Commitments and Contingencies

12 Months Ended

Dec. 31, 2019

Note 8: Commitments and Contingencies

Regulatory Matters

Overview

—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing

distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms.

Most of Unitil’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers are entitled to purchase their natural gas supplies from third-party suppliers at this time. Most small and

medium-sized

customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted. The MDPU, the NHPUC and the MPUC have each continued to approve these reconciling rate mechanisms which allow Fitchburg, Unitil Energy and Northern Utilities to recover their actual wholesale energy costs for electric power and natural gas.

In connection with the implementation of retail choice, Unitil Power 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 and other restructuring-related regulatory assets. These assets have been principally recovered as of

December 31

, 2019

The remaining balance of these assets is

$0.6

million

as of

December 31

, 2019

, including $0.3

million recorded in

Current Assets as

Accrued Revenue

on the Company’s Consolidated Balance Sheet projected to be recovered in the next

year

and

$0.3

million

recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the

two years

. Unitil’s

distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

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%, effective January 1, 2018. Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, issued orders directing how the tax law changes were to be reflected in rates. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC issued a Notice of Proposed Rulemaking that would allow it to determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax reduction. This matter has been resolved for Granite State in its May 2, 2018 uncontested rate settlement filing, which accounted for the effect of the TCJA.

On November 21, 2019, the FERC issued Order No. 864, a final rule on Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes. The new rule requires public utilities with formula transmission rates to revise their formula rates to include a transparent methodology to address the impacts of the TCJA and future tax law changes on customer rates by accounting for “excess” or “deficient” Accumulated Deferred Income Taxes (ADIT). FERC also required transmission providers with stated rates to account for the ADIT impacts of the TCJA in their next rate case. The Company believes that compliance with the new rule will not have a material impact on its financial position, operating results, or cash flows.

Rate Case Activity

Northern Utilities—Base Rates—Maine—

On June 28, 2019, Northern Utilities filed a petition with the MPUC seeking an increase to annual base operating revenues of $7.0 million. If approved as filed, the requested increase will result in a 7% increase over the Company’s test-year operating revenues. The intended rate effective date is April 1, 2020. In addition, Northern Utilities is requesting approval to implement a multi-year alternative rate mechanism (“Capital Investment Recovery Adjustment” or “CIRA”) that will allow for future changes to the Company’s distribution rates and mitigate the need to file a general rate case. The CIRA is designed to recover the costs of replacing

and

relocating existing

facilities and other operational and safety-related system improvements. The first annual adjustment is proposed for November 1, 2020, to recover the Company’s 2019 investment cost of eligible facilities and improvements. This matter remains pending.

Northern Utilities—Targeted Infrastructure Replacement Adjustment (TIRA)—Maine—

The settlement in Northern Utilities’ Maine division’s 2013 rate case allowed the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP). In its Final Order issued on February 28, 2018 for Northern Utilities’ last base rate case, the MPUC approved an extension of the TIRA mechanism, for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. On May 7, 2018, the MPUC approved the Company’s request to increase its annual base rates by 2.4%, or $1.1 million, effective May 1, 2018, to recover the revenue requirements for 2017 eligible facilities. On April 17, 2019, the MPUC approved the Company’s request to increase its annual base rates by 2.1%, or $1.0 million, effective May 1, 2019, to recover the revenue requirements for 2018 eligible facilities.

Northern Utilities—Base Rates—New Hampshire—

On May 2, 2018, the NHPUC approved a settlement agreement providing for a net annual revenue increase of $3.2 million, incorporating the effect of the TCJA, and an initial step increase to recover post-test year capital investments. The Company’s second step increase of approximately $1.4 million of annual revenue was approved by the NHPUC, effective May 1, 2019, to recover eligible capital investments in 2018. According to the terms of the settlement agreement, Northern Utilities’ next distribution base rate case shall be based on an historic test year of no earlier than the twelve months ending December 31, 2020.

