Form 10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT UNDER SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For Quarter Ended
September 30, 2018
Commission File Number 1-8858
UNITIL CORPORATION
(Exact name of registrant as specified in its charter)
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| New Hampshire |
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02-0381573 |
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incorporation or organization) |
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(I.R.S. Employer Identification No.) |
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| 6 Liberty Lane West, Hampton, New Hampshire |
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03842-1720 |
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Registrant’s telephone number, including area code: (603)
772-0775
Indicate by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes ☒ No ☐
Indicate by check mark
whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the
definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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| Large accelerated filer |
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Accelerated filer |
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| Non-accelerated filer |
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Smaller reporting company |
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Emerging growth company |
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition
period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes ☐ No ☒
Indicate the number of
shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
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Outstanding at October 22,
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| Common Stock, No par value |
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14,872,955 Shares |
UNITIL CORPORATION AND SUBSIDIARY COMPANIES
FORM 10-Q
For the Quarter Ended September 30, 2018
Table of
Contents
CAUTIONARY STATEMENT
This report and the documents incorporated by reference into this report contain statements that constitute “forward-looking statements” within the meaning of Section 27A of the Securities
Act of 1933, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, included or incorporated by reference into this
report, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for the Company’s future operations, are forward-looking statements.
These statements include declarations regarding the Company’s beliefs and current expectations. In some cases, forward-looking statements can be
identified by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or
“continue,” or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to
differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in Item 1A (Risk Factors) and the following:
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the Company’s regulatory environment (including regulations relating to climate change, greenhouse gas emissions and other environmental matters),
which could affect the rates the Company is able to charge, the Company’s authorized rate of return and the Company’s ability to recover costs in its rates; |
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fluctuations in the supply of, demand for, and the prices of energy commodities and transmission capacity and the Company’s ability to recover
energy commodity costs in its rates; |
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customers’ preferred energy sources; |
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severe storms and the Company’s ability to recover storm costs in its rates; |
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the Company’s stranded electric generation and generation-related supply costs and the Company’s ability to recover stranded costs in its
rates; |
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declines in the valuation of capital markets, which could require the Company to make substantial cash contributions to cover its pension obligations,
and the Company’s ability to recover pension obligation costs in its rates; |
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general economic conditions, which could adversely affect (i) the Company’s customers and, consequently, the demand for the Company’s
distribution services, (ii) the availability of credit and liquidity resources and (iii) certain of the Company’s counterparties’ obligations (including those of its insurers and lenders); |
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the Company’s ability to obtain debt or equity financing on acceptable terms; |
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increases in interest rates, which could increase the Company’s interest expense; |
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restrictive covenants contained in the terms of the Company’s and its subsidiaries’ indebtedness, which restrict certain aspects of the
Company’s business operations; |
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variations in weather, which could decrease demand for the Company’s distribution services; |
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long-term global climate change, which could adversely affect customer demand or cause extreme weather events that could disrupt the Company’s
electric and natural gas distribution services; |
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numerous hazards and operating risks relating to the Company’s electric and natural gas distribution activities, which could result in accidents
and other operating risks and costs; |
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the Company’s ability to retain its existing customers and attract new customers; |
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the Company’s energy brokering customers’ performance under multi-year energy brokering contracts; and |
Many of these risks are beyond the Company’s control. Any forward-looking statements speak only as of the date of this report, and the Company
undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it
is not possible for the Company to predict all of these factors, nor can the Company assess the impact of any such factor on its business or the extent to which any factor, or combination of factors, may cause results to differ materially from those
contained in any forward-looking statements.
PART I. FINANCIAL INFORMATION
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
Unitil Corporation (Unitil or the Company) is a public utility holding company
headquartered in Hampton, New Hampshire. Unitil is subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005.
Unitil’s principal business is the local distribution of electricity and natural gas throughout its service areas in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company
of three wholly-owned distribution utilities:
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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; |
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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 |
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Northern Utilities, Inc. (Northern Utilities), which provides natural gas service in southeastern New Hampshire and portions of southern and
central Maine, including the city of Portland, which is the largest city in northern New England. |
Unitil Energy, Fitchburg
and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 105,000 electric customers and 81,300 natural gas customers in their service territory.
In addition, Unitil is the parent company of Granite State Gas Transmission, Inc. (Granite State) an interstate natural gas transmission
pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to major natural gas pipelines and access to domestic natural
gas supplies in the south and Canadian natural gas supplies in the north.
Unitil had an investment in Net Utility Plant of
$1,022.3 million at September 30, 2018. Unitil’s total operating revenue includes revenue to recover the approved cost of purchased electricity and natural gas in rates on a fully reconciling basis. As a result of this reconciling
rate structure, the Company’s earnings are not directly affected by changes in the cost of purchased electricity and natural gas. Earnings from Unitil’s utility operations are primarily derived from the return on investment in the utility
assets of the three distribution utilities and Granite State.
Unitil also conducts non-regulated
operations principally through Usource Inc. and Usource L.L.C. (collectively, Usource), which is wholly-owned by Unitil Resources Inc., a wholly-owned subsidiary of Unitil. Usource provides energy brokering and advisory services to large commercial
and industrial
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customers primarily in the northeastern United States. The Company’s other subsidiaries include Unitil Service Corp., which provides, at cost, a variety of administrative and professional
services to Unitil’s affiliated companies, Unitil Realty Corp. (Unitil Realty), which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire and Unitil Power Corp., which formerly functioned as
the full requirements wholesale power supply provider for Unitil Energy. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.
RATES AND REGULATION
Regulation
Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a
holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities are
also regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil
Energy is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the Massachusetts Department of Public Utilities (MDPU); and Northern Utilities is regulated by the NHPUC and the Maine
Public Utilities Commission (MPUC). Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate
regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.
Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under cost
of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, and earn a return on their capital investment in
utility assets. In addition, the Company’s distribution utilities and its natural gas transmission pipeline company may also recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management
programs, through annual step adjustments and cost tracker rate mechanisms.
Fitchburg is subject to revenue decoupling. Revenue decoupling is
the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue
decoupling amounts is recognized as an increase or a decrease in Accrued Revenue which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of
rate cases and other authorized adjustments that the Company files with the MDPU. The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.
Tax Cuts and Jobs Act of 2017
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law. Among other things, the TCJA substantially reduced the corporate
income tax rate to 21 percent, effective January 1, 2018. Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, has issued procedural orders directing
how the tax law changes are to be reflected in rates, including requiring that the companies provide certain filings and calculations. 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). The Company believes that these matters are substantially resolved and will not
have a material impact on its financial position, operating results, or cash flows.
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In Maine, Northern Utilities’ Maine division recently completed a base 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 among 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 pursuant to the provisions of its last 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 on 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 Activity
Unitil 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 2019 to recover the revenue requirements associated with annual capital
expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s second step adjustment filing. The filing incorporated the revenue requirement of $3.3 million 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 the one-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 decrease of $0.3 million.
Fitchburg – Base Rates
– Electric – Fitchburg’s last base rate order from the MDPU, issued in April 2016, included the approval of an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions.
While a number of the capital cost recovery filings may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory
proceedings and there are no material issues outstanding. On June 28, 2018, Fitchburg filed its compliance report of capital investments for calendar year 2017. This matter remains pending.
Fitchburg – Electric Grid Modernization – On May 10, 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 address pre-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.
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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, subject to further investigation and reconciliation. A final order is pending.
Fitchburg – Base Rates – Gas – Pursuant to the Company’s revenue decoupling adjustment clause tariff, as approved
in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather and energy efficiency impacts to the
Company’s revenues. The MDPU has consistently found that the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that they result in just and reasonable rates.
Fitchburg – Gas System Enhancement Program – Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan
(GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking
filing for the subsequent construction year, to be filed on or before October 31; 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 from
year-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. Under this tariff, a
revenue increase of $0.9 million went into effect on May 1, 2018, subject to 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 annual 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 Area Build-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 Area Build-out Program – Maine – In December
2015, the MPUC approved a TAB program and associated rate surcharge mechanism. 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 was
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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 Epping remains pending.
Granite State – Base Rates – On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which provided for no
change in rates, and accounted for the effects of a capital step adjustment offset by the effect of the TCJA. The settlement was approved by FERC on June 27, 2018, and complies with the FERC Notice of Proposed Rulemaking concerning the justness
and reasonableness of rates in light of the corporate income tax reductions under the TCJA. The settlement also provides that Granite State may not file a general (Section 4) rate case prior to April 30, 2019.
RESULTS OF OPERATIONS
The following
section of MD&A compares the results of operations for each of the two fiscal periods ended September 30, 2018 and September 30, 2017 and should be read in conjunction with the accompanying unaudited Consolidated Financial Statements
and the accompanying Notes to unaudited Consolidated Financial Statements included in Part I, Item 1 of this report, which are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).
The Company’s results of operations reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during
the heating season as a result of higher sales of natural gas due to cold weather. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a
significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by the weather conditions in both the winter and summer seasons. Also, as a result of
recent rate cases, the Company’s natural gas sales margins are derived from a higher percentage of fixed billing components, including customer charges. Therefore, natural gas revenues and margin will be less affected by the seasonal nature of
the natural gas business. In addition, as discussed above, approximately 27% and 11% of the Company’s total annual electric and natural gas sales volumes, respectively, are decoupled and changes in sales to existing customers do not affect
sales margin.
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Earnings Overview
The Company’s Net Income was $2.8 million, or $0.19 per share, for the third quarter of 2018, an increase of $0.5 million, or $0.03 per share, compared to the third quarter of 2017. For the
nine months ended September 30, 2018, the Company reported Net Income of $22.0 million, or $1.49 per share, an increase of $4.2 million, or $0.22 per share, compared to the same nine month period in 2017. The increases in earnings in
2018 were driven by higher sales margins, reflecting: customer growth, favorable impacts of weather on unit sales and new distribution rates. Also, earnings per share reflect a higher number of shares outstanding due to the issuance of 690,000
common shares on December 14, 2017, discussed below in Note 5 to the Consolidated Financial Statements.
Natural gas sales margins were
$17.6 million and $80.4 million in the three and nine months ended September 30, 2018, respectively, increases of $0.8 million and $5.1 million, respectively, compared to the same periods in 2017. Gas sales margin in the
first nine months of 2018 was positively affected by higher natural gas distribution revenues of $5.9 million, partially offset by 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 award in the Company’s New Hampshire gas utility, the Company recognized concurrent non-recurring adjustments to increase both Gas Operating
Revenues and Operation and Maintenance (O&M) expenses by $1.2 million in the second quarter of 2018 to reconcile permanent rates and deferred costs to 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.
Natural
gas therm sales decreased 2.9% and increased 5.5% in the three and nine month periods ended September 30, 2018, respectively, compared to the same periods in 2017. 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 Heating Degree Days (HDD) in the first nine months of 2018
compared to the same period in 2017. As of September 30, 2018, the number of total natural gas customers served has increased by approximately 1,200 over the last year.
Electric sales margins were $25.9 million and $70.5 million in the three and nine months ended September 30, 2018, respectively, increases of $1.1 million and $0.4 million,
respectively, compared to the same periods in 2017. Electric sales margin in the first nine months of 2018 was positively affected by higher electric distribution revenues of $2.5 million, 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 a one-year $1.4 million temporary rate reconciliation adjustment
recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.
Total electric kilowatt-hour (kWh) sales
increased 3.4% and 4.2%, respectively, in the three and nine month periods ended September 30, 2018 compared to the same periods in 2017. The increase 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. Based on weather data collected in the Company’s electric service areas, there were 48.7% more Cooling Degree Days (CDD) in the third quarter of 2018 compared to the same
period in 2017. As of September 30, 2018, the number of total electric customers served has increased by approximately 575 over the last year.
O&M expenses decreased $0.5 million and increased $2.1 million for the three and nine months ended September 30, 2018, 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 include a non-recurring temporary rate adjustment to increase O&M expenses by $1.2 million in the second quarter of 2018, which was offset by a corresponding increase in gas revenue.
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Depreciation and Amortization expense increased $1.6 million and $2.2 million in the three and
nine months ended September 30, 2018, respectively, compared to the same periods in 2017. These increases reflect higher 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.
Taxes Other Than Income Taxes increased
$0.6 million and $0.9 million in the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017, primarily reflecting higher local property tax rates on higher levels of utility plant assets in
service and higher payroll taxes.
Interest Expense, net increased $0.2 million and $0.8 million in the three and nine months ended
September 30, 2018, respectively, compared to the same periods in 2017. These increases primarily reflect interest on higher levels of long-term debt.
At its January 2018, April 2018, July 2018 and October 2018 meetings, Unitil’s Board of Directors declared quarterly dividends on the Company’s common stock of $0.365 per share. These quarterly
dividends result in a current effective annualized dividend rate of $1.46 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.
A more detailed discussion of the Company’s results of operations for the three and nine months ended September 30, 2018 is presented below.
Gas Sales, Revenues and Margin
Therm Sales – Unitil’s total therm sales of natural gas decreased 2.9% and increased 5.5% in the three and nine month periods ended September 30, 2018, respectively, compared
to the same periods in 2017. In the third quarter of 2018, sales to Residential and C&I customers decreased 10.7% and 2.0%, respectively, compared to the same period in 2017, reflecting warmer late summer and early fall weather in 2018,
partially offset by customer growth. For the nine months ended September 30, 2018, sales to Residential and C&I customers increased 7.2% and 5.0%, respectively, compared to the same period in 2017. 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. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 2.0% in the first nine months of 2018 compared to the same period in 2017. As of
September 30, 2018, the number of total natural gas customers served has increased by approximately 1,200 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.
