in a company or other entity, or a contract that both: (i) imposes on one entity a contractual obligation either to deliver cash or another financial instrument to a second entity or to exchange other financial instruments on potentially unfavorable terms with the second entity and (ii) conveys to that second entity a contractual right either to receive cash or another financial instruments from the first entity or to exchange other financial instruments on potentially favorable terms with the first entity. The ASU became effective for the Company on January 1, 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.pronouncementspronouncement discussed above, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.impactedwould result in adjustment to or disclosure in its unaudited consolidated financial statements.NOTE DIVIDENDS DECLARED PER SHARE 24/1823/19 29/1827/19 15/1813/19 0.365 0.37025/1824/19 1819 1819 0.365 0.37025/1824/19 1819 1819 0.365 0.3701819 1819 1819 0.365 0.37010/25/17 11/29/17 11/15/17 $0.36007/26/17 08/1718 08/1718 0.360 0.36504/26/17 05/30/17 05/16/17 0.360 0.36501/1718 02/28/17 02/14/17 0.360 0.365NOTE SEGMENT INFORMATION20182019 and September 30, 20172018 and as of December 31, 20172018 (millions): Gas Electric Non-
Regulated Other Total $ 19.6 $ 60.9 $ — $ — $ 80.5 6.1 0.5 — — 6.6 — — 1.1 — 1.1 $ 25.7 $ 61.4 $ 1.1 $ — $ 88.2 (3.2 ) 4.5 0.3 1.2 2.8 30.9 7.2 — 1.0 39.1 $ 25.1 $ 57.5 $ 1.4 $ — $ 84.0 (2.1 ) 4.1 0.3 — 2.3 26.0 10.0 — 3.3 39.3 $ 151.1 $ 176.2 $ — $ — $ 327.3 (3.7 ) (8.6 ) — — (12.3 ) — — 3.5 — 3.5 $ 147.4 $ 167.6 $ 3.5 $ — $ 318.5 9.1 10.2 0.9 1.8 22.0 53.1 20.8 — 2.4 76.3 730.0 485.7 6.6 42.2 1,264.5 $ 131.9 $ 154.4 $ 4.5 $ — $ 290.8 7.9 9.3 0.8 (0.2 ) 17.8 48.7 23.8 — 11.7 84.2 661.2 461.2 7.3 50.2 1,179.9 $ 714.3 $ 476.9 $ 6.7 $ 44.0 $ 1,241.9 NOTE $ $ $ $ $ $ $ $ $ $ ) $ $ $ $ $ $ $ $ $ $ ) $ $ $ $ $ ) ) $ $ $ $ $ $ $ $ $ $ ) ) ) $ $ $ $ $ DEBT2018, September2019, Sept20172018 and December 31, 20172018 are shown below: September 30, December 31, 2018 2017 2017 $ 20.0 $ 20.0 $ 20.0 30.0 30.0 30.0 10.0 15.0 15.0 7.5 9.0 7.5 20.0 20.0 20.0 15.0 15.0 15.0 15.0 15.0 15.0 7.6 9.5 7.6 10.0 10.0 10.0 10.0 — 10.0 12.0 12.0 12.0 15.0 15.0 15.0 14.0 14.0 14.0 15.0 — 15.0 10.0 20.0 10.0 16.6 25.0 25.0 20.0 — 20.0 50.0 50.0 50.0 50.0 50.0 50.0 30.0 — 30.0 3.3 6.7 3.3 15.0 — 15.0 396.0 336.2 409.4 3.1 2.8 3.3 392.9 333.4 406.1 31.8 29.8 29.8 $ 361.1 $ 303.6 $ 376.3 $ $ $ — — $ $ $ (1) The Current Portion of Long-Term Debt includes sinking fund payments. September 30, December 31, 2018 2017 2017 $ 418.7 $ 383.0 $ 457.1 Credit Arrangements $ $ $ $202.5$187.1 million for the nine months ended September 30, 2018.2019. Total gross repayments were $171.7$220.7 million for the nine months ended September 30, 2018.2019. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30 2018,2019, September 30, 20172018 and December 31, 2017: Credit Facility ($ millions) September 30, December 31, 2018 2017 2017 $ 120.0 $ 120.0 $ 120.0 69.1 111.9 38.3 — 1.1 — $ 50.9 $ 7.0 $ 81.7
($ millions) $ $ $ — — $ $ $ 2018,2019, September 30, 20172018 and December 31, 2017,2018, 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.)weightedCompany 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.3.2%3.4% and 2.3% 3.3%20182019 and September 30, 2017,2018, respectively. The weighted average interest rate on all short-term borrowings for the twelve months ended December 31, 20172018 was 2.4%November 1, 2017,September 12, 2019, Northern Utilities issued $20$40 million of Notes due 20272049 at 3.52% and $30 million of Notes due 2047 at 4.32%. Fitchburg issued $10 million of Notes due 2027 at 3.52% and $15 million of Notes due 2047 at 4.32%. Granite State issued $15 million of Notes due 2027 at 3.72%4.04%. Northern Utilities Fitchburg and Granite State used the net proceeds from these offerings to refinance higher cost long-term debt that matured in 2017,this offering to repay short-term debt and for general corporate purposes. Approximately $0.7$0.2 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.TheThis capital lease matures on September 30, 2020. Aswas paid off in the second quarter of September 30, 2018, there are $2.7 million of current and $3.0 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.$9.0 million and $8.5$8.4 million of natural gas storage inventory at September 30, 2018,2019, September 30, 20172018 and December 31, 2017,2018, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2019 and payable inis $0.1wasiswas recorded in Accounts Payable at September 30, 2018. The amount of natural gas inventory released in September 2017 and payable in October 2017 was $0.1 million and was recorded in Accounts Payable at September 30, 2017. The amount of natural gas inventory released in December 20172018 and payable in January 20182019 was $3.1$0.9 million and was recorded in Accounts Payable at December 31, 2017.2018,2019, there were approximately $5.6$4.3 million of guarantees outstanding.Company also guaranteesbalance sheet classification of the paymentCompany’s lease obligations was as follows: $ $ $ $ $ principal, interestoperating lease obligations