Unitil Energy—Base Rates—

On April 20, 2017 the NHPUC issued its final order providing for a permanent increase of $4.1 million, effective May 1, 2017, followed by two annual rate step adjustments to recover the revenue requirements associated with certain capital expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s first step increase, effective May 1, 2018. On April 22, 2019, the NHPUC approved Unitil Energy’s second and final step adjustment, providing for a revenue increase of approximately $340,000, effective May 1, 2019.

Fitchburg—Base Rates—Electric—

Fitchburg’s base rates are decoupled, and subject to an annual revenue decoupling adjustment mechanism, which includes a cap on the amount that rates may be increased in any year. In addition, Fitchburg has an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. On April 3, 2019, the

MDPU

approved Fitchburg’s cumulative revenue requirement associated with the Company’s 2015 and 2016 capital expenditures, an increase of $0.4 million. The increase was effective January 1, 2018. On November 1, 2018, Fitchburg filed its cumulative revenue requirement of $0.9 million associated with the Company’s 2015

2017 capital expenditures. On December 27, 2018, the filing was approved, effective January 1, 2019, subject to further investigation and reconciliation. Final approval of the 2018 filing remains pending.

On October 29, 2019, Fitchburg filed its cumulative revenue requirement of $1.1 million associated with the Company’s 2015-2018 capital expenditures. On December 16, 2019, the filing was approved, effective January 1, 2020, subject to further investigation and reconciliation. Final approval of the 2019 filing remains pending.

On December 17, 2019, Fitchburg filed for a $2.7 million increase in its electric base revenue decoupling target, which represents a 4.1% increase over 2018 test year operating electric revenues. The filing included

a request for an inflation-based Performance Base Ratemaking plan. By statute, the MDPU is afforded ten months to act on a request for a rate increase. A decision is expected by the end of October, 2020.

Fitchburg—Base Rates—Gas—

Pursuant to the Company’s revenue decoupling adjustment clause tariff, as approved in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target in order to mitigate economic, weather and energy efficiency impacts to the Company’s revenues. The MDPU has consistently found that the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that they result in just and reasonable rates. On December 17, 2019, Fitchburg filed for a $7.3 million increase in its gas base revenue decoupling target, which represents a 20.8% increase over 2018 test year total gas operating revenues. By statute, the MDPU is afforded ten months to act on a request for a rate increase. A decision is expected by the end of October, 2020.

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

(the “GSEP Filing”); and a filing, submitted on or before May

, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred (the “GREC Filing”). The Company considers these to be routine regulatory proceedings and there are no material issues outstanding.

In an Order issued on April 30, 2019, the MDPU approved Fitchburg’s 2018 GSEP Filing and increased the annual cap on recovery. Because the increase in the amount for recovery, $1.6 million, still exceeded the annual cap, the Order resulted in a revenue increase of $1.0 million that went into effect on May 1, 2019, subject to reconciliation. The amount that exceeded the cap, $0.6 million, has been deferred to be recovered in a later proceeding. On May 1, 2019, the Company made its 2019 GREC Filing, seeking a

waiver of the annual cap and a revenue increase of $1.0 million. The MDPU approved the Company’s request in its Order issued October 31, 2019.

Granite State—Base Rates—

On May 2, 2018, Granite State filed an uncontested rate settlement with

the

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

the

FERC on June 27, 2018, and complies with the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reductions under the TCJA.

Other Matters

Fitchburg—Independent Statewide Examination of the Safety of the Commonwealth’s Gas Distribution System

–

The MDPU has engaged a third-party evaluator to conduct an independent statewide examination of the safety of the gas distribution system to complement the investigation of the National Transportation Safety Board which focuses on the gas incident on September 13, 2018 in the Merrimack Valley and its potential causes. The evaluator will examine the following areas: (1) the physical integrity and safety of the gas distribution system; and (2) the operation and maintenance policies and practices of the gas companies and municipal gas companies, with respect to the Commonwealth’s gas distribution system, including recommendations for improvements. The evaluator issued a Phase 1 summary report including preliminary recommendations for the MDPU’s consideration on May 13, 2019. The investigation is

on-going

and the evaluator will produce a final report at the end of the process. The Company believes that this examination will not result in a material impact on its financial position, operating results or cash flows.