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The following table details total firm therm sales for the three and nine months ended September 30,
2018 and 2017, by major customer class:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Therm Sales (millions) |
|
| |
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
| |
|
2018 |
|
|
2017 |
|
|
Change |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
Change |
|
|
% Change |
|
| Residential |
|
|
2.5 |
|
|
|
2.8 |
|
|
|
(0.3 |
) |
|
|
(10.7 |
%) |
|
|
35.9 |
|
|
|
33.5 |
|
|
|
2.4 |
|
|
|
7.2 |
% |
| Commercial / Industrial |
|
|
23.9 |
|
|
|
24.4 |
|
|
|
(0.5 |
) |
|
|
(2.0 |
%) |
|
|
132.3 |
|
|
|
126.0 |
|
|
|
6.3 |
|
|
|
5.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
26.4 |
|
|
|
27.2 |
|
|
|
(0.8 |
) |
|
|
(2.9 |
%) |
|
|
168.2 |
|
|
|
159.5 |
|
|
|
8.7 |
|
|
|
5.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and
Sales Margin for the three and nine months ended September 30, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Gas Operating Revenues and Sales Margin (millions) |
|
| |
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
| |
|
2018 |
|
|
2017 |
|
|
$ Change |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
$ Change |
|
|
% Change |
|
| Gas Operating Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Residential |
|
$ |
9.2 |
|
|
$ |
9.1 |
|
|
$ |
0.1 |
|
|
|
1.1 |
% |
|
$ |
58.9 |
|
|
$ |
53.4 |
|
|
$ |
5.5 |
|
|
|
10.3 |
% |
| Commercial / Industrial |
|
|
16.5 |
|
|
|
16.0 |
|
|
|
0.5 |
|
|
|
3.1 |
% |
|
|
88.5 |
|
|
|
78.5 |
|
|
|
10.0 |
|
|
|
12.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Gas Operating Revenue |
|
$ |
25.7 |
|
|
$ |
25.1 |
|
|
$ |
0.6 |
|
|
|
2.4 |
% |
|
$ |
147.4 |
|
|
$ |
131.9 |
|
|
$ |
15.5 |
|
|
|
11.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cost of Gas Sales |
|
$ |
8.1 |
|
|
$ |
8.3 |
|
|
$ |
(0.2 |
) |
|
|
(2.4 |
%) |
|
$ |
67.0 |
|
|
$ |
56.6 |
|
|
$ |
10.4 |
|
|
|
18.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Gas Sales Margin |
|
$ |
17.6 |
|
|
$ |
16.8 |
|
|
$ |
0.8 |
|
|
|
4.8 |
% |
|
$ |
80.4 |
|
|
$ |
75.3 |
|
|
$ |
5.1 |
|
|
|
6.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company analyzes operating results using Gas Sales Margin, a non-GAAP
measure. Gas Sales Margin is calculated as Total Gas Operating Revenue less Cost of Gas Sales. The Company believes Gas Sales Margin is an important measure to analyze profitability because the approved cost of sales are tracked and reconciled costs
that are passed through directly to the customer, resulting in an equal and offsetting amount reflected in Total Gas Operating Revenue. Sales margin can be reconciled to Operating Income, a GAAP measure, by including Operation and Maintenance,
Depreciation and Amortization and Taxes Other Than Income Taxes for each segment in the analysis.
Natural gas sales margins were
$17.6 million and $80.4 million in the three and nine months ended September 30, 2018, respectively, increases of $0.8 million and $5.1 million, respectively, compared to the same periods in 2017. Gas sales margin in the
third quarter of 2018 was positively affected by higher natural gas distribution revenues of $1.1 million, partially offset by lower revenue of $0.4 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. Gas sales margin in the third quarter of 2018 also reflects the effect of customer growth on sales volume of
$0.1 million.
Gas sales margin in the first nine months of 2018 was positively affected by higher natural gas distribution revenues of
$5.9 million, 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 award in the Company’s New
Hampshire gas utility, the Company recognized concurrent non-recurring adjustments to increase both Gas Operating Revenues and O&M expenses by $1.2 million in the second quarter of 2018 to reconcile
permanent rates and deferred costs to 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.
11
The increase in Total Gas Operating Revenues of $0.6 million in the three months ended
September 30, 2018 compared to the same period 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, and lower cost
of gas sales, which are tracked and reconciled costs as a pass-through to customers. The increase in Total Gas Operating Revenues of $15.5 million in the nine months ended September 30, 2018 compared to the same period in 2017 reflects
higher natural gas distribution rates, customer growth, 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.
Electric Sales, Revenues and Margin
Kilowatt-hour Sales – Unitil’s total electric kWh sales increased 3.4% and 4.2%, respectively, in the three and nine month periods ended September 30, 2018 compared to the
same periods in 2017. In the third quarter of 2018, sales to Residential and C&I customers increased 9.2% and decreased 0.4%, respectively, compared to the same period in 2017, reflecting warmer-than-average summer temperatures in 2018 and
customer growth. For the nine months ended September 30, 2018, sales to Residential and C&I customers increased 6.3% and 2.7%, respectively, compared to the same period in 2017, reflecting customer growth, the favorable impacts of weather
on unit sales and higher usage by industrial customers for production purposes. Based on weather data collected in the Company’s electric service areas, there were 48.7% more CDD in the third quarter of 2018 compared to the same period in 2017
and 9.0% more HDD in the first nine months of 2018 compared to the same period in 2017. As of September 30, 2018, the number of total electric customers served has increased by approximately 575 over the last year. As previously discussed,
sales margins derived from decoupled unit sales (representing approximately 27% of total annual kWh sales volume) are not sensitive to changes in electric kWh sales.
The following table details total kWh sales for the three and nine months ended September 30, 2018 and 2017 by major customer class:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| kWh Sales (millions) |
|
| |
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
| |
|
2018 |
|
|
2017 |
|
|
Change |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
Change |
|
|
% Change |
|
| Residential |
|
|
195.0 |
|
|
|
178.5 |
|
|
|
16.5 |
|
|
|
9.2 |
% |
|
|
527.8 |
|
|
|
496.4 |
|
|
|
31.4 |
|
|
|
6.3 |
% |
| Commercial / Industrial |
|
|
268.3 |
|
|
|
269.5 |
|
|
|
(1.2 |
) |
|
|
(0.4 |
%) |
|
|
755.9 |
|
|
|
735.9 |
|
|
|
20.0 |
|
|
|
2.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
463.3 |
|
|
|
448.0 |
|
|
|
15.3 |
|
|
|
3.4 |
% |
|
|
1,283.7 |
|
|
|
1,232.3 |
|
|
|
51.4 |
|
|
|
4.2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
Electric Operating Revenues and Sales Margin – The following table details total Electric
Operating Revenues and Sales Margin for the three and nine month periods ended September 30, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Electric Operating Revenues and Sales Margin
(millions) |
|
| |
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
| |
|
2018 |
|
|
2017 |
|
|
$ Change |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
$ Change |
|
|
% Change |
|
| Electric Operating Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Residential |
|
$ |
35.5 |
|
|
$ |
32.2 |
|
|
$ |
3.3 |
|
|
|
10.2 |
% |
|
$ |
95.7 |
|
|
$ |
86.9 |
|
|
$ |
8.8 |
|
|
|
10.1 |
% |
| Commercial / Industrial |
|
|
25.9 |
|
|
|
25.3 |
|
|
|
0.6 |
|
|
|
2.4 |
% |
|
|
71.9 |
|
|
|
67.5 |
|
|
|
4.4 |
|
|
|
6.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Electric Operating Revenue |
|
$ |
61.4 |
|
|
$ |
57.5 |
|
|
$ |
3.9 |
|
|
|
6.8 |
% |
|
$ |
167.6 |
|
|
$ |
154.4 |
|
|
$ |
13.2 |
|
|
|
8.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cost of Electric Sales |
|
$ |
35.5 |
|
|
$ |
32.7 |
|
|
$ |
2.8 |
|
|
|
8.6 |
% |
|
$ |
97.1 |
|
|
$ |
84.3 |
|
|
$ |
12.8 |
|
|
|
15.2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Electric Sales Margin |
|
$ |
25.9 |
|
|
$ |
24.8 |
|
|
$ |
1.1 |
|
|
|
4.4 |
% |
|
$ |
70.5 |
|
|
$ |
70.1 |
|
|
$ |
0.4 |
|
|
|
0.6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company analyzes operating results using Electric Sales Margin, a non-GAAP
measure. Electric Sales Margin is calculated as Total Electric Operating Revenues less Cost of Electric Sales. The Company believes Electric Sales Margin is an important measure to analyze profitability because the approved cost of sales are tracked
and reconciled costs that are passed through directly to the customer resulting in an equal and offsetting amount reflected in Total Electric Operating Revenues. Sales margin can be reconciled to Operating Income, a GAAP measure, by including
Operation and Maintenance, Depreciation and Amortization and Taxes Other Than Income Taxes for each segment in the analysis.
Electric sales
margins were $25.9 million and $70.5 million in the three and nine months ended September 30, 2018, respectively, increases of $1.1 million and $0.4 million, respectively, compared to the same periods in 2017. Electric sales
margin in the third quarter was positively affected by higher electric distribution revenues of $0.8 million, partially offset by lower revenue of $0.6 million in 2018 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. 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, 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 a one-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-through to customers, partially offset by lower revenue related to the TCJA, discussed above.
The increase in Total Electric Operating Revenues of $13.2 million in the first nine months of 2018 reflects higher electric distribution rates and higher cost of electric sales, which are tracked
and reconciled to costs as a pass-through to customers, partially offset by a non-recurring adjustment in the second quarter of 2017 to increase revenue by $1.4 million related to the completion of a base
rate case and lower revenue related to the TCJA, discussed above.
13
Operating Revenue – Other
The following table details total Other Revenue for the three and nine months ended September 30, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other Revenue (000’s) |
|
| |
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
| |
|
2018 |
|
|
2017 |
|
|
$ Change |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
$ Change |
|
|
% Change |
|
| Other |
|
$ |
1.1 |
|
|
$ |
1.4 |
|
|
$ |
(0.3 |
) |
|
|
(21.4 |
%) |
|
$ |
3.5 |
|
|
$ |
4.5 |
|
|
$ |
(1.0 |
) |
|
|
(22.2 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Other Revenue |
|
$ |
1.1 |
|
|
$ |
1.4 |
|
|
$ |
(0.3 |
) |
|
|
(21.4 |
%) |
|
$ |
3.5 |
|
|
$ |
4.5 |
|
|
$ |
(1.0 |
) |
|
|
(22.2 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Operating Revenue (See “Other Operating Revenue –
Non-regulated” in Note 1 to the accompanying Consolidated Financial Statements) is comprised of revenues from the Company’s non-regulated energy brokering
business, 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 revenues 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 ASU 2015-14, ASU 2016-08, ASU 2016-10 and ASU 2017-13, on a modified retrospective basis, which requires application to contracts with customers
effective January 1, 2018. ASU 2014-09 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 ASU 2014-09, 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 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 ASU 2014-09 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.
Operating Expenses
Cost of Gas Sales – Cost of Gas Sales includes the cost of natural gas purchased and manufactured to supply the
Company’s total gas supply requirements and spending on energy efficiency programs. Cost of Gas Sales decreased $0.2 million, or 2.4%, and increased $10.4 million, or 18.4%, in the three and nine months ended September 30, 2018,
respectively, compared to the same periods in 2017. The decrease in the three month period primarily reflects lower sales of natural gas and 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. 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.
14
Cost of Electric Sales – Cost of Electric Sales includes the cost of electric supply as
well as other energy supply related restructuring costs, including power supply buyout costs, and spending on energy efficiency programs. Cost of Electric Sales increased $2.8 million, or 8.6% and $12.8 million, or 15.2% in the three and
nine months ended September 30, 2018 compared to the same periods in 2017. The increase in the three month period reflects higher electric sales 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. 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.
O&M expense includes gas and electric utility operating costs, and the operating costs of the Company’s corporate and other business activities. Total O&M expenses decreased $0.5 million
and increased $2.1 million for the three and nine months ended September 30, 2018, 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 include a non-recurring temporary rate adjustment to increase O&M
expenses by $1.2 million in the second quarter of 2018, which was offset by a corresponding increase in gas revenue.
Depreciation
and Amortization – Depreciation and Amortization expense increased $1.6 million, or 14.8%, and $2.2 million, or 6.3%, in the three and nine months ended September 30, 2018, respectively, compared to the same periods in
2017. These increases reflect higher 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.
Taxes Other Than Income Taxes – Taxes Other Than Income Taxes 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, compared to the same periods in 2017, primarily reflecting higher local property tax rates on higher levels of utility plant assets in service and
higher payroll taxes.
Other Expense, net – Other Expense, net increased $0.2 million, or 22.2%, and
$0.4 million, or 10.8%, in the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017. In the first quarter of 2018, the Company adopted ASU
No. 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 Form 10-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
15
Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. There are $1.2 million and $0.8 million of
non-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 of non-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.
Income Taxes – Federal and State Income Taxes decreased by $1.0 million and $6.1 million for the three and nine months ended September 30, 2018, respectively, compared to
the same periods in 2017. The decrease in the three month period reflects the lower tax rate on pre-tax earnings from the TCJA in 2018. The decrease in the nine month period reflects $5.0 million from the
lower tax rate on pre-tax earnings in 2018 and the current tax benefit of $1.1 million of book/tax temporary differences turning at the lower income tax rate from the TCJA in 2018.
Interest Expense, net – Interest expense is presented in the Consolidated Financial Statements net of interest income. Interest
expense is mainly comprised of interest on long-term debt and short-term borrowings. In addition, certain reconciling rate mechanisms used by the Company’s distribution operating utilities give rise to regulatory assets and regulatory
liabilities on which interest is calculated.