for the nine months ended September 30, 2019 was $1.1 million and other amounts payablewas included in Cash Provided by Operating Activities on the notes issued by Granite State.Consolidated Statements of Cash Flows. $ $ $ $ principal amount outstanding for the 7.15% Granite State notes was $3.3 million.NOTEpayment amounts as of September 30, 2018. $ $ $ $ COMMON STOCK AND PREFERRED STOCK14,119,893,14,815,58514,872,011, 14,876,955 and 14,872,01114,925,898 shares of common stock outstanding at September 30, 2017,2018, December 31, 20172018 and September 30, 2018,2019, respectively.Unitil Corporation Common Stock Offering - On December 14, 2017, the Company issued and sold 690,000 shares of its common stock at a price of $48.30 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $31.7 million and was used to make equity capital contributions to the Company’s regulated utility subsidiaries, repay short-term debt and for general corporate purposes.-–2018,2019, the Company sold 19,70015,793 shares of its common stock, at an average price of $46.97$56.29 per share, in$925,000.$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.-–2018, 37,5102019, 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 49,58150,917 and 89,32649,58120182019 and 2017,2018, respectively. The weighted average grant date fair value of these shares was $41.96$46.41 and $39.54,$41.96, respectively. The compensation expense associated with the issuance of shares under the StockPlan is being recognized over the vesting period and was $2.1$2.2 million and $2.6$2.1 million for the nine months ended September 30, 20182019 and 2017,2018, respectively. At September 30, 2018,2019, there was approximately $1.0$2.52.7 years. During the nine months ended September 30, 2018 there were 784 shares of Restricted Shares forfeited. There were no2018.20182019 in conjunction with the Stock Plan areis presented in the following table: Units Weighted
Average
Stock
Price 52,224 $ 36.22 — — 1,230 $ 46.87 — — 53,454 $ 36.47 $ $ $ 44,34353,454 Restricted Stock Units outstanding as of September 30, 20172018 with a weighted average stock price of $33.72. $36.47.2018,2019, there were 11,2759,918 fully-vested Restricted Stock Units issued to members of the Company’s Board of Directors.2018,2019, September 30, 20172018 and December 31, 20172018 is $1.7 million, $1.2 million $0.9 million and $1.0$1.3 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.September 30, 2017 and December 31, 2017.2018. 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, 20182019 and September 30, 2017,2018, respectively.NOTEREGULATORY MATTERSUNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTEREgulatory MattersTO THE FINANCIAL STATEMENTS IN ITEMto the Financial Statements in Item 8 OF PARTof Part II OF UNITIL CORPORATION’S FORMof Unitil Corporation’s Form 10-K FOR DECEMBER for December 31, 2017 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2018. 2018. has issued procedural orders directing how the tax law changes arewere to be reflected in rates, including requiring that the companies provide certain filings and calculations.rates. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC has also opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State (described below).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.division recently completed a basedivision’s 2013 rate case (described below). The MPUC’s final order in that docket incorporated the lower tax rates in the calculation of rates for the Company.Similarly, in New Hampshire, Northern Utilities’ New Hampshire division recently completed a base rate case proceeding (described below). The NHPUC’s final order in that docket approved a comprehensive settlement agreement amongallowed the Company the Staff of the Public Utilities Commission and the Office of Consumer Advocate which included the effect of the tax changes in the calculation of the revenue requirement. With respect to Unitil Energy, on April 30, 2018 the NHPUC approved the Company’s annual step increase pursuantimplement a TIRA rate mechanism to the provisions of its lastadjust base rate case, which included adjustments to account for the TCJA’s income tax changes.In Massachusetts, the MDPU issued an order opening an investigation into the effect ondistribution rates of the decrease in the federal corporate income tax rate on the MDPU’s regulated utilities, and required each utility subject to its jurisdiction to submit proposals to address the effects of the TCJA and to reduce its rates as of January 1, 2018. The MDPU consolidated an earlier petition filed by the Attorney General requesting such an investigation into its order. On June 29, 2018, the MDPU issued an order accepting Fitchburg’s proposal to decrease the annual revenue requirement of both its gas and electric divisions by $0.8 million each. The MDPU will address the refund of excess accumulated deferred income taxes in phase two of its investigation. An order is pending.On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which accounted for the effects of the TCJA in its rates. The settlement was approved by FERC on June 27, 2018, and