Unitil’s utility subsidiaries operate a number of reconciling rate 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Interest Expense, net (Millions) |
|
Three Months Ended
September 30, |
|
|
Nine Months Ended
September 30, |
|
| |
|
2018 |
|
|
2017 |
|
|
Change |
|
|
2018 |
|
|
2017 |
|
|
Change |
|
| Interest Expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Long-term Debt |
|
$ |
5.7 |
|
|
$ |
5.3 |
|
|
$ |
0.4 |
|
|
$ |
17.3 |
|
|
$ |
15.9 |
|
|
$ |
1.4 |
|
| Short-term Debt |
|
|
0.7 |
|
|
|
0.8 |
|
|
|
(0.1 |
) |
|
|
1.6 |
|
|
|
1.9 |
|
|
|
(0.3 |
) |
| Regulatory Liabilities |
|
|
0.2 |
|
|
|
0.3 |
|
|
|
(0.1 |
) |
|
|
0.5 |
|
|
|
0.8 |
|
|
|
(0.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Subtotal Interest Expense |
|
|
6.6 |
|
|
|
6.4 |
|
|
|
0.2 |
|
|
|
19.4 |
|
|
|
18.6 |
|
|
|
0.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Interest (Income) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Regulatory Assets |
|
|
(0.2 |
) |
|
|
(0.2 |
) |
|
|
— |
|
|
|
(0.6 |
) |
|
|
(0.5 |
) |
|
|
(0.1 |
) |
|
AFUDC(1)
and Other |
|
|
(0.4 |
) |
|
|
(0.4 |
) |
|
|
— |
|
|
|
(0.9 |
) |
|
|
(1.0 |
) |
|
|
0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Subtotal Interest (Income) |
|
|
(0.6 |
) |
|
|
(0.6 |
) |
|
|
— |
|
|
|
(1.5 |
) |
|
|
(1.5 |
) |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Interest Expense, net |
|
$ |
6.0 |
|
|
$ |
5.8 |
|
|
$ |
0.2 |
|
|
$ |
17.9 |
|
|
$ |
17.1 |
|
|
$ |
0.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (1) |
AFUDC – Allowance for Funds Used During Construction. |
Interest Expense, net increased $0.2 million and $0.8 million in the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017. These increases
primarily reflect interest on higher levels of long-term debt.
16
CAPITAL REQUIREMENTS
Sources of Capital
Unitil requires capital to fund utility plant additions, working
capital and other utility expenditures recovered in subsequent periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating
activities. The Company initially supplements internally-generated funds through short-term bank borrowings, as needed, under its unsecured revolving Credit Facility. Periodically, the Company replaces portions of its short-term debt with long-term
financings more closely matched to the long-term nature of its utility assets. Additionally, from time to time, the Company has accessed the public capital markets through public offerings of equity securities. The Company’s utility operations
are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The amount, type and timing of any future financing will vary from year to year based on capital needs and maturity or redemptions of securities.
The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (the “Cash Pool”). The Cash Pool is the
financing vehicle for day-to-day cash borrowing and investing. The Cash Pool allows for an efficient exchange of cash among the Company and its subsidiaries. The
interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on actual interest costs from lenders under the Company’s revolving Credit Facility (as defined below). At September 30, 2018, September 30, 2017
and December 31, 2017, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.
On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement and related documents (collectively, the “Credit Facility”) with a syndicate of lenders, which
amended and restated in its entirety the Company’s prior credit facility. The Credit Facility extends to July 25, 2023, subject to two one-year extensions under certain circumstances, and has a
borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company with the ability to elect that borrowings under the Credit Facility bear
interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.125%. The Company may increase the borrowing limit under the
Credit Facility by up to $50 million under certain circumstances.
The Company utilizes the Credit Facility for cash management purposes
related to its short-term operating activities. Total gross borrowings were $202.5 million for the nine months ended September 30, 2018. Total gross repayments were $171.7 million for the nine months ended September 30, 2018. The
following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30, 2018, September 30, 2017 and December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Credit Facility ($ millions) |
|
| |
|
September 30, |
|
|
December 31, |
|
| |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Limit |
|
$ |
120.0 |
|
|
$ |
120.0 |
|
|
$ |
120.0 |
|
| Short-Term Borrowings Outstanding |
|
|
69.1 |
|
|
|
111.9 |
|
|
|
38.3 |
|
| Letters of Credit Outstanding |
|
|
— |
|
|
|
1.1 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Available |
|
$ |
50.9 |
|
|
$ |
7.0 |
|
|
$ |
81.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
The Credit Facility contains customary terms and conditions for credit facilities of this type, including
affirmative and negative covenants. There are restrictions on, among other things, the Company’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on the Company’s ability to merge or consolidate
with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with
respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly
basis. At September 30, 2018, September 30, 2017 and December 31, 2017, 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.)
On November 1, 2017, Northern Utilities issued $20 million of Notes due 2027 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%. Northern Utilities, Fitchburg and Granite State used the net
proceeds from these offerings to refinance higher cost long-term debt that matured in 2017, to repay short-term debt and for general corporate purposes. Approximately $0.7 million of costs associated with these issuances have been netted
against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.
In April 2014, Unitil Service Corp. entered into a
financing arrangement, structured as a capital lease obligation, for various information systems and technology equipment. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million.
The capital lease matures on September 30, 2020. As 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.
Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated
“BBB+” by Standard & Poor’s Ratings Services. Unitil Corporation and Granite State are currently rated “Baa2”, and Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1” by Moody’s
Investors Services.
The continued availability of various methods of financing, as well as the choice of a specific form of security for such
financing, will depend on many factors, including, but not limited to: security market conditions; general economic climate; regulatory approvals; the ability to meet covenant issuance restrictions; the level of earnings, cash flows and financial
position; and the competitive pricing offered by financing sources.
The Company provides limited guarantees on certain energy and natural gas
storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of September 30, 2018, there were approximately $5.6 million of guarantees outstanding.
Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage
assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager.
There was $9.6 million, $9.0 million and $8.5 million of natural gas storage inventory at September 30, 2018, September 30, 2017 and December 31, 2017, respectively, related to these asset management agreements. The
amount of natural gas inventory released in September 2018 and payable in October 2018 is $0.1 million and is 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 2017 and payable in January 2018 was $3.1 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.
18
Off-Balance Sheet Arrangements
The Company and its subsidiaries do not currently use, and are not dependent on the use of, off-balance sheet
financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. Unitil Corporation’s subsidiaries conduct a portion of their operations in leased
facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. Additionally, as of September 30, 2018, there were approximately $5.6 million of guarantees on certain
energy and natural gas storage management contracts entered into by the distribution utilities outstanding. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.
CRITICAL ACCOUNTING POLICIES
The
preparation of the Company’s financial statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, the Company is
sometimes required to make difficult, subjective and/or complex judgments about the impact of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in
its financial statements. If actual results were to differ significantly from those estimates, assumptions and judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be
materially different than reported. For a complete discussion of the Company’s significant accounting policies, refer to the Note 1 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 1, 2018.
LABOR RELATIONS
As of September 30, 2018, the Company and its subsidiaries had 513 employees. The Company considers its relationship with employees
to be good and has not experienced any major labor disruptions.
As of September 30, 2018, a total of 165 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:
|
|
|
|
|
|
|
|
|
| |
|
Employees Covered |
|
|
CBA Expiration |
|
| Fitchburg |
|
|
47 |
|
|
|
05/31/2019 |
|
| Northern Utilities NH Division |
|
|
34 |
|
|
|
06/05/2020 |
|
| Northern Utilities ME Division |
|
|
39 |
|
|
|
03/31/2021 |
|
| Granite State |
|
|
3 |
|
|
|
03/31/2021 |
|
| Unitil Energy |
|
|
37 |
|
|
|
05/31/2023 |
|
| Unitil Service |
|
|
5 |
|
|
|
05/31/2023 |
|
The CBAs provide discrete salary adjustments, established work practices and uniform benefit packages. The Company
expects to negotiate new agreements prior to their expiration dates.
19
INTEREST RATE RISK
As discussed above, the Company 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, 2018 and
September 30, 2018 were 3.3% and 2.5%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 2018 and September 30, 2017 were 3.2% and 2.3%, respectively. The
average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2017 was 2.4%.
COMMODITY
PRICE RISK
Although Unitil Corporation’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
Please refer to Note 6 to the Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Regulatory Matters.
ENVIRONMENTAL MATTERS
Please refer to Note 7 to the Consolidated Financial Statements
in Part I, Item 1 of this report for a discussion of Environmental Matters.
20
UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF EARNINGS
(Millions except per share data)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months
Ended
September 30, |
|
|
Nine Months
Ended
September 30, |
|
| |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
| Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Gas |
|
$ |
25.7 |
|
|
$ |
25.1 |
|
|
$ |
147.4 |
|
|
$ |
131.9 |
|
| Electric |
|
|
61.4 |
|
|
|
57.5 |
|
|
|
167.6 |
|
|
|
154.4 |
|
| Other |
|
|
1.1 |
|
|
|
1.4 |
|
|
|
3.5 |
|
|
|
4.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Operating Revenues |
|
|
88.2 |
|
|
|
84.0 |
|
|
|
318.5 |
|
|
|
290.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cost of Gas Sales |
|
|
8.1 |
|
|
|
8.3 |
|
|
|
67.0 |
|
|
|
56.6 |
|
| Cost of Electric Sales |
|
|
35.5 |
|
|
|
32.7 |
|
|
|
97.1 |
|
|
|
84.3 |
|
| Operation and Maintenance |
|
|
16.4 |
|
|
|
16.9 |
|
|
|
51.5 |
|
|
|
49.4 |
|
| Depreciation and Amortization |
|
|
12.4 |
|
|
|
10.8 |
|
|
|
37.4 |
|
|
|
35.2 |
|
| Taxes Other Than Income Taxes |
|
|
5.5 |
|
|
|
4.9 |
|
|
|
16.5 |
|
|
|
15.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Operating Expenses |
|
|
77.9 |
|
|
|
73.6 |
|
|
|
269.5 |
|
|
|
241.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Operating Income |
|
|
10.3 |
|
|
|
10.4 |
|
|
|
49.0 |
|
|
|
49.7 |
|
| Interest Expense, net |
|
|
6.0 |
|
|
|
5.8 |
|
|
|
17.9 |
|
|
|
17.1 |
|
| Other Expense, net |
|
|
1.1 |
|
|
|
0.9 |
|
|
|
4.1 |
|
|
|
3.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Income Before Income Taxes |
|
|
3.2 |
|
|
|
3.7 |
|
|
|
27.0 |
|
|
|
28.9 |
|
| Income Tax Expense |
|
|
0.4 |
|
|
|
1.4 |
|
|
|
5.0 |
|
|
|
11.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net Income |
|
$ |
2.8 |
|
|
$ |
2.3 |
|
|
$ |
22.0 |
|
|
$ |
17.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net Income Per Common Share |
|
$ |
0.19 |
|
|
$ |
0.16 |
|
|
$ |
1.49 |
|
|
$ |
1.27 |
|
| Weighted Average Common Shares Outstanding |
|
|
14.8 |
|
|
|
14.1 |
|
|
|
14.8 |
|
|
|
14.1 |
|
| Dividends Declared Per Share of Common Stock |
|
$ |
0.365 |
|
|
$ |
0.36 |
|
|
$ |
1.095 |
|
|
$ |
1.08 |
|
(The
accompanying notes are an integral part of these consolidated unaudited financial statements.)
21
UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Millions)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
September 30, |
|
|
December 31, |
|
| |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| ASSETS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Current Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
| Cash and Cash Equivalents |
|
$ |
6.3 |
|
|
$ |
10.9 |
|
|
$ |
8.9 |
|
| Accounts Receivable, net |
|
|
52.3 |
|
|
|
45.8 |
|
|
|
67.4 |
|
| Accrued Revenue |
|
|
36.0 |
|
|
|
39.2 |
|
|
|
53.3 |
|
| Exchange Gas Receivable |
|
|
10.1 |
|
|
|
9.5 |
|
|
|
5.8 |
|
| Materials and Supplies |
|
|
7.2 |
|
|
|
7.3 |
|
|
|
6.9 |
|
| Prepayments and Other |
|
|
8.7 |
|
|
|
9.3 |
|
|
|
9.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Current Assets |
|
|
120.6 |
|
|
|
122.0 |
|
|
|
151.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Utility Plant: |
|
|
|
|
|
|
|
|
|
|
|
|
| Gas |
|
|
712.7 |
|
|
|
646.7 |
|
|
|
699.6 |
|
| Electric |
|
|
485.6 |
|
|
|
454.6 |
|
|
|
476.7 |
|
| Common |
|
|
82.1 |
|
|
|
36.0 |
|
|
|
67.4 |
|
| Construction Work in Progress |
|
|
68.4 |
|
|
|
113.0 |
|
|
|
35.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Utility Plant |
|
|
1,348.8 |
|
|
|
1,250.3 |
|
|
|
1,279.2 |
|
| Less: Accumulated Depreciation |
|
|
326.5 |
|
|
|
303.6 |
|
|
|
307.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net Utility Plant |
|
|
1,022.3 |
|
|
|
946.7 |
|
|
|
971.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other Noncurrent Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
| Regulatory Assets |
|
|
111.6 |
|
|
|
102.0 |
|
|
|
109.6 |
|
| Other Assets |
|
|
10.0 |
|
|
|
9.2 |
|
|
|
9.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Other Noncurrent Assets |
|
|
121.6 |
|
|
|
111.2 |
|
|
|
119.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| TOTAL ASSETS |
|
$ |
1,264.5 |
|
|
$ |
1,179.9 |
|
|
$ |
1,241.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(The
accompanying notes are an integral part of these consolidated unaudited financial statements.)
22
UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS (Cont.)
(Millions, except number of shares)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
September 30, |
|
|
December 31, |
|
| |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| LIABILITIES AND CAPITALIZATION: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Current Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
| Accounts Payable |
|
$ |
27.4 |
|
|
$ |
24.1 |
|
|
$ |
41.5 |
|
| Short-Term Debt |
|
|
69.1 |
|
|
|
111.9 |
|
|
|
38.3 |
|
| Long-Term Debt, Current Portion |
|
|
31.8 |
|
|
|
29.8 |
|
|
|
29.8 |
|
| Regulatory Liabilities |
|
|
12.2 |
|
|
|
15.0 |
|
|
|
9.2 |
|
| Energy Supply Obligations |
|
|
15.0 |
|
|
|
12.9 |
|
|
|
9.7 |
|
| Capital Lease Obligations |
|
|
3.1 |
|
|
|
3.1 |
|
|
|
3.1 |
|
| Other Current Liabilities |
|
|
21.9 |
|
|
|
19.5 |
|
|
|
19.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Current Liabilities |
|
|
180.5 |
|
|
|
216.3 |
|
|
|
151.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Noncurrent Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
| Retirement Benefit Obligations |
|
|
142.4 |
|
|
|
155.0 |
|
|
|
150.1 |
|
| Deferred Income Taxes, net |
|
|
86.4 |
|
|
|
109.2 |
|
|
|
82.9 |
|
| Cost of Removal Obligations |
|
|
91.2 |
|
|
|
84.8 |
|
|
|
84.3 |
|
| Regulatory Liabilities |
|
|
47.9 |
|
|
|
— |
|
|
|
48.9 |
|
| Capital Lease Obligations |
|
|
3.4 |
|
|
|
6.4 |
|
|
|
5.7 |
|
| Other Noncurrent Liabilities |
|
|
6.6 |
|
|
|
6.3 |
|
|
|
5.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Noncurrent Liabilities |
|
|
377.9 |
|
|
|
361.7 |
|
|
|
377.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Capitalization: |
|
|
|
|
|
|
|
|
|
|
|
|
| Long-Term Debt, Less Current Portion |
|
|
361.1 |
|
|
|
303.6 |
|
|
|
376.3 |
|
| Stockholders’ Equity: |
|
|
|
|
|
|
|
|
|
|
|
|
| Common Equity (Authorized: 25,000,000 and Outstanding: 14,872,011, 14,119,893 and 14,815,585 Shares) |
|
|
278.3 |
|
|
|
243.4 |
|
|
|
275.8 |
|
| Retained Earnings |
|
|
66.5 |
|
|
|
54.7 |
|
|
|
60.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Common Stock Equity |
|
|
344.8 |
|
|
|
298.1 |
|
|
|
336.6 |
|
| Preferred Stock |
|
|
0.2 |
|
|
|
0.2 |
|
|
|
0.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Stockholders’ Equity |
|
|
345.0 |
|
|
|
298.3 |
|
|
|
336.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Capitalization |
|
|
706.1 |
|
|
|
601.9 |
|
|
|
713.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Commitments and Contingencies (Notes 6 & 7) |
|
|
|
|
|
|
|
|
|
|
|
|
| TOTAL LIABILITIES AND CAPITALIZATION |
|
$ |
1,264.5 |
|
|
$ |
1,179.9 |
|
|
$ |
1,241.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(The accompanying notes are an integral part of these consolidated unaudited
financial statements.)
23
UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
| |
|
Nine Months
Ended
September 30, |
|
| |
|
2018 |
|
|
2017 |
|
| Operating Activities: |
|
|
|
|
|
|
|
|
| Net Income |
|
$ |
22.0 |
|
|
$ |
17.8 |
|
| Adjustments to Reconcile Net Income to Cash |
|
|
|
|
|
|
|
|
| Provided by Operating Activities: |
|
|
|
|
|
|
|
|
| Depreciation and Amortization |
|
|
37.4 |
|
|
|
35.2 |
|
| Deferred Tax Provision |
|
|
4.6 |
|
|
|
11.2 |
|
| Changes in Working Capital Items: |
|
|
|
|
|
|
|
|
| Accounts Receivable |
|
|
15.1 |
|
|
|
7.1 |
|
| Accrued Revenue |
|
|
17.3 |
|
|
|
10.3 |
|
| Exchange Gas Receivable |
|
|
(4.3 |
) |
|
|
(1.2 |
) |
| Regulatory Liabilities |
|
|
3.0 |
|
|
|
4.6 |
|
| Accounts Payable |
|
|
(14.1 |
) |
|
|
(8.3 |
) |
| Other Changes in Working Capital Items |
|
|
3.7 |
|
|
|
(2.6 |
) |
| Deferred Regulatory and Other Charges |
|
|
(5.7 |
) |
|
|
(5.1 |
) |
| Other, net |
|
|
(9.0 |
) |
|
|
5.7 |
|
|
|
|
|
|
|
|
|
|
| Cash Provided by Operating Activities |
|
|
70.0 |
|
|
|
74.7 |
|
|
|
|
|
|
|
|
|
|
| Investing Activities: |
|
|
|
|
|
|
|
|
| Property, Plant and Equipment Additions |
|
|
(76.3 |
) |
|
|
(84.2 |
) |
|
|
|
|
|
|
|
|
|
| Cash (Used in) Investing Activities |
|
|
(76.3 |
) |
|
|
(84.2 |
) |
|
|
|
|
|
|
|
|
|
| Financing Activities: |
|
|
|
|
|
|
|
|
| Proceeds from (Repayment of) Short-Term Debt, net |
|
|
30.8 |
|
|
|
30.0 |
|
| Repayment of Long-Term Debt |
|
|
(13.5 |
) |
|
|
(0.4 |
) |
| Decrease in Capital Lease Obligations |
|
|
(2.3 |
) |
|
|
(1.8 |
) |
| Net Increase in Exchange Gas Financing |
|
|
4.1 |
|
|
|
1.1 |
|
| Dividends Paid |
|
|
(16.3 |
) |
|
|
(15.3 |
) |
| Proceeds from Issuance of Common Stock, net |
|
|
0.9 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
| Cash Provided by Financing Activities |
|
|
3.7 |
|
|
|
14.6 |
|
|
|
|
|
|
|
|
|
|
| Net (Decrease) Increase in Cash and Cash Equivalents |
|
|
(2.6 |
) |
|
|
5.1 |
|
| Cash and Cash Equivalents at Beginning of Period |
|
|
8.9 |
|
|
|
5.8 |
|
|
|
|
|
|
|
|
|
|
| Cash and Cash Equivalents at End of Period |
|
$ |
6.3 |
|
|
$ |
10.9 |
|
|
|
|
|
|
|
|
|
|
| Supplemental Cash Flow Information: |
|
|
|
|
|
|
|
|
| Interest Paid |
|
$ |
15.6 |
|
|
$ |
15.2 |
|
| Income Taxes Paid |
|
$ |
0.4 |
|
|
$ |
— |
|
| Payments on Capital Leases |
|
$ |
2.3 |
|
|
$ |
2.5 |
|
| Non-cash Investing Activity: |
|
|
|
|
|
|
|
|
| Capital Expenditures Included in Accounts Payable |
|
$ |
1.2 |
|
|
$ |
1.8 |
|
(The
accompanying notes are an integral part of these consolidated unaudited financial statements.)
24
UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(Millions, except number of shares)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Common
Equity |
|
|
Retained
Earnings |
|
|
Total |
|
| Three Months Ended September 30, 2018 |
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at July 1, 2018 |
|
$ |
277.9 |
|
|
$ |
69.1 |
|
|
$ |
347.0 |
|
| Net Income |
|
|
|
|
|
|
2.8 |
|
|
|
2.8 |
|
| Dividends on Common Shares ($0.365 per share) |
|
|
|
|
|
|
(5.4 |
) |
|
|
(5.4 |
) |
| Stock Compensation Plans |
|
|
0.1 |
|
|
|
|
|
|
|
0.1 |
|
| Issuance of 5,423 Common Shares |
|
|
0.3 |
|
|
|
|
|
|
|
0.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at September 30, 2018 |
|
$ |
278.3 |
|
|
$ |
66.5 |
|
|
$ |
344.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at July 1, 2017 |
|
$ |
242.7 |
|
|
$ |
57.5 |
|
|
$ |
300.2 |
|
| Net Income |
|
|
|
|
|
|
2.3 |
|
|
|
2.3 |
|
| Dividends on Common Shares ($0.36 per share) |
|
|
|
|
|
|
(5.1 |
) |
|
|
(5.1 |
) |
| Stock Compensation Plans |
|
|
0.4 |
|
|
|
|
|
|
|
0.4 |
|
| Issuance of 6,173 Common Shares |
|
|
0.3 |
|
|
|
|
|
|
|
0.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at September 30, 2017 |
|
$ |
243.4 |
|
|
$ |
54.7 |
|
|
$ |
298.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(The
accompanying notes are an integral part of these consolidated unaudited financial statements.)
25
UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(Millions, except number of shares and per share data)
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Common
Equity |
|
|
Retained
Earnings |
|
|
Total |
|
| Nine Months Ended September 30, 2018 |
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at January 1, 2018 |
|
$ |
275.8 |
|
|
$ |
60.8 |
|
|
$ |
336.6 |
|
| Net Income |
|
|
|
|
|
|
22.0 |
|
|
|
22.0 |
|
| Dividends on Common Shares ($1.095 per share) |
|
|
|
|
|
|
(16.3 |
) |
|
|
(16.3 |
) |
| Stock Compensation Plans |
|
|
1.5 |
|
|
|
|
|
|
|
1.5 |
|
| Issuance of 19,700 Common Shares |
|
|
1.0 |
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at September 30, 2018 |
|
$ |
278.3 |
|
|
$ |
66.5 |
|
|
$ |
344.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at January 1, 2017 |
|
$ |
240.7 |
|
|
$ |
52.2 |
|
|
$ |
292.9 |
|
| Net Income |
|
|
|
|
|
|
17.8 |
|
|
|
17.8 |
|
| Dividends on Common Shares ($1.08 per share) |
|
|
|
|
|
|
(15.3 |
) |
|
|
(15.3 |
) |
| Stock Compensation Plans |
|
|
1.7 |
|
|
|
|
|
|
|
1.7 |
|
| Issuance of 20,564 Common Shares |
|
|
1.0 |
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at September 30, 2017 |
|
$ |
243.4 |
|
|
$ |
54.7 |
|
|
$ |
298.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(The
accompanying notes are an integral part of these consolidated unaudited financial statements.)
26
UNITIL CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 –
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations – Unitil Corporation (Unitil or the Company) is a public
utility holding company. Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005. The following companies are wholly-owned subsidiaries
of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power),
Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources). Usource Inc. and Usource L.L.C. are subsidiaries of
Unitil Resources.
The Company’s earnings are seasonal and are typically higher in the first and fourth quarters when customers use
natural gas for heating purposes.
Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and
state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts, and the local distribution of natural gas in southeastern New Hampshire, portions of southern and central Maine and in the greater Fitchburg area
of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine
(collectively referred to as the distribution utilities).
Granite State is a natural gas transportation pipeline, operating 86 miles of
underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and
Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.
A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection
with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 and divested of its long-term power supply contracts through the sale of the
entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers.
Unitil also has three other wholly-owned subsidiaries: Unitil Service; Unitil Realty; and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services,
including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s
corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource,
Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to large commercial and industrial customers in the northeastern United States.
Basis of Presentation – The accompanying unaudited Consolidated Financial Statements of Unitil have been prepared in accordance with the
instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair
presentation have been included and are of a normal and recurring nature. The results of operations for the three and nine months ended September 30, 2018 are not necessarily indicative of results to be expected for the year ending
December 31, 2018. For further information, please refer to Note 1 of Part II to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form
10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commission (SEC) on February 1, 2018, for a description of the Company’s Basis of Presentation.
27
Utility Revenue Recognition - Gas Operating Revenues and Electric Operating Revenues consist of
billed and unbilled revenue and revenue from rate adjustment mechanisms. Billed and unbilled revenue includes delivery revenue and pass-through revenue, recognized according to tariffs approved by federal and state regulatory commissions which
determine the amount of revenue the Company will record for these items. Revenue from rate adjustment mechanisms is accrued revenue, recognized in connection with rate adjustment mechanisms, and authorized by regulators for recognition in the
current period for future cash recoveries from, or credits to, customers.
Billed and unbilled revenue is recorded when service is rendered or
energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of
energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable
customer rates and are then reversed in the following month when billed to customers.
In the first quarter of 2018, the Company adopted
Accounting Standards Update (ASU) 2014-09, and its subsequent clarifications and amendments outlined in ASU 2015-14, ASU 2016-08,
ASU 2016-10 and ASU 2017-13, 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. A majority of the Company’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customer monthly consumption. Such
revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer.
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 Company’s billed and unbilled
revenue meets the definition of “revenues from contracts with customers” as defined in ASU 2014-09. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition
of alternative revenue programs in Accounting Standards Codification (ASC) 980-605-25-3, as the Company has the ability to adjust
rates in the future as a result of past activities or completed events. ASU 2014-09 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue
program revenues.