complies with and satisfies the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reduction under the TCJA.Base Rate ActivityUnitil Energy – Base Rates –On April 20, 2017 the NHPUC approved a permanent increase of $4.1 million in electric base rates, and a three year rate plan with an additional rate step adjustment, effective May 1, 2017, of $0.9 million, followed by two rate step adjustments in May of 2018 and 2019annually 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).filing. The filing incorporated the revenue requirement of $3.3 millionproviding for 2017 plant additions, a reduction of $2.2 million for the effect of the federal tax decrease pursuant to the TCJA, along with the termination of theone-year $1.4 million reconciliation adjustment which had recouped the difference between temporary rates and final rates. The net effect of the three adjustments resulted in a revenue decreaseincrease of $0.3 million.last base rate order fromrates are decoupled, and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the MDPU, issuedamount that rates may be increased in April 2016, included the approval ofany year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. While a numberOn April 3, 2019, the DPU approved Fitchburg’s cumulative revenue requirement associated with the Company’s 2015 and 2016 capital expenditures, an increase of the capital cost recovery filings may remain pending fromyear-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. June 28,compliance reportcumulative revenue requirement of $0.9 million associated with the Company’s 2015, 2016 and 2017 capital investments for calendar year 2017. This matter remains pending.Fitchburg – Electric Grid Modernization –expenditures. On May 10,December 27, 2018, the MDPU issued an order approving a three year grid modernization investment plan for Fitchburg for the period 2018 through 2020 with a spending cap of $4.4 million. The order provides for a cost recovery mechanism for incremental capital investments and operation and maintenance (O&M) expenses. The electric distribution companies in Massachusetts jointly filed compliance filings in August 2018 including 1) revised proposed performance metrics designed to addresspre-authorized grid-facing investments, 2) a proposed evaluation plan for the three-year investment term, and 3) a model tariff for cost recovery including proposed protocol for identifying and tracking incremental O&M expenses. Approval of these filings is pending. The next three year investment plan is due July 1, 2020 for the period 2021 through 2023, and is required to include a five year strategic plan for 2021 – 2025.Fitchburg – Solar Generation –On November 9, 2016, the MDPU approved Fitchburg’s petition to develop a 1.3 MW solar generation facility located on Company property in Fitchburg Massachusetts. Construction of the solar generating facility was completed and the facility began generating power on November 22, 2017. On April 2, 2018, Fitchburg submitted its first filing pursuant to its Solar Cost Adjustment tariff, by which the Company recovers its annual revenue requirement related to its investment in the solar generation facility. The filing sought a net amount of approximately $0.3 million for recovery effective June 1, 2018. The recovery of this amount in rates was approved, by the MDPU on May 31, 2018,effective January 1, 2019, subject to further investigation and reconciliation. A final orderFinal approval of the 2018 filing remains pending.pending.31;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. While a number of the filings under the GSEP tariff may remain pending fromyear-to-year in any given year, theincurred (the “GREC Filing”). The Company considers these to be routine regulatory proceedings and there are no material issues outstanding. Under this tariff,$0.9$1.0 million that went into effect on May 1, 2018,2019, subject to reconciliation. The amount that exceeded the cap, $0.6 reconciliation.Northern Utilities – Base Rates – Maine –On February 28, 2018, the MPUC issued its Final Order (Order) in Northern Utilities pending base rate case. The Order provided for an annuala revenue increase of $2.1 million before a reduction of $2.2 million to incorporate the effect of the lower federal income tax rate under the TCJA. The MPUC Order approved a return on equity of 9.5 percent and a capital structure reflecting 50 percent equity and 50 percent long-term debt. The Order also provides for a reduction in annual depreciation expense, reducing the Company’s annual operating costs by approximately $0.5 million, and addressed a number of other issues, including a change to therm billing, increases in other delivery charges, and cost recovery under the Company’s TAB Program and TIRA mechanism. The new rates and other changes became effective on March 1, 2018.Northern Utilities – Targeted Infrastructure Replacement Adjustment – 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). The TIRA had an initial term of four years and covered targeted capital expenditures in 2013 through 2016. In its Order in the current base rate case (see above), the MPUC approved