28
In the following tables, revenue is classified by the types of goods/services rendered and market/customer
type. 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 of 2017 (TCJA) are shown separately in the tables below for informational
purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended September 30, 2018 |
|
| Gas and Electric Operating Revenues ($ millions): |
|
Gas |
|
|
Electric |
|
|
Total |
|
| Billed and Unbilled Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
| Residential |
|
$ |
6.6 |
|
|
$ |
33.6 |
|
|
$ |
40.2 |
|
| C&I |
|
|
11.9 |
|
|
|
25.3 |
|
|
|
37.2 |
|
| Other |
|
|
1.5 |
|
|
|
2.6 |
|
|
|
4.1 |
|
| Revenue Reductions – TCJA |
|
|
(0.4 |
) |
|
|
(0.6 |
) |
|
|
(1.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Billed and Unbilled Revenue |
|
|
19.6 |
|
|
|
60.9 |
|
|
|
80.5 |
|
| Rate Adjustment Mechanism Revenue |
|
|
6.1 |
|
|
|
0.5 |
|
|
|
6.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Gas and Electric Operating Revenues |
|
$ |
25.7 |
|
|
$ |
61.4 |
|
|
$ |
87.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended September 30, 2017 |
|
| Gas and Electric Operating Revenues ($ millions): |
|
Gas |
|
|
Electric |
|
|
Total |
|
| Billed and Unbilled Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
| Residential |
|
$ |
6.8 |
|
|
$ |
29.9 |
|
|
$ |
36.7 |
|
| C&I |
|
|
11.5 |
|
|
|
24.3 |
|
|
|
35.8 |
|
| Other |
|
|
1.5 |
|
|
|
1.3 |
|
|
|
2.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Billed and Unbilled Revenue |
|
|
19.8 |
|
|
|
55.5 |
|
|
|
75.3 |
|
| Rate Adjustment Mechanism Revenue |
|
|
5.3 |
|
|
|
2.0 |
|
|
|
7.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Gas and Electric Operating Revenues |
|
$ |
25.1 |
|
|
$ |
57.5 |
|
|
$ |
82.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Nine Months Ended September 30, 2018 |
|
| Gas and Electric Operating Revenues ($ millions): |
|
Gas |
|
|
Electric |
|
|
Total |
|
| Billed and Unbilled Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
| Residential |
|
$ |
58.3 |
|
|
$ |
95.6 |
|
|
$ |
153.9 |
|
| C&I |
|
|
84.7 |
|
|
|
74.1 |
|
|
|
158.8 |
|
| Other |
|
|
11.0 |
|
|
|
8.6 |
|
|
|
19.6 |
|
| Revenue Reductions – TCJA |
|
|
(2.9 |
) |
|
|
(2.1 |
) |
|
|
(5.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Billed and Unbilled Revenue |
|
|
151.1 |
|
|
|
176.2 |
|
|
|
327.3 |
|
| Rate Adjustment Mechanism Revenue |
|
|
(3.7 |
) |
|
|
(8.6 |
) |
|
|
(12.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Gas and Electric Operating Revenues |
|
$ |
147.4 |
|
|
$ |
167.6 |
|
|
$ |
315.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Nine Months Ended September 30, 2017
|
|
| Gas and Electric Operating Revenues ($ millions): |
|
Gas |
|
|
Electric |
|
|
Total |
|
| Billed and Unbilled Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
| Residential |
|
$ |
52.7 |
|
|
$ |
80.9 |
|
|
$ |
133.6 |
|
| C&I |
|
|
73.7 |
|
|
|
65.0 |
|
|
|
138.7 |
|
| Other |
|
|
9.0 |
|
|
|
4.3 |
|
|
|
13.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Billed and Unbilled Revenue |
|
|
135.4 |
|
|
|
150.2 |
|
|
|
285.6 |
|
| Rate Adjustment Mechanism Revenue |
|
|
(3.5 |
) |
|
|
4.2 |
|
|
|
0.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Gas and Electric Operating Revenues |
|
$ |
131.9 |
|
|
$ |
154.4 |
|
|
$ |
286.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of
a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded as an increase or a decrease in
Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases that the Company files with the MDPU. The Company
estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.
Other Operating Revenue – Non-regulated – Usource, Unitil’s non-regulated subsidiary, conducts its
business activities as a broker of competitive energy services. Usource does not take title to the electric and gas commodities which are the subject of the brokerage contracts. The Company records energy brokering revenues based upon the amount of
electricity and gas delivered to customers through the end of the accounting period. Usource partners with certain entities to facilitate these brokerage services and pays these entities a fee under revenue sharing agreements.
As discussed above, the Company adopted ASU 2014-09 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. ASU 2014-09 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 ASU 2014-09, 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 ASU 2014-09 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 $0.8 million, respectively, in both “Other” in the “Operating Revenues” section of the Consolidated
Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings as shown in the tables below.
30
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended September 30, |
|
| |
|
As
Reported |
|
|
If ASU 2014-09
Had Been in
Effect |
|
| Other Operating Revenues ($ millions): |
|
2018 |
|
|
2017 |
|
| Usource Contract Revenue |
|
$ |
1.4 |
|
|
$ |
1.4 |
|
| Less: Revenue Sharing Payments |
|
|
0.3 |
|
|
|
0.3 |
|
|
|
|
|
|
|
|
|
|
| Total Other Operating Revenues |
|
$ |
1.1 |
|
|
$ |
1.1 |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended September 30, |
|
| |
|
As
Reported |
|
|
If ASU 2014-09
Had Been in
Effect |
|
| Operation and Maintenance Expense ($ millions): |
|
2018 |
|
|
2017 |
|
| Operation and Maintenance Expense |
|
$ |
16.4 |
|
|
$ |
16.6 |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Nine Months Ended September 30, |
|
| |
|
As
Reported |
|
|
If ASU 2014-09
Had Been in
Effect |
|
| Other Operating Revenues ($ millions): |
|
2018 |
|
|
2017 |
|
| Usource Contract Revenue |
|
$ |
4.3 |
|
|
$ |
4.5 |
|
| Less: Revenue Sharing Payments |
|
|
0.8 |
|
|
|
0.8 |
|
|
|
|
|
|
|
|
|
|
| Total Other Operating Revenues |
|
$ |
3.5 |
|
|
$ |
3.7 |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Nine Months Ended September 30, |
|
| |
|
As
Reported |
|
|
If ASU 2014-09
Had Been in
Effect |
|
| Operation and Maintenance Expense ($ millions): |
|
2018 |
|
|
2017 |
|
| Operation and Maintenance Expense |
|
$ |
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 ASU No. 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.
31
Accordingly, for all periods presented in the Consolidated Financial Statements in this Form 10-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 of non-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 of non-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.
Income Taxes – The Company is subject to Federal and State income taxes as well as various other business taxes. This process involves
estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These
temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with the Financial
Accounting Standards Board (FASB) Codification guidance on Income Taxes. The Company classifies penalty and interest expense related to income tax liabilities as income tax expense and interest expense, respectively, in the Consolidated Statements
of Earnings.
Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a
statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes.
Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid.
In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the
facts and circumstances which gave rise to the revision become known.
Cash and Cash Equivalents – Cash and Cash Equivalents
include all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents
are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE)
Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this
Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. As of
September 30, 2018, September 30, 2017 and December 31, 2017, the Unitil subsidiaries had deposited $3.2 million, $4.8 million and $2.9 million, respectively to satisfy their
ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of
September 30, 2018, September 30, 2017 and December 31, 2017.
Allowance for Doubtful Accounts – The Company
recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables
is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory
rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, the electric and gas
32
divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from
shut-off. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including the level of customers enrolling in payment plans with the
Company. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.
The Allowance for Doubtful Accounts as of September 30, 2018, September 30, 2017 and December 31, 2017, which is included in Accounts Receivable, net on the accompanying unaudited
consolidated balance sheets, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
| ($ millions) |
|
|
|
| |
|
September 30, |
|
|
December 31, |
|
| |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Allowance for Doubtful Accounts |
|
$ |
1.2 |
|
|
$ |
1.5 |
|
|
$ |
1.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues.
The following table shows the components of Accrued Revenue as of September 30, 2018, September 30, 2018 and December 31, 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
September 30, |
|
|
December 31, |
|
| Accrued Revenue ($ millions) |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Regulatory Assets – Current |
|
$ |
26.4 |
|
|
$ |
31.3 |
|
|
$ |
39.5 |
|
| Unbilled Revenues |
|
|
9.6 |
|
|
|
7.9 |
|
|
|
13.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Accrued Revenue |
|
$ |
36.0 |
|
|
$ |
39.2 |
|
|
$ |
53.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements
whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are
recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of September 30, 2018, September 30, 2017 and December 31, 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
September 30, |
|
|
December 31, |
|
| Exchange Gas Receivable ($ millions) |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Northern Utilities |
|
$ |
9.5 |
|
|
$ |
8.9 |
|
|
$ |
5.4 |
|
| Fitchburg |
|
|
0.6 |
|
|
|
0.6 |
|
|
|
0.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Exchange Gas Receivable |
|
$ |
10.1 |
|
|
$ |
9.5 |
|
|
$ |
5.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
Gas Inventory – The Company uses the weighted average cost methodology to value natural gas
inventory. The following table shows the components of gas inventory as of September 30, 2018, September 30, 2017 and December 31, 2017 which are recorded on the Consolidated Balance Sheets in Prepayments and Other.
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
September 30, |
|
|
December 31, |
|
| Gas Inventory ($ millions) |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Natural Gas |
|
$ |
0.4 |
|
|
$ |
0.4 |
|
|
$ |
0.4 |
|
| Propane |
|
|
0.4 |
|
|
|
0.2 |
|
|
|
0.1 |
|
| Liquefied Natural Gas & Other |
|
|
0.1 |
|
|
|
0.1 |
|
|
|
0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Gas Inventory |
|
$ |
0.9 |
|
|
$ |
0.7 |
|
|
$ |
0.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are
capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate
operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as
part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At September 30, 2018, September 30, 2017 and December 31, 2017, the Company estimates that the cost of removal amounts, which
are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $91.2 million, $84.8 million, and $84.3 million, respectively.
Regulatory Accounting – The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern
Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC)
and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations
guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the
applicable public utility regulatory commission.
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
September 30, |
|
|
December 31, |
|
| Regulatory Assets consist of the following ($ millions) |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Retirement Benefits |
|
$ |
88.0 |
|
|
$ |
76.2 |
|
|
$ |
84.5 |
|
| Energy Supply & Other Rate Adjustment Mechanisms |
|
|
24.8 |
|
|
|
28.2 |
|
|
|
36.0 |
|
| Deferred Storm Charges |
|
|
6.3 |
|
|
|
6.8 |
|
|
|
7.2 |
|
| Environmental |
|
|
8.9 |
|
|
|
9.9 |
|
|
|
9.5 |
|
| Income Taxes |
|
|
5.9 |
|
|
|
6.7 |
|
|
|
6.5 |
|
| Other |
|
|
4.1 |
|
|
|
5.5 |
|
|
|
5.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Regulatory Assets |
|
|
138.0 |
|
|
|
133.3 |
|
|
|
149.1 |
|
| Less: Current Portion of Regulatory Assets(1) |
|
|
26.4 |
|
|
|
31.3 |
|
|
|
39.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Regulatory Assets – noncurrent |
|
$ |
111.6 |
|
|
$ |
102.0 |
|
|
$ |
109.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (1)
|
Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets. |
34
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
September 30, |
|
|
December 31, |
|
| Regulatory Liabilities consist of the following ($ millions) |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Rate Adjustment Mechanisms |
|
$ |
12.2 |
|
|
$ |
11.6 |
|
|
$ |
6.9 |
|
| Gas Pipeline Refund (Note 6) |
|
|
— |
|
|
|
3.4 |
|
|
|
2.3 |
|
| Income Taxes (Note 8) |
|
|
47.9 |
|
|
|
— |
|
|
|
48.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Regulatory Liabilities |
|
|
60.1 |
|
|
|
15.0 |
|
|
|
58.1 |
|
| Less: Current Portion of Regulatory Liabilities |
|
|
12.2 |
|
|
|
15.0 |
|
|
|
9.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Regulatory Liabilities – noncurrent |
|
$ |
47.9 |
|
|
$ |
— |
|
|
$ |
48.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made.
Included in Regulatory Assets as of September 30, 2018 are $6.1 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. 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.
Derivatives –
The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the
guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company
determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that none of its energy supply contracts, other than the regulatory approved hedging program,
described below, qualifies as a derivative instrument under the guidance set forth in the FASB Codification.
The Company has a regulatory
approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service. 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 based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from
the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Clause.
35
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 ASC 815-20 have a fair value of $0, $0.1 million and less than $0.1 million, respectively.
Investments in Marketable Securities – In 2015, the Company established 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 Retirement Plan (“SERP”) (See further discussion of the SERP in Note 9.
At September 30, 2018, September 30, 2017 and December 31, 2017, the fair value of the Company’s investments in these trading
securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.3 million, $3.4 million and $3.6 million, respectively, as shown in the table below. These investments are valued based on quoted prices from
active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, net.
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
September 30, |
|
|
December 31, |
|
| Fair Value of Marketable Securities ($ millions) |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Equity Funds |
|
$ |
3.0 |
|
|
$ |
1.9 |
|
|
$ |
2.1 |
|
| Fixed Income Funds |
|
|
2.3 |
|
|
|
1.5 |
|
|
|
1.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Marketable Securities |
|
$ |
5.3 |
|
|
$ |
3.4 |
|
|
$ |
3.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Supply Obligations – The following discussion and table summarize the nature and amounts of the items
recorded as current and noncurrent Energy Supply Obligations on the Company’s Consolidated Balance Sheets. The noncurrent portion of Energy Supply Obligations is recorded in Other Noncurrent Liabilities on the Company’s Consolidated
Balance Sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
September 30, |
|
|
December 31, |
|
| Energy Supply Obligations ($ millions) |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Current: |
|
|
|
|
|
|
|
|
|
|
|
|
| Exchange Gas Obligation |
|
$ |
9.5 |
|
|
$ |
8.9 |
|
|
$ |
5.4 |
|
| Renewable Energy Portfolio Standards |
|
|
5.2 |
|
|
|
3.7 |
|
|
|
4.0 |
|
| Power Supply Contract Divestitures |
|
|
0.3 |
|
|
|
0.3 |
|
|
|
0.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Energy Supply Obligations – Current |
|
|
15.0 |
|
|
|
12.9 |
|
|
|
9.7 |
|
| Noncurrent: |
|
|
|
|
|
|
|
|
|
|
|
|
| Power Supply Contract Divestitures |
|
|
0.7 |
|
|
|
1.0 |
|
|
|
0.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Energy Supply Obligations |
|
$ |
15.7 |
|
|
$ |
13.9 |
|
|
$ |
10.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange Gas Obligation – Northern Utilities enters into gas exchange agreements under which Northern Utilities
releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold
the natural gas inventory to the asset manager. The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply
Obligations.
36
Renewable Energy Portfolio Standards – Renewable Energy Portfolio Standards (RPS) require retail
electricity suppliers, including public utilities, to demonstrate that required percentages of their sales are met with power generated from certain types of resources or technologies. Compliance is demonstrated by purchasing and retiring Renewable
Energy Certificates (REC) generated by facilities approved by the state as qualifying for REC treatment. Unitil Energy and Fitchburg purchase RECs in compliance with RPS legislation in New Hampshire and Massachusetts for supply provided to default
service customers. RPS compliance costs are a supply cost that is recovered in customer default service rates. Unitil Energy and Fitchburg collect RPS compliance costs from customers throughout the year and demonstrate compliance for each calendar
year on the following July 1. Due to timing differences between collection of revenue from customers and payment of REC costs to suppliers, Unitil Energy and Fitchburg typically maintain accrued revenue for RPS compliance which is recorded in
Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.
Fitchburg has
entered into long-term renewable contracts for electric energy and/or renewable energy credits pursuant to Massachusetts legislation, specifically, the Act Relative to Green Communities of 2008 and the Act Relative to Competitively Priced
Electricity (2012) in the Commonwealth, and the MDPU’s regulations implementing the legislation. The generating facilities associated with three of these contracts have been constructed and are operating. A recent round of long-term
renewable energy procurements was conducted during 2016 and several contracts were finalized and submitted to the MDPU in September, 2017 for approval. Additional procurements have been issued in compliance with the Act to Promote Energy Diversity
(2016). Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.
Power Supply Contract Divestitures – As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the
opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and
Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their
power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. The obligations related to these divestitures are recorded in Energy Supply Obligations on
the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion).
Recently Issued Pronouncements – In August 2018, the FASB issued Accounting Standards Update (ASU) No. 2018-14, “Compensation –
Retirement Benefits – Defined Benefit Plans – General (Sutopic 715-20)” 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 ASU
No. 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.
37
In March 2017, the FASB issued ASU No. 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.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)”. The new standard requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than 12 months. Leases will be
classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company plans to adopt 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 payments 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 ASU No. 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.
Other than the pronouncements discussed above, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.
Subsequent Events – The Company has evaluated all events or transactions through the date of this filing. During this period the Company
did not have any material subsequent events that impacted its unaudited consolidated financial statements.
38
NOTE 2 – DIVIDENDS DECLARED PER SHARE
|
|
|
|
|
|
|
| Declaration
Date |
|
Date
Paid
(Payable) |
|
Shareholder of
Record Date |
|
Dividend
Amount |
| 10/24/18 |
|
11/29/18 |
|
11/15/18 |
|
$0.365 |
| 07/25/18 |
|
08/29/18 |
|
08/15/18 |
|
$0.365 |
| 04/25/18 |
|
05/29/18 |
|
05/15/18 |
|
$0.365 |
| 01/30/18 |
|
02/28/18 |
|
02/14/18 |
|
$0.365 |
|
|
|
|
| 10/25/17 |
|
11/29/17 |
|
11/15/17 |
|
$0.360 |
| 07/26/17 |
|
08/29/17 |
|
08/15/17 |
|
$0.360 |
| 04/26/17 |
|
05/30/17 |
|
05/16/17 |
|
$0.360 |
| 01/25/17 |
|
02/28/17 |
|
02/14/17 |
|
$0.360 |
39
NOTE 3 – SEGMENT INFORMATION
The following table provides significant segment financial data for the three and nine months ended September 30, 2018 and September 30, 2017 and as of December 31, 2017 (millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Gas |
|
|
Electric |
|
|
Non-
Regulated |
|
|
Other |
|
|
Total |
|
|
|
|
|
|
|
| Three Months Ended September 30, 2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Billed and Unbilled Revenue |
|
$ |
19.6 |
|
|
$ |
60.9 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
80.5 |
|
| Rate Adjustment Mechanism Revenue |
|
|
6.1 |
|
|
|
0.5 |
|
|
|
— |
|
|
|
— |
|
|
|
6.6 |
|
| Other Operating Revenue – Non-Regulated |
|
|
— |
|
|
|
— |
|
|
|
1.1 |
|
|
|
— |
|
|
|
1.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Operating Revenues |
|
$ |
25.7 |
|
|
$ |
61.4 |
|
|
$ |
1.1 |
|
|
$ |
— |
|
|
$ |
88.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Segment Profit (Loss) |
|
|
(3.2 |
) |
|
|
4.5 |
|
|
|
0.3 |
|
|
|
1.2 |
|
|
|
2.8 |
|
| Capital Expenditures |
|
|
30.9 |
|
|
|
7.2 |
|
|
|
— |
|
|
|
1.0 |
|
|
|
39.1 |
|
|
|
|
|
|
|
| Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Revenues |
|
$ |
25.1 |
|
|
$ |
57.5 |
|
|
$ |
1.4 |
|
|
$ |
— |
|
|
$ |
84.0 |
|
| Segment Profit (Loss) |
|
|
(2.1 |
) |
|
|
4.1 |
|
|
|
0.3 |
|
|
|
— |
|
|
|
2.3 |
|
| Capital Expenditures |
|
|
26.0 |
|
|
|
10.0 |
|
|
|
— |
|
|
|
3.3 |
|
|
|
39.3 |
|
|
|
|
|
|
|
| Nine Months Ended September 30, 2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Billed and Unbilled Revenue |
|
$ |
151.1 |
|
|
$ |
176.2 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
327.3 |
|
| Rate Adjustment Mechanism Revenue |
|
|
(3.7 |
) |
|
|
(8.6 |
) |
|
|
— |
|
|
|
— |
|
|
|
(12.3 |
) |
| Other Operating Revenue – Non-Regulated |
|
|
— |
|
|
|
— |
|
|
|
3.5 |
|
|
|
— |
|
|
|
3.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Operating Revenues |
|
$ |
147.4 |
|
|
$ |
167.6 |
|
|
$ |
3.5 |
|
|
$ |
— |
|
|
$ |
318.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Segment Profit |
|
|
9.1 |
|
|
|
10.2 |
|
|
|
0.9 |
|
|
|
1.8 |
|
|
|
22.0 |
|
| Capital Expenditures |
|
|
53.1 |
|
|
|
20.8 |
|
|
|
— |
|
|
|
2.4 |
|
|
|
76.3 |
|
| Segment Assets |
|
|
730.0 |
|
|
|
485.7 |
|
|
|
6.6 |
|
|
|
42.2 |
|
|
|
1,264.5 |
|
|
|
|
|
|
|
| Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Revenues |
|
$ |
131.9 |
|
|
$ |
154.4 |
|
|
$ |
4.5 |
|
|
$ |
— |
|
|
$ |
290.8 |
|
| Segment Profit |
|
|
7.9 |
|
|
|
9.3 |
|
|
|
0.8 |
|
|
|
(0.2 |
) |
|
|
17.8 |
|
| Capital Expenditures |
|
|
48.7 |
|
|
|
23.8 |
|
|
|
— |
|
|
|
11.7 |
|
|
|
84.2 |
|
| Segment Assets |
|
|
661.2 |
|
|
|
461.2 |
|
|
|
7.3 |
|
|
|
50.2 |
|
|
|
1,179.9 |
|
|
|
|
|
|
|
| As of December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Segment Assets |
|
$ |
714.3 |
|
|
$ |
476.9 |
|
|
$ |
6.7 |
|
|
$ |
44.0 |
|
|
$ |
1,241.9 |
|
40
NOTE 4 – DEBT AND FINANCING ARRANGEMENTS
Details on long-term debt at September 30, 2018, September 30, 2017 and December 31, 2017 are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
| ($ millions) |
|
September 30, |
|
|
December 31, |
|
| |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Unitil Corporation: |
|
|
|
|
|
|
|
|
|
|
|
|
| 6.33% Senior Notes, Due May 1, 2022 |
|
$ |
20.0 |
|
|
$ |
20.0 |
|
|
$ |
20.0 |
|
| 3.70% Senior Notes, Due August 1, 2026 |
|
|
30.0 |
|
|
|
30.0 |
|
|
|
30.0 |
|
| Unitil Energy First Mortgage Bonds: |
|
|
|
|
|
|
|
|
|
|
|
|
| 5.24% Senior Secured Notes, Due March 2, 2020 |
|
|
10.0 |
|
|
|
15.0 |
|
|
|
15.0 |
|
| 8.49% Senior Secured Notes, Due October 14, 2024 |
|
|
7.5 |
|
|
|
9.0 |
|
|
|
7.5 |
|
| 6.96% Senior Secured Notes, Due September 1, 2028 |
|
|
20.0 |
|
|
|
20.0 |
|
|
|
20.0 |
|
| 8.00% Senior Secured Notes, Due May 1, 2031 |
|
|
15.0 |
|
|
|
15.0 |
|
|
|
15.0 |
|
| 6.32% Senior Secured Notes, Due September 15, 2036 |
|
|
15.0 |
|
|
|
15.0 |
|
|
|
15.0 |
|
| Fitchburg: |
|
|
|
|
|
|
|
|
|
|
|
|
| 6.75% Senior Notes, Due November 30, 2023 |
|
|
7.6 |
|
|
|
9.5 |
|
|
|
7.6 |
|
| 6.79% Senior Notes, Due October 15, 2025 |
|
|
10.0 |
|
|
|
10.0 |
|
|
|
10.0 |
|
| 3.52% Senior Notes, Due November 1, 2027 |
|
|
10.0 |
|
|
|
— |
|
|
|
10.0 |
|
| 7.37% Notes, Due January 15, 2029 |
|
|
12.0 |
|
|
|
12.0 |
|
|
|
12.0 |
|
| 5.90% Notes, Due December 15, 2030 |
|
|
15.0 |
|
|
|
15.0 |
|
|
|
15.0 |
|
| 7.98% Notes, Due June 1, 2031 |
|
|
14.0 |
|
|
|
14.0 |
|
|
|
14.0 |
|
| 4.32% Senior Notes, Due November 1, 2047 |
|
|
15.0 |
|
|
|
— |
|
|
|
15.0 |
|
| Northern Utilities: |
|
|
|
|
|
|
|
|
|
|
|
|
| 6.95% Senior Notes, Due December 3, 2018 |
|
|
10.0 |
|
|
|
20.0 |
|
|
|
10.0 |
|
| 5.29% Senior Notes, Due March 2, 2020 |
|
|
16.6 |
|
|
|
25.0 |
|
|
|
25.0 |
|
| 3.52% Senior Notes, Due November 1, 2027 |
|
|
20.0 |
|
|
|
— |
|
|
|
20.0 |
|
| 7.72% Senior Notes, Due December 3, 2038 |
|
|
50.0 |
|
|
|
50.0 |
|
|
|
50.0 |
|
| 4.42% Senior Notes, Due October 15, 2044 |
|
|
50.0 |
|
|
|
50.0 |
|
|
|
50.0 |
|
| 4.32% Senior Notes, Due November 1, 2047 |
|
|
30.0 |
|
|
|
— |
|
|
|
30.0 |
|
| Granite State Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
| 7.15% Senior Notes, Due December 15, 2018 |
|
|
3.3 |
|
|
|
6.7 |
|
|
|
3.3 |
|
| 3.72% Senior Notes, Due November 1, 2027 |
|
|
15.0 |
|
|
|
— |
|
|
|
15.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Long-Term Debt |
|
|
396.0 |
|
|
|
336.2 |
|
|
|
409.4 |
|
| Less: Unamortized Debt Issuance Costs |
|
|
3.1 |
|
|
|
2.8 |
|
|
|
3.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Long-Term Debt, net of Unamortized Debt Issuance Costs |
|
|
392.9 |
|
|
|
333.4 |
|
|
|
406.1 |
|
| Less: Current Portion |
|
|
31.8 |
|
|
|
29.8 |
|
|
|
29.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Long-term Debt, Less Current Portion |
|
$ |
361.1 |
|
|
$ |
303.6 |
|
|
$ |
376.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41
Fair Value of Long-Term Debt – Currently, the Company believes that there is no active market in
the Company’s debt securities, which have all been sold through private placements. If there were an active market for the Company’s debt securities, the fair value of the Company’s long-term debt would be estimated based on the
quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. The fair value of the Company’s long-term debt is estimated using Level 2 inputs (valuations
based on quoted prices available in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are directly observable, and inputs derived
principally from market data.) In estimating the fair value of the Company’s long-term debt, the assumed market yield reflects the Moody’s Baa Utility Bond Average Yield. Costs, including prepayment costs, associated with the early
settlement of long-term debt are not taken into consideration in determining fair value.
|
|
|
|
|
|
|
|
|
|
|
|
|
| ($ millions) |
|
September 30, |
|
|
December 31, |
|
| |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Estimated Fair Value of Long-Term Debt |
|
$ |
418.7 |
|
|
$ |
383.0 |
|
|
$ |
457.1 |
|
Credit Arrangements
On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement and related documents (collectively, the “Credit Facility”) with a syndicate of lenders, which
amended and restated in its entirety the Company’s prior credit facility. The Credit Facility extends to July 25, 2023, subject to two one-year extensions under certain circumstances, and has a
borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company with the ability to elect that borrowings under the Credit Facility bear
interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.125%. The Company may increase the borrowing limit under the
Credit Facility by up to $50 million under certain circumstances.
The Company utilizes the Credit Facility for cash management purposes
related to its short-term operating activities. Total gross borrowings were $202.5 million for the nine months ended September 30, 2018. Total gross repayments were $171.7 million for the nine months ended September 30, 2018. The
following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of September 30, 2018, September 30, 2017 and December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Credit Facility ($ millions) |
|
| |
|
September 30, |
|
|
December 31, |
|
| |
|
2018 |
|
|
2017 |
|
|
2017 |
|
| Limit |
|
$ |
120.0 |
|
|
$ |
120.0 |
|
|
$ |
120.0 |
|
| Short-Term Borrowings Outstanding |
|
|
69.1 |
|
|
|
111.9 |
|
|
|
38.3 |
|
| Letters of Credit Outstanding |
|
|
— |
|
|
|
1.1 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Available |
|
$ |
50.9 |
|
|
$ |
7.0 |
|
|
$ |
81.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and
negative covenants. There are restrictions on, among other things, the Company’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on the Company’s ability to merge or consolidate with another
entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply until the Credit Facility terminates and all amounts
42
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, 2018, September 30, 2017 and December 31, 2017, the Company was in compliance with the covenants
contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 4.)
The weighted average interest
rates on all short-term borrowings and intercompany money pool transactions were 3.2% and 2.3% for the nine months ended September 30, 2018 and September 30, 2017, respectively. The weighted average interest rate on all short-term
borrowings for the twelve months ended December 31, 2017 was 2.4%.
On November 1, 2017, Northern Utilities issued $20 million
of Notes due 2027 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%. Northern Utilities, Fitchburg and Granite State used the net proceeds from these offerings to refinance higher cost long-term debt that matured in 2017, to repay short-term debt and for general corporate purposes. Approximately
$0.7 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.