an extension of the TIRA mechanism, with adjustment, 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, to recover the revenue requirements for 2017 eligible facilities.Northern Utilities – Targeted AreaBuild-out Program – Maine –In December 2015, the MPUC approved a Targeted AreaBuild-out (TAB) program and associated rate surcharge mechanism.program is designed to allow the economic extension of natural gas mains to new, targeted service areas in Maine. It allows customers in the targeted area the ability to pay a rate surcharge, instead of a large upfront payment or capital contribution to connect to the natural gas delivery system. The initial pilot of the TAB program was approved for the City of Saco, and is being built out over a period of three years, with the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco area. A second TAB program was approved for the Town of Sanford, and has the potential to add 2,000 new customers and approximately $2 million in annual distribution revenue in the Sanford area. In its base rate case Order (described above), the MPUC approved the inclusion of Saco TAB investments in rate base along with a cost recovery incentive mechanism for future TAB investments.Northern Utilities – Base Rates – New Hampshire –On May 2, 2018, the NHPUC approved a settlement agreement providing for an annual revenue increase of $2.6 million, a reduction of annual revenue of $1.7 million to reflect the effect of the TCJA, and a step increase of $2.3 million to recover post-test year capital investments, all effective May 1, 2018 (with the revenue increase of $2.6 million reconciling to the date of temporary rates of August 1, 2017 and the revenue decrease for TCJA reconciling to January 1, 2018), for a net increase of approximately $3.2 million. Under the agreement, the Company may file for a second step increase for effect May 1, 2019 to recover eligible capital investments in 2018, up to a revenue requirement cap of $2.2 million. If the Company chooses the option to implement the second step increase, the next distribution base rate case will be based on an historic test year of no earlier than twelve months ending December 31, 2020.Northern Utilities – Franchise Extensions – New Hampshire –On October 3, 2018, the NHPUC granted Northern Utilities authority to expand its previously limited franchise to provide natural gas service in the Towns of Kingston and Atkinson, New Hampshire to serve new industrial, commercial and residential customers. Northern Utilities has also petitioned the NHPUC to extend its franchise into the Town of Epping, New Hampshire, where new commercial and residential developments present the Company with opportunities for growth. The franchise petition for service to the Town of Eppingmatter remains pending. The settlement also provides that Granite State may not file a general (Section 4) rate case prior to April 30, 2019.NHPUC Energy Efficiency Resource Standard ProceedingOn August 2, 2016, Independent Statewide Examination of the NHPUC issuedSafety of the Commonwealth’s Gas Distribution System –order establishing an Energy Efficiency Resource Standard (EERS), an energy efficiency policyindependent 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 specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. The EERS includes a recovery mechanism to compensate the utilities for lost-revenue relatedrespect to the EERS programs, and performance incentives and processesCommonwealth’s gas distribution system, including recommendations for stakeholder involvement, evaluation, measurement and verification, and oversight of the EERS programs. In accordance with the Order, on Septemberimprovements. The evaluator issued a Phase 1 2017, the New Hampshire electric and gas utilities jointly filed a Statewide Energy Efficiency Plansummary report including preliminary recommendations for the period 2018-2020, which was approvedMDPU’s consideration on January 2, 2018. On September 14, 2018,May 13, 2019. The investigation isNew Hampshire electric and gas utilities jointly filed its 2019 update to the Statewide Energy Efficiency Plan. This filing is currently under review by the NHPUC.Unitil Energy – Electric Grid Modernization –In July 2015, the NHPUC opened an investigation into Grid Modernization to address a variety of issues related to Distribution System Planning, Customer Engagement with Distributed Energy Resources, and Utility Cost Recovery and Financial Incentives. The NHPUC engaged a consultant to direct a Working Group to investigate these issues and to prepareevaluator will produce a final report with recommendations forat the Commission. The final report was filed on March 20, 2017. This matter remains pending.Unitil Energy – Net Metering –Pursuant to legislation that became effective in May 2016,end of the NHPUC opened a proceeding to consider alternatives to the net metering tariffs currently in place. The NHPUC issued an Order on June 23, 2017. The Order removes the cap on the total amount of generation capacity which may be owned or operated by customer-generators eligible for net metering. The order also adopts an alternative net metering tariff for small customer-generators (those with renewable energy systems of 100 kW or less) which will remain in effect for a period of years while further data is collected and analyzed,time-of-use and other pilot programs are implemented, and a distributed energy resource valuation study is conducted. Systems that are installed or queued during this period will have their net metering rate structure “grandfathered” until December 31, 2040.process. The Company does not believebelieves that this proceedingexamination will havenot result in a material adverse impact on the Company’sits financial position, operating results or cash flows.