In April 2014, Unitil Service Corp. entered into a financing arrangement, structured as a capital lease obligation, for various information systems and technology equipment. Final funding under this
capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As 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.
Unitil Corporation and its utility
subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services. Unitil Corporation and Granite State are currently rated “Baa2”, and
Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1” by Moody’s Investors Services.
Northern Utilities
enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course
of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $9.6 million, $9.0 million and $8.5 million of natural gas storage inventory at September 30,
2018, September 30, 2017 and December 31, 2017, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2018 and payable in October 2018 is $0.1 million and is 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 2017 and payable in January 2018 was $3.1 million and was recorded in Accounts Payable at December 31, 2017.
Guarantees
The Company provides limited guarantees on certain energy and natural gas
storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of September 30, 2018, there were approximately $5.6 million of guarantees outstanding.
The Company also guarantees the payment of principal, interest and other amounts payable on the 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.
43
NOTE 5 – COMMON STOCK AND PREFERRED STOCK
Common Stock
The Company’s common
stock trades on the New York Stock Exchange under the symbol, “UTL.”
The Company had 14,119,893,14,815,585 and 14,872,011 shares of
common stock outstanding at September 30, 2017, December 31, 2017 and September 30, 2018, 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.
Dividend Reinvestment and Stock Purchase Plan - During the first nine months of 2018, the Company sold 19,700 shares of its common stock, at an
average price of $46.97 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $925,000. The DRP provides participants in the plan a method for investing
cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.
Stock Plan
- The Company maintains the Unitil Corporation Second Amended and Restated 2003 Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors to receive awards under the Stock
Plan, including awards of restricted shares (Restricted Shares), or of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a
manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s
administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee
as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan
participants.
The maximum number of shares available for awards to participants under the Stock Plan is 677,500. The maximum number of shares
that may be awarded in any one calendar year to any one participant is 20,000. In the event of any change in capitalization of the Company, the Compensation Committee is authorized to make an equitable adjustment to the number and kind of shares of
common stock that may be delivered under the Stock Plan and, in addition, may authorize and make an equitable adjustment to the Stock Plan’s annual individual award limit.
Restricted Shares
Outstanding awards of Restricted Shares fully vest over a period of four
years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a participant’s account. The Company may deduct or withhold, or require a participant to remit to the Company,
an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with an Award. For purposes of compensation expense, Restricted Shares vest
immediately upon a participant becoming eligible for retirement, as defined in the Stock Plan. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than
due to the participant’s death.
44
On January 29, 2018, 37,510 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 49,581 and 89,326 non-vested shares under the Stock Plan as of September 30, 2018 and 2017, respectively. The
weighted average grant date fair value of these shares was $41.96 and $39.54, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $2.1 million
and $2.6 million for the nine months ended September 30, 2018 and 2017, respectively. At September 30, 2018, there was approximately $1.0 million of total unrecognized compensation cost under the Stock Plan which is expected to
be recognized over approximately 2.5 years. During the nine months ended September 30, 2018 there were 784 shares of Restricted Shares forfeited. There were no cancellations under the Stock Plan during the nine months ended September 30,
2018.
Restricted Stock Units
Non-management members of the Company’s Board of Directors (Directors) may elect to receive the equity
portion of their annual retainer in the form of Restricted Stock Units. Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from
service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair
market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity portion of Restricted Stock Units activity during the nine months ended September 30, 2018 in conjunction with the Stock Plan
are presented in the following table:
|
|
|
|
|
|
|
|
|
| Restricted Stock Units (Equity
Portion) |
|
| |
|
Units |
|
|
Weighted
Average
Stock
Price |
|
| Restricted Stock Units as of December 31, 2017 |
|
|
52,224 |
|
|
$ |
36.22 |
|
| Restricted Stock Units Granted |
|
|
— |
|
|
|
— |
|
| Dividend Equivalents Earned |
|
|
1,230 |
|
|
$ |
46.87 |
|
| Restricted Stock Units Settled |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
| Restricted Stock Units as of September 30, 2018 |
|
|
53,454 |
|
|
$ |
36.47 |
|
|
|
|
|
|
|
|
|
|
There were 44,343 Restricted Stock Units outstanding as of September 30, 2017 with a weighted average stock price of
$33.72. On October 1, 2018, there were 11,275 fully-vested Restricted Stock Units issued to members of the Company’s Board of Directors. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of
September 30, 2018, September 30, 2017 and December 31, 2017 is $1.2 million, $0.9 million and $1.0 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that
will be settled in cash.
Preferred Stock
There was $0.2 million, or 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2018, September 30, 2017 and December 31, 2017. 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, 2018 and September 30, 2017, respectively.
NOTE 6 – REGULATORY MATTERS
UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE
8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2017 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2018.
45
Tax Cuts and Jobs Act of 2017
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law. Among other things, the TCJA substantially reduced the corporate income tax rate to 21 percent, effective
January 1, 2018. Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, has issued procedural orders directing how the tax law changes are to be reflected
in rates, including requiring that the companies provide certain filings and calculations. 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). 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.
In Maine, Northern Utilities’ Maine division recently completed a base 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 among 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 pursuant to the provisions of its last 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 on 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 Activity
Unitil 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 2019 to recover the revenue requirements associated with annual capital
expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s second step adjustment filing. The filing incorporated the revenue requirement of $3.3 million 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 the one-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 decrease of $0.3 million.
Fitchburg – Base Rates
– Electric – Fitchburg’s last base rate order from the MDPU, issued in April 2016, included the approval of an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions.
While a number of the capital cost recovery filings may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory
proceedings and there are no material issues outstanding. On June 28, 2018, Fitchburg filed its compliance report of capital investments for calendar year 2017. This matter remains pending.
46
Fitchburg – Electric Grid Modernization – On May 10, 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 address
pre-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, subject to further investigation and reconciliation. A final order is pending.
Fitchburg – Base Rates – Gas – Pursuant to the Company’s revenue decoupling adjustment clause tariff, as approved in its last
base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather and energy efficiency impacts to the Company’s revenues.
The MDPU has consistently found that the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that they result in just and reasonable rates.
Fitchburg – Gas System Enhancement Program – Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain
gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be
filed on or before October 31; 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 from year-to-year in any given year, the
Company considers these to be routine regulatory proceedings and there are no material issues outstanding. Under this tariff, a revenue increase of $0.9 million went into effect on May 1, 2018, subject to 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 annual 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,
47
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 Area Build-out Program – Maine – In December 2015, the MPUC approved a Targeted Area Build-out (TAB) program and associated rate surcharge mechanism. 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 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 Epping remains pending.
Granite State – Base Rates – On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which
provided for no change in rates, and accounted for the effects of a capital step adjustment offset by the effect of the TCJA. The settlement was approved by FERC on June 27, 2018, and complies with the FERC Notice of Proposed Rulemaking
concerning the justness and reasonableness of rates in light of the corporate income tax reductions under the TCJA. The settlement also provides that Granite State may not file a general (Section 4) rate case prior to April 30, 2019.
Other Matters
NHPUC
Energy Efficiency Resource Standard Proceeding – On August 2, 2016, the NHPUC issued an order establishing an Energy Efficiency Resource Standard (EERS), an energy efficiency policy 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 related to the EERS programs, and performance incentives and processes for stakeholder involvement,
evaluation, measurement and verification, and oversight of the EERS programs. In accordance with the Order, on September 1, 2017, the New Hampshire electric and gas utilities jointly filed a Statewide Energy Efficiency Plan for the period
2018-2020, which was approved on January 2, 2018. On September 14, 2018, the New 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.
48
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 prepare a final report with recommendations for 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, 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. The Company does not believe that this proceeding will have a material adverse impact on the Company’s financial position, operating results or
cash flows.
Unitil Energy – Recent Legislation – On September 13, 2018, the 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 approved by the NHPUC in each
applicable default service supply solicitation proceeding. The anticipated higher cost differential of the power purchase agreement is to be recovered through a
non-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 1 of the following year, and the MDPU approves them subject to
reconciliation and pending further investigation. Subsequently, during the course of the year, the MDPU engages in more intensive review of these filings, including discovery and, when deemed necessary, the scheduling of evidentiary hearings. While
a number of the Reconciling Filings may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory proceedings and there
are no material issues outstanding.
Fitchburg – Service Quality – On March 1, 2018, Fitchburg submitted its 2017
Service Quality Reports for both its gas and electric divisions in accordance 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 – Massachusetts Governor Baker signed into law H.4568 “An Act to Promote Energy Diversity” on August 8, 2016. Among many sections in the
bill, the primary provision adds new sections 83c and 83d to the 2008 Green Communities Act. Section 83c requires every electric distribution company (EDC), including Fitchburg, to jointly and competitively solicit proposals 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 by the MDPU that
the proposed long-term contracts are cost-effective. Section 83d further requires the EDCs to jointly seek proposals for cost effective clean energy (hydro and other) 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 regulations
49
implementing 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. The EDCs issued the RFP for Long-Term Contracts for Clean Energy Projects, pursuant to Section 83d on March 31, 2017 and project proposals were received on July 27, 2017. Final selection of projects concluded in
the first quarter of 2018, contracts were signed in June 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed the 83d long-term contracts with MDPU for approval. This matter remains pending. The EDCs issued the RFP for Long-Term
Contracts for Offshore Wind Energy Projects pursuant to Section 83c on 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 83c long-term contracts 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 to the MDPU,
in a uniform manner, lost and unaccounted for gas each year; Requires electric distribution companies to annually file with the MDPU an Electric Distribution System Resiliency Report which must include heat maps that show the electric load on the
distribution system including loads during peak times, highlight the most congested or constrained areas 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, issued an RFP for clean energy resources (including Class I renewable generation and large hydroelectric generation) in November 2015. The RFP
sought proposals 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 during the second quarter of 2017. On September 20, 2017, Fitchburg, along with the other three EDCs, filed for approval of the purchase power agreements which were negotiated as a result of the joint solicitation. A
hearing on the merits was held in February 2018. 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 pursuant to Chapter 75 of the Acts of 2016,
which required the DOER to establish a new solar incentive program. The regulation is designed 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 jointly filed a model SMART tariff
50
with the MDPU to implement the program 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 required to submit to the MDPU its annual SMART Factor cost recovery filing for effect January 1 of the next year. This matter remains pending.
FERC Transmission Formula Rate Proceedings – Pursuant to Section 206 of the Federal Power Act, there are several pending proceedings before the FERC concerning the justness and
reasonableness of the Return on Equity (ROE) component of the ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates. On April 14,
2017, the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating a decision of the FERC with respect to the ROE, and remanded it for further proceedings. The FERC had found that the Transmission Owners existing ROE was unlawful, and
had set a new ROE. The Court found that the FERC had failed to articulate a satisfactory explanation for its orders. At this time, the ROE set in the vacated order will remain in place until further FERC action is taken. Separately, on
March 15, 2018, the Transmission Owners filed a petition for review with the Court of certain orders of the FERC setting for hearing other complaints challenging the allowed return on equity component of the formula rates. Also pending at FERC
is a Section 206 proceeding concerning the justness and reasonableness of ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and
to develop formula rate protocols for these rates. On August 17, 2018 a joint settlement agreement among a number of the parties was filed with the FERC and remains pending. Fitchburg and Unitil Energy are Participating Transmission Owners,
although Unitil Energy does not own transmission plant. To the extent that these proceedings result in any changes to the rates being charged, a retroactive reconciliation may be required. The Company does not believe that these proceedings will
have a material adverse impact on the Company’s financial condition or results of operations.
Legal Proceedings
The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. The Company
believes, based upon information furnished by counsel and others, that the ultimate resolution of these claims will not have a material impact on its financial position, operating results or cash flows.
In 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.
NOTE 7 – ENVIRONMENTAL MATTERS
UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2017 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2018.
The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material
compliance with applicable environmental and safety laws and regulations and, as of September 30, 2018, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company cannot assure
that significant costs and liabilities will not be incurred in the future. It is
51
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.
Northern Utilities Manufactured Gas Plant Sites – Northern Utilities
has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites, which were operated from the mid-1800s through the mid-1900s.
In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough.
Northern Utilities has worked with the Maine Department of Environmental Protection and New Hampshire Department of Environmental Services to
address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of all sites, though on site monitoring continues and it is possible that future activities may be required. Supplemental
remediation at the Exeter MGP commenced in the second quarter of 2018 and was completed in the third quarter of 2018.
The NHPUC and MPUC have
approved regulatory mechanisms for the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding seven-year periods. For Northern
Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five-year periods.
The Environmental Obligations table below shows the amounts accrued for Northern Utilities related to estimated future cleanup costs associated with
Northern Utilities’ environmental remediation obligations for former MGP sites. Corresponding Regulatory Assets were recorded to reflect that the future recovery of these environmental remediation costs is expected based on regulatory precedent
and established practices.
Fitchburg’s Manufactured Gas Plant Site – Fitchburg has worked with the Massachusetts Department
of Environmental Protection to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring will continue and it is possible that future activities may
be required.
The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated future cleanup costs for
permanent remediation of the Sawyer Passway site with a corresponding Regulatory Asset recorded to reflect that the recovery of these environmental remediation costs are probable through the regulatory process. The amounts recorded do not assume any
amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU.
Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods.
The following table sets forth a summary of changes in the Company’s liability for environmental obligations for the nine months ended September 30, 2018 and 2017. The Company’s current and
noncurrent environmental obligations are recorded on the Company’s Consolidated Balance Sheets in Other Current Liabilities and Other Noncurrent Liabilities, respectively.