– Recent Legislation –On September 13, 2018,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 legislature voted to override New Hampshire Governor Sununu’s veto of Senate Bill 365. The enacted legislation requires Unitil Energy to enter into a power purchase agreement with a trash incinerator located in its service territory to purchase the facility’s entire net electrical output for a period that is coterminous with Unitil Energy’s next six default service procurements. The procurement is to be priced at the adjusted energy rate derived from the default service rates approvedand Massachusetts, as directed by the NHPUC in each applicable default service supply solicitation proceeding. The anticipated higher cost differentialand MDPU; recovery of the ongoing costs of storm repairs incurred by Unitil Energy; and the actual wholesale energy costs for electric power purchase agreement is to be recovered through anon-by-passable charge applicable to all customers.Fitchburg – Electric Reconciliation Filing –The MDPU investigates and reviews Fitchburg’s annual filings which reconcile the costs and revenues in the Company’s various reconciliation accounts. Typically, the Reconciliation Filings are submitted during the fourth quarter for rates effective January 1natural gas incurred by each of the following year,three companies. Fitchburg, Unitil Energy and the MDPU approves them subject to reconciliationNorthern Utilities have been, and pending further investigation. Subsequently, during the course of the year, the MDPU engagesremain in more intensive review offull compliance with all directives and orders regarding these filings, including discovery and, when deemed necessary, the scheduling of evidentiary hearings. While a number of the Reconciling Filings may remain pending fromyear-to-year in any given year, thefilings. The Company considers these to be routine regulatory proceedings and there are no material issues outstanding.Service QualityMassachusetts RFPs –On March 1, 2018, Fitchburg submitted its 2017 Service Quality Reports for both its gas and electric divisionsaccordance with new Service Quality Guidelines issued by the MDPU in December 2015. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. The MDPU approved the gas division’s filing on October 22, 2018. The electric division’s filing is pending approval.Fitchburg – Energy Diversity –MassachusettsGovernor Baker signed into law H.45682016, “An Act to Promote Energy Diversity” on August 8, 2016. Among many sections inDiversity,” under Section 83C, the bill, the primary provision adds new sections 83c and 83d to the 2008 Green Communities Act. Section 83c requires everyMassachusetts electric distribution company (EDC)companies (EDCs), including Fitchburg, are required to jointly and competitively 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. The procurement requirement is subject to a determination byUnder Section 83D of the MDPU thatAct, the proposed long-term contractsEDCs are cost-effective. Section 83d further requires the EDCsrequired to jointly seek proposals for cost effective clean energy (hydro, solar and other)land-based wind) long-term contracts via one or more staggered solicitations the first of which shall be issued not later than April 1, 2017, for a total of 9,450,000 megawatt-hours by December 31, 2022. Emergency regulationsimplementingUnitil’s pro rata share of each of these new provisions, 220 C.M.R. § 23.00 et seq. and 220 C.M.R. § 24.00 et seq. were adopted by the MDPU on December 29, 2016, and adopted as final regulations on March 8, 2017. contracts is approximatelypursuant to Section 83d onin March 31, 2017, and project proposals were received on July 27, 2017. Finalafter selection of final projects concludedand 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 thefirst quarterpublic interest. Also, the MDPU approved the EDCs’ proposal to amend their respective tariffs to include the recovery of 2018, contracts were signed in June 2018 and on July 23, 2018,costs associated with the EDCs, including Fitchburg, filedcontracts. The Company believes that the 83dpower purchase obligations under these long-term contracts with MDPU for approval. This matter remains pending. will have a material impact on the contractual obligations and regulatory assets of Fitchburg, once certain conditions and contingencies are met.Projects pursuant to Section 83c onGeneration in June 29, 2017 and project proposals were received on December 20, 2017. Final selection of projects was made in late May 2018, contracts were signed in July 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed the 83ctwo long-term contracts, each for 400MW of offshore wind energy generation with MDPU for approval. This matter remains pending.Fitchburg – Recent Legislation –On August 9, 2018, Massachusetts Governor Baker signed into law H. 4857, “An Act to Advance Clean Energy.” The legislation contains numerous provisions, including: a requirement that increases the pace at which the Class 1 Renewable Portfolio Standard requirement increases, from the current pace of an additional 1 percent of sales each year to an additional 2 percent of sales each year during the period from January 1, 2020 through December 31, 2029; Electric supply contracts entered into after December 1, 2018 are required to provide a minimum percentage of kWh sales with clean peak resources, subject to regulations to be promulgated by the MDPU; Authorizes electric distribution companies to implement demand charges as part of a monthly minimum reliability charge provided the demand charge is based on system peak demand during the peak hours of the day and if affected customers are informed of the manner by which the demand charges are assessed and ways by which customers may manage and reduce demand; requires all gas distribution companies to report toApril 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 thea uniform manner, lost and unaccounted for gas each year; Requires electric distribution companiesthe public interest. Also, the MDPU approved the EDCs’ proposal to annually fileamend their respective tariffs to include the recovery of costs associated with the MDPU an Electric Distribution System Resiliency Report which must include heat mapscontracts. The Company believes that show the electric loadpower purchase obligations under these long-term contracts will have a material impact on the distribution system including loads during peak times, highlight the most congested or constrained areascontractual obligations and regulatory assets of the distribution system and identify areas of the system most vulnerable to outages due to high electricity demand, lack of local generation, and extreme weather events; Establishes an energy storage target of 1,000 megawatt (MW) hours to be achieved by December 31, 2025, and requires each electric distribution company to submit a report to the Massachusetts Department of Energy Resources (DOER) documenting the energy storage installation in their service territory; Requires the DOER to investigate the necessity of requiring electric distribution companies to jointly conduct additional offshore wind generation solicitations and procurement of up to 1,600 MW of capacity in addition to the 1,600 MW required in H.4568 “An Act to Promote Energy Diversity”. Many of these provisions require further development and implementation by the MDPU and DOER. Fitchburg intends to actively participate in all such proceedings and will comply with all regulatory directives and requirements resulting from these legislative changes.Fitchburg – Clean Energy RFP –Pursuant to Section 83a of the Green Communities Act in Massachusetts and similar clean energy directives established in Connecticut and Rhode Island, state agencies and the electric distribution companies in the three states, including Fitchburg,Fitchburg.clean energy resources (including Class I renewable generation and large hydroelectric generation) in November 2015. The RFP sought proposalsLong-Term Contracts for clean energy and transmission projects that can deliver new renewable energy to the three states. Project proposals were received in January 2016. Selection of contracts concluded during the fourth quarter of 2016 and contract negotiations concluded duringOffshore Wind Energy Generation on May quarter of 2017. On September 20, 2017, Fitchburg, alongsolicitation pursuant to Section 83C and with the other three EDCs, filed forDepartment’s approval of the purchase power agreements which were negotiatedVineyard Wind contracts for 800 MW of offshore wind energy generation as a result of the joint solicitation. A hearing onfirst solicitation, the merits was held in February 2018.remaining obligation under 83C is to procure an additional 800 MW of offshore wind energy generation. The MDPU approved the agreements on June 15, 2018.Fitchburg – Other –On August 25, 2017, the Massachusetts Department of Energy Resources (DOER) issued its final Solar Massachusetts Renewable Target (SMART) Program regulations. These regulations were promulgated pursuantEDCs intend to Chapter 75purchase at leastActs of 2016, which required the DOERremaining 800 MW obligation under this RFP.establish a new solar incentive program. The regulation is designedoccur on November 8, 2019, contracts are to support the continued development of an additional 1,600 MW of solar renewable energy generating sources via a declining block compensation mechanism. On September 12, 2017, the Massachusetts electric utilities jointlybe executed by December 13, 2019, and filed a model SMART