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Environmental Obligations |
|
|
|
|
|
|
|
|
|
| |
|
($ millions) |
|
| |
|
Fitchburg |
|
|
Northern
Utilities |
|
|
Total |
|
| |
|
Nine months ended September 30, |
|
| |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
| Total Balance at Beginning of Period |
|
$ |
0.1 |
|
|
$ |
0.1 |
|
|
$ |
2.0 |
|
|
$ |
1.8 |
|
|
$ |
2.1 |
|
|
$ |
1.9 |
|
| Additions |
|
|
— |
|
|
|
— |
|
|
|
0.6 |
|
|
|
0.5 |
|
|
|
0.6 |
|
|
|
0.5 |
|
| Less: Payments / Reductions |
|
|
0.1 |
|
|
|
— |
|
|
|
0.5 |
|
|
|
0.2 |
|
|
|
0.6 |
|
|
|
0.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Balance at End of Period |
|
|
— |
|
|
|
0.1 |
|
|
|
2.1 |
|
|
|
2.1 |
|
|
|
2.1 |
|
|
|
2.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Less: Current Portion |
|
|
— |
|
|
|
0.1 |
|
|
|
0.6 |
|
|
|
0.4 |
|
|
|
0.6 |
|
|
|
0.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Noncurrent Balance at End of Period |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
1.5 |
|
|
$ |
1.7 |
|
|
$ |
1.5 |
|
|
$ |
1.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 8: INCOME TAXES
The Company filed its tax returns for the year ended December 31, 2017 with the Internal Revenue Service in September 2018 and generated additional federal net operating loss (NOL) carryforward
assets principally due to current pension deductions, tax repair deductions, tax depreciation and research and development deductions. As of September 30, 2018, the Company had recorded cumulative federal and state NOL carryforward assets of
$18.2 million to offset against taxes payable in future periods. If unused, the Company’s NOL carryforward assets will begin to expire in 2029. In addition, at September 30, 2018, the Company had $3.4 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 resolution of this examination will not have a material impact on the Company’s financial statements. The Company remains
subject to examination by New Hampshire tax authorities for the tax periods ended December 31, 2015; December 31, 2016; and December 31, 2017. Income tax filings for the year ended December 31, 2017 have been filed with the New
Hampshire Department of Revenue Administration. The State of Maine has concluded its review of the Company’s tax returns for December 31, 2014, December 31, 2015, and December 31, 2016 which resulted in a small additional refund
to the Company.
In assessing the near-term use of NOLCs and tax credits, the Company evaluates the expected level of future taxable income,
available tax planning strategies, reversals of existing taxable temporary differences and taxable income available in carryback years. Based on all available evidence, both positive and negative, and the weight of that evidence to the extent such
evidence can be objectively verified, the Company expects to utilize all of its NOLCs by December 31, 2020 prior to their expiration in 2029.
In 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.
53
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 the re-measurement of regulatory deferred tax balances. At this time, the Company has applied a reasonable interpretation of the TCJA and a reasonable estimate of the regulatory resolution. Future clarification of TCJA
matters with the Company’s regulators may change the amounts estimated.
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.
The Company bills its customers for sales tax in Massachusetts and Maine and consumption tax in New Hampshire. These taxes are remitted to the appropriate departments of revenue in each state and are
excluded from revenues on the Company’s unaudited Consolidated Statements of Earnings.
NOTE 9: RETIREMENT BENEFIT OBLIGATIONS
The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree
Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation Supplemental Executive Retirement Plan (SERP) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the
Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2017 as filed with the SEC on February 1, 2018 for additional information regarding these plans.
The following table includes the key weighted average assumptions used in determining the Company’s benefit plan costs and obligations:
|
|
|
|
|
|
|
|
|
| |
|
2018 |
|
|
2017 |
|
| Used to Determine Plan Costs |
|
|
|
|
|
|
|
|
| Discount Rate |
|
|
3.60 |
% |
|
|
4.10 |
% |
| Rate of Compensation Increase |
|
|
3.00 |
% |
|
|
3.00 |
% |
| Expected Long-term rate of return on plan assets |
|
|
7.75 |
% |
|
|
7.75 |
% |
| Health Care Cost Trend Rate Assumed for Next Year |
|
|
7.50 |
% |
|
|
8.00 |
% |
| Ultimate Health Care Cost Trend Rate |
|
|
4.50 |
% |
|
|
4.00 |
% |
| Year that Ultimate Health Care Cost Trend Rate is reached |
|
|
2024 |
|
|
|
2025 |
|
54
The following tables provide the components of the Company’s Retirement plan costs ($000’s):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Pension Plan |
|
|
PBOP Plan |
|
|
SERP |
|
| Three Months Ended September 30, |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
| Service Cost |
|
$ |
848 |
|
|
$ |
824 |
|
|
$ |
733 |
|
|
$ |
744 |
|
|
$ |
122 |
|
|
$ |
115 |
|
| Interest Cost |
|
|
1,469 |
|
|
|
1,514 |
|
|
|
852 |
|
|
|
978 |
|
|
|
101 |
|
|
|
98 |
|
| Expected Return on Plan Assets |
|
|
(1,946 |
) |
|
|
(1,826 |
) |
|
|
(409 |
) |
|
|
(337 |
) |
|
|
— |
|
|
|
— |
|
| Prior Service Cost Amortization |
|
|
81 |
|
|
|
66 |
|
|
|
327 |
|
|
|
350 |
|
|
|
47 |
|
|
|
47 |
|
| Actuarial Loss Amortization |
|
|
1,447 |
|
|
|
1,165 |
|
|
|
346 |
|
|
|
524 |
|
|
|
121 |
|
|
|
74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sub-total |
|
|
1,899 |
|
|
|
1,743 |
|
|
|
1,849 |
|
|
|
2,259 |
|
|
|
391 |
|
|
|
334 |
|
| Amounts Capitalized and Deferred |
|
|
(962 |
) |
|
|
(932 |
) |
|
|
(930 |
) |
|
|
(1,226 |
) |
|
|
(113 |
) |
|
|
(99 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net Periodic Benefit Cost Recognized |
|
$ |
937 |
|
|
$ |
811 |
|
|
$ |
919 |
|
|
$ |
1,033 |
|
|
$ |
278 |
|
|
$ |
235 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Pension Plan |
|
|
PBOP Plan |
|
|
SERP |
|
| Nine Months Ended September 30, |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
| Service Cost |
|
$ |
2,544 |
|
|
$ |
2,471 |
|
|
$ |
2,199 |
|
|
$ |
2,231 |
|
|
$ |
366 |
|
|
$ |
345 |
|
| Interest Cost |
|
|
4,407 |
|
|
|
4,543 |
|
|
|
2,554 |
|
|
|
2,935 |
|
|
|
303 |
|
|
|
294 |
|
| Expected Return on Plan Assets |
|
|
(5,838 |
) |
|
|
(5,479 |
) |
|
|
(1,227 |
) |
|
|
(1,010 |
) |
|
|
— |
|
|
|
— |
|
| Prior Service Cost Amortization |
|
|
243 |
|
|
|
197 |
|
|
|
981 |
|
|
|
1,049 |
|
|
|
141 |
|
|
|
141 |
|
| Actuarial Loss Amortization |
|
|
4,341 |
|
|
|
3,496 |
|
|
|
1,038 |
|
|
|
1,573 |
|
|
|
365 |
|
|
|
222 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sub-total |
|
|
5,697 |
|
|
|
5,228 |
|
|
|
5,545 |
|
|
|
6,778 |
|
|
|
1,175 |
|
|
|
1,002 |
|
| Amounts Capitalized and Deferred |
|
|
(2,590 |
) |
|
|
(2,402 |
) |
|
|
(2,557 |
) |
|
|
(3,418 |
) |
|
|
(339 |
) |
|
|
(297 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net Periodic Benefit Cost Recognized |
|
$ |
3,107 |
|
|
$ |
2,826 |
|
|
$ |
2,988 |
|
|
$ |
3,360 |
|
|
$ |
836 |
|
|
$ |
705 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employer Contributions
As of September 30, 2018, the Company had made $16.6 million and $3.0 million of contributions to its Pension and PBOP Plans, respectively, in 2018. The Company, along with its
subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2018 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for
these Pension and PBOP Plan costs.
As of September 30, 2018, the Company had made $87,500 of benefit payments under the SERP in 2018.
The Company presently anticipates making an additional $313,100 of benefit payments under the SERP in 2018.
| Item 3. |
Quantitative and Qualitative Disclosures About Market Risk |
Reference is made to the “Interest Rate Risk” and “Market Risk” sections of Item 2. “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” (above).
| Item 4. |
Controls and Procedures |
Management of the Company, under the supervision and with the participation of the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, carried out an evaluation
of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of September 30, 2018. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief
Accounting Officer concluded as of September 30, 2018 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15(d)-15(e)) are effective.
55
There have been no changes in the Company’s internal control over financial reporting (as defined in
Exchange Act Rules 13a-15(f) and 15(d)-15(f)) during the fiscal quarter covered by this Form 10-Q that have materially
affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II. OTHER
INFORMATION
| Item 1. |
Legal Proceedings |
The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. Certain specific matters are discussed in Notes 6 and 7 to the
Consolidated Financial Statements. In the opinion of Management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company’s financial position.
There have been no material changes to the risk factors disclosed in the Company’s Form 10-K for the year-ended December 31, 2017 as filed with the SEC on
February 1, 2018.
| Item 2. |
Unregistered Sales of Equity Securities and Use of Proceeds |
Recent Sales of Unregistered Securities
There were no sales of unregistered equity securities by the Company during the fiscal quarter ended September 30, 2018.
Issuer Purchases of Equity Securities
Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the
Exchange Act), adopted by the Company on May 1, 2018, 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 in value of shares have been purchased or, if sooner, on
May 1, 2019.
The Company may suspend or terminate this trading plan at any time, so long as the suspension or termination is made in
good faith and not as part of a plan or scheme to evade the prohibitions of Rule 10b-5 under the Exchange Act, or other applicable securities laws.
The following table shows information regarding repurchases by the Company of shares of its common stock pursuant to the trading plan for each month in the quarter ended September 30, 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 |
|
| 7/1/18 – 7/31/18 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
$ |
85,020 |
|
| 8/1/18 – 8/31/18 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
$ |
85,020 |
|
| 9/1/18 – 9/30/18 |
|
|
190 |
|
|
$ |
50.18 |
|
|
|
190 |
|
|
$ |
75,366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
190 |
|
|
$ |
50.18 |
|
|
|
190 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
| Item 5. |
Other Information |
On October 25, 2018, the Company issued a press release announcing its results of operations for the three- and nine-month periods ended September 30, 2018. The press release is furnished with
this Quarterly Report on Form 10-Q as Exhibit 99.1.
(a) Exhibits
|
|
|
|
|
| Exhibit No. |
|
Description of Exhibit |
|
Reference* |
|
|
|
| 4.1 |
|
Second Amended and Restated Credit Agreement dated July
25, 2018 among Unitil Corporation, Bank of America, N.A., as administrative agent, and the Lenders |
|
Exhibit 4.1 to Form 8-K dated July 25, 2018
(SEC File No. 1-8858) |
|
|
|
| 4.2 |
|
Amended and Restated Note issued to Bank of America, N.A. |
|
Exhibit 4.2 to Form 8-K dated July 25, 2018
(SEC File No. 1-8858) |
|
|
|
| 4.3 |
|
Amended and Restated Note issued to Citizens Bank, N.A. |
|
Exhibit 4.3 to Form 8-K dated July 25, 2018 (SEC File
No. 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 File
No. 1-8858) |
|
|
|
| 10.1 |
|
Second 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 File
No. 1-8858) |
|
|
|
| 10.2 |
|
Amended and Restated Form of Severance Agreement (Three-Year Term) |
|
Filed herewith |
|
|
|
| 10.3 |
|
Amended and Restated Form of Severance Agreement (Two-Year
Term) |
|
Exhibit 10.2 to Form 8-K dated July 25, 2018 (SEC File
No. 1-8858) |
|
|
|
| 10.4 |
|
Amended and Restated Form of Severance Agreement (Two-Year
Term; Non-Pension) |
|
Exhibit 10.3 to Form 8-K dated July 25, 2018 (SEC File
No. 1-8858) |
57
|
|
|
|
|
|
|
|
| 10.5 |
|
Amended 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) |
|
|
|
| 10.6 |
|
Amended and Restated Supplemental Executive Retirement Plan |
|
Exhibit 10.5 to Form 8-K dated July 25, 2018
(SEC File No. 1-8858) |
|
|
|
| 10.7 |
|
Unitil Corporation Deferred Compensation Plan |
|
Exhibit 10.6 to Form 8-K dated July 25, 2018
(SEC File No. 1-8858) |
|
|
|
| 11 |
|
Computation in Support of Earnings Per Weighted Average Common Share |
|
Filed herewith |
|
|
|
| 31.1 |
|
Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002 |
|
Filed herewith |
|
|
|
| 31.2 |
|
Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002 |
|
Filed herewith |
|
|
|
| 31.3 |
|
Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002 |
|
Filed herewith |
|
|
|
| 32.1 |
|
Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section
1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
Filed herewith |
|
|
|
| 99.1 |
|
Unitil Corporation Press Release Dated October 25, 2018 Announcing Earnings For the Quarter Ended September 30, 2018. |
|
Filed herewith |
|
|
|
| 101.INS |
|
XBRL Instance Document. |
|
Filed herewith |
|
|
|
| 101.SCH |
|
XBRL Taxonomy Extension Schema Document. |
|
Filed herewith |
|
|
|
| 101.CAL |
|
XBRL Taxonomy Extension Calculation Linkbase Document. |
|
Filed herewith |
|
|
|
| 101.DEF |
|
XBRL Taxonomy Extension Definition Linkbase Document |
|
Filed herewith |
58
|
|
|
|
|
|
|
|
| 101.LAB |
|
XBRL Taxonomy Extension Label Linkbase Document. |
|
Filed herewith |
|
|
|
| 101.PRE |
|
XBRL Taxonomy Extension Presentation Linkbase Document. |
|
Filed herewith |
| * |
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. |
59
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
|
|
|
|
|
|
|
|
|
UNITIL CORPORATION |
|
|
|
|
(Registrant) |
|
|
|
| Date: October 25, 2018 |
|
|
|
/s/ Mark H. Collin |
|
|
|
|
Mark H. Collin |
|
|
|
|
Chief Financial Officer |
|
|
|
| Date: October 25, 2018 |
|
|
|
/s/ Laurence M. Brock |
|
|
|
|
Laurence M. Brock |
|
|
|
|
Chief Accounting Officer |
60