tariffMDPUDepartment on January 10, 2020.implement the programhave its procurement practices examined, and propose a cost recovery mechanism. Hearings on the merits were held in late March and early April 2018. The MDPU issued its Order on September 26, 2018 making the program effective on that date. Utilities are required to file a revised model tariff prior to October 15, 2018 and, once approved, Fitchburg is required to make a company specific compliance filing. On or before November 1 of each year the Company is requiredcooperating with a consultant engaged by the MPUC to submit to the MDPUconduct this ongoing investigation. The Company believes that this investigation will not result in a material impact on its annual SMART Factor cost recovery filing for effect January 1 of the next year. This matter remains pending.remains pending.remanded the proceedingIn early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court, (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint sought an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The Massachusetts Supreme Judicial Court issued an order denying class certification status in July 2016, though the plaintiffs’ individual claims remain pending. The Company continues to believe these claims are without merit and will continue to defend itself vigorously.20172018 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2018.2018,2019, 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 issubstantially completed remediation ofactivities at all sites, thoughsites; however, on site monitoring continues and it is possibleat several sites which may result in future remedial actions as directed by the applicable regulatory agency. In July 2019, the NH DES requested that future activities mayNorthern Utilities review modeled expectations for groundwater contaminants against observed data at Rochester. The results of the review, along with any recommendations, will be required. Supplementalsubmitted to the NH DES in January 2020. The Company has accrued $0.7 million for estimated costs to complete the remediation at the Exeter MGP commencedRochester site, which is included in the second quarter of 2018 and was completed in the third quarter of 2018. seven-year five-yearfuture cleanupand periodic, regulatory review costs for the completed permanent remediation of the Sawyer Passway site with asite. A corresponding Regulatory Asset was recorded to reflect that the recovery of these environmental remediation costs areis probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods.for the nine months ended September 30, 2018 and 2017. The Company’s current and noncurrent environmental obligationswhich are recorded on the Company’s Consolidated Balance Sheetsincluded in Other Current Liabilities and Other Noncurrent Liabilities, respectively.Environmental Obligations ($ millions) Fitchburg Northern
Utilities Total Nine months ended September 30, 2018 2017 2018 2017 2018 2017 $ 0.1 $ 0.1 $ 2.0 $ 1.8 $ 2.1 $ 1.9 — — 0.6 0.5 0.6 0.5 0.1 — 0.5 0.2 0.6 0.2 — 0.1 2.1 2.1 2.1 2.2 — 0.1 0.6 0.4 0.6 0.5 $ — $ — $ 1.5 $ 1.7 $ 1.5 $ 1.7 NOTErespectively, on the Company’s Consolidated Balance Sheets as of September 30, 2019 and 2018.
Utilities $ $ $ $ $ $ $ $ $ $ $ $ 2017 2012018 201 generated additional net operating loss (NOL) carryforwardcurrent pension cost deductions, tax repair deductions, tax depreciation and research and development deductions.2018,2019, the CompanyNOL carryforwardNOLC assets of $18.2$11.9 millionNOLNOLC carryforward assets will begin to expire in 2029. In addition, at September 30, 2018,December 31, 201$3.4$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.In March 2018, Unitil Corporation received notice that its Federal Income Tax return filings for the years ended December 31, 2015 and December 31, 2016 are under examination by the IRS. Currently, the Company believes that the ultimate resolutionIn December 2017, the Tax Cuts and Jobs Act of 2017 (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.On March 15, 2018 FERC issued its Notice of Proposed Rulemaking in Docket No.RM18-11-000 in which FERC provided specific guidance on the flow back of excess ADIT. The amount of the reduction to ADIT that was 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. Subject to regulatory approval, the Company expects to flow back to customers a net $47.1 million of the excess ADIT created as a result of the lowering of the statutory tax rate by the TCJA.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 excess ADIT amounts will be subject to flow back to customers in future utility rates according to the Average Rate Assumption Method (ARAM). The Company estimates the ARAM flow back period to be between fifteen and twenty years.The Company’s regulators are expected to issue ratemaking guidance in future periods that will determine the final disposition of there-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.In addition to the excess $47.1 million ADIT amounts the Company expects to flow through to customers in utility rates, as noted above, there was $1.8 million of excess ADIT 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 recognize a benefit in its tax provision as the underlying book/tax temporary differences reverse in the current and future periods.The Company evaluated its tax positions at September 30, 2018 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 Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2015; December 31, 2016; and December 31, 2017.Maine and consumption tax in New Hampshire.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 RETIREMENT BENEFIT OBLIGATIONS(SERP)(SERP Plan) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the Consolidated FinancialFinancial Statements in the Company’s Form20172018 as filed with the SEC on February 1, 2018January 31, 2019 for additional information regarding these plans. 2018 2017 3.60 % 4.10 % 3.00 % 3.00 % 7.75 % 7.75 % 7.50 % 8.00 % 4.50 % 4.00 % 2024 2025 Used to Determine Plan Costs % % % % % % % % % % Pension Plan PBOP Plan SERP 2018 2017 2018 2017 2018 2017 $ 848 $ 824 $ 733 $ 744 $ 122 $ 115 1,469 1,514 852 978 101 98 (1,946 ) (1,826 ) (409 ) (337 ) — — 81 66 327 350 47 47 1,447 1,165 346 524 121 74 1,899 1,743 1,849 2,259 391 334 (962 ) (932 ) (930 ) (1,226 ) (113 ) (99 ) $ 937 $ 811 $ 919 $ 1,033 $ 278 $ 235 Pension Plan PBOP Plan SERP 2018 2017 2018 2017 2018 2017 $ 2,544 $ 2,471 $ 2,199 $ 2,231 $ 366 $ 345 4,407 4,543 2,554 2,935 303 294 (5,838 ) (5,479 ) (1,227 ) (1,010 ) — — 243 197 981 1,049 141 141 4,341 3,496 1,038 1,573 365 222 5,697 5,228 5,545 6,778 1,175 1,002 (2,590 ) (2,402 ) (2,557 ) (3,418 ) (339 ) (297 ) $ 3,107 $ 2,826 $ 2,988 $ 3,360 $ 836 $ 705 $ $ $ $ $ $ ) ) ) ) ) ) ) ) ) ) $ $ $ $ $ $ $ $ $ $ $ $ ) ) ) ) ) ) ) ) ) ) $ $ $ $ $ $ 2018,2019, the Company had made $16.6$6.9 million and $3.0$2.8 million of contributions to its Pension and PBOP Plans, respectively, in 2018.2019. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 20182019 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.2018,2019, the Company had made $87,500$0.4 million of benefitbenefit payments under the SERP Plan in 2018.2019. The Company presently anticipates making an additional $313,100$0.2 million of benefit payments under the SERP Plan in 2018.Item 3.Quantitative and Qualitative Disclosures About Market Risk2018.2019. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of September 30, 20182019 that the Company’s disclosure controls and procedures (as defined in Exchange Act RulesItem 1A.Risk Factors20172018 as filed with the SEC on February 1, 2018.Item 2.Unregistered Sales of Equity Securities and Use of Proceeds2018.2018,2019, the Company will periodically repurchase shares of its Common Stock on the open market related to Employee Length of Service Awards and the stock portion of the Directors’ annual retainer 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 $92,700$195,000 in value of shares have been purchased or, if sooner, on May 1, 2019.2018. 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 — — — $ 85,020 — — — $ 85,020 190 $ 50.18 190 $ 75,366 190 $ 50.18 190 Item 5.Other Information
Number
of Shares
Purchased
Price Paid
per Share
Shares Purchased as
Part of Publicly
Announced Plans or
Programs
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs $ $ $ 25, 2018,24, 2019, the Company issued a press release announcing its results of operations for the three-three and nine-monthnine month periods ended September 30, 2018.2019. The press release is furnished with this Quarterly Report on FormItem 6.Exhibits(a) ExhibitsExhibit No.
No. Reference* 4.1 July 25, 2018 1-8858)) 4.2 Amended and Restated Note issued to Bank of America, N.A. July 25, 2018 4.3 Amended and Restated Note issued to Citizens Bank, N.A. Exhibit 4.3 to Form 8-K dated July 25, 2018 (SEC FileNo. 1-8858) 4.4 Amended and Restated Note issued to TD Bank, N.A.Exhibit 4.4 to Form 8-K dated July 25, 2018 (SEC FileNo. 1-8858) 10.1Second Amended and Restated Credit Agreement dated July 25, 2018 among Unitil Corporation, Bank of America, N.A., as administrative agent, and the Lenders (included as Exhibit 4.1)Exhibit 10.1 to Form 8-K dated July 25, 2018 (SEC FileNo. 1-8858) 10.2Amended and Restated Form of Severance Agreement (Three-Year Term)Filed herewith 10.3Amended and Restated Form of Severance Agreement(Two-Year Term)Exhibit 10.2 to Form 8-K dated July 25, 2018 (SEC FileNo. 1-8858) 10.4Amended and Restated Form of Severance Agreement(Two-Year Term;Non-Pension)Exhibit 10.3 toForm 8-K dated July 25, 2018 (SEC FileNo. 1-8858) 10.5Amended and Restated Employment Agreement between Unitil Corporation and Thomas P. Meissner, Jr.Exhibit 10.4 to Form 8-K dated July 25, 2018(SEC File No. 1-8858) 10.6Amended and Restated Supplemental Executive Retirement PlanExhibit 10.5 to Form 8-K dated July 25, 2018(SEC File No. 1-8858) 10.7Unitil Corporation Deferred Compensation PlanExhibit 10.6 to Form 8-K dated July 25, 2018(SEC File No. 1-8858) 11 31.1 31.2 31.3 32.1 99.1 101.INS XBRL Instance Document. Filed herewith101.SCH 101.CAL 101.DEF 101.LAB 101.PRE *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. 25, 201824, 2019 Mark H. CollinChristine L. Vaughan Mark H. Collin 25, 201824, 2019 60 $ $ $ $ $ $ $ $