Northern Utilities / Granite State—Firm Capacity Contract

—Northern Utilities relies on the transport of gas supply over its affiliate Granite State pipeline to serve its customers in the Maine and New Hampshire service territories, as Granite State facilitates critical upstream interconnections with interstate pipelines and third party suppliers essential to Northern Utilities’ service to its customers. Northern Utilities reserves firm capacity through a contract with Granite State, which is renewed annually. Pursuant to statutory requirements in Maine as well as the orders of the MPUC, Northern Utilities submits an annual informational report requesting approval of a

one-year

extension of its

12-month

contract for firm pipeline capacity reservation, with an evergreen provision and three-month termination notification requirement. On July 11, 2019, the MPUC approved Northern Utilities’ request to extend its contract for firm transmission on its affiliate Granite State pipeline for another year, extending the current contract for the period of November 1, 2019 through October 31, 2020. The next request to the MPUC for approval to extend the transmission contract will be filed in April 2020. In New Hampshire, pursuant to statute, Northern Utilities advises the NHPUC of its annual contract renewal with Granite State, though it is not required to seek approval of the renewal.

Reconciliation Filings—

Fitchburg, Unitil Energy and Northern Utilities each have a number of regulatory reconciling accounts which require annual or semi-annual filings with the MDPU, NHPUC and MPUC, respectively, to reconcile costs and revenues and seek approval of any rate changes. These filings include: annual electric reconciliation filings by Fitchburg and Unitil Energy for a number of items, including default service, stranded cost changes and transmission charges; costs associated with energy efficiency programs in New Hampshire and Massachusetts, as directed by the NHPUC and MDPU;

recovery of the ongoing costs of storm repairs incurred by Unitil Energy; and the actual wholesale energy costs for electric power and natural gas incurred by each of the three companies. Fitchburg, Unitil Energy and Northern Utilities have been, and remain in full compliance with all directives and orders regarding these filings. The Company considers these to be routine regulatory proceedings and there are no material issues outstanding.

Fitchburg—Massachusetts RFPs—

Pursuant to a comprehensive energy law enacted in 2016, “An Act to Promote Energy Diversity,” under Section 83C, the Massachusetts electric distribution companies (EDCs), including Fitchburg, are required to jointly solicit proposals for long term contracts for at least 400 MW’s of offshore wind energy generation by June 30, 2017, as part of a total of 1,600 MW of offshore wind the EDCs are directed to procure by June 30, 2027. Under Section 83D of the Act, the EDCs are required to jointly seek proposals for cost effective clean energy (hydro, solar and land-based wind) long-

term contracts via one or more staggered solicitations for a total of 9,450,000 megawatt-hours by December 31, 2022. Unitil’s pro rata share of each of these contracts is approximately one percent.

The EDCs issued the RFP for Section 83D Long-Term Contracts for Qualified Clean Energy Projects in March 2017, and after selection of final projects and negotiation, final contracts for 9,554,940 MWh of Qualified Clean Energy and associated Environmental Attributes from hydroelectric generation were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the power purchase agreements, including the EDCs’ proposal to sell the energy procured under the contract into the

ISO-NE

wholesale market and to credit or charge the difference between the contract costs and the

ISO-NE

market costs to customers. The MDPU also determined that the EDCs’ request for remuneration equal to 2.75% is reasonable and in the public interest. Also, the MDPU approved the EDCs’ proposal to amend their respective tariffs to include the recovery of costs associated with the contracts. The Company believes that the power purchase obligations under these long-term contracts will have a material impact on the contractual obligations and regulatory assets of Fitchburg, once certain conditions and contingencies are met.

The EDCs issued the RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation in June 2017. Final selection of projects was made in May 2018, contracts were signed in July 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed two long-term contracts, each for 400MW of offshore wind energy generation with

the

MDPU for approval. On April 12, 2019, the MDPU approved the Offshore Wind Energy Generation power purchase agreements, including the EDCs’ proposal to sell the energy procured under the contract into the

ISO-NE

wholesale market and to credit or charge the difference between the contract costs and the

ISO-NE

, once certain conditions and contingencies are met

The EDCs issued an RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation on May 23, 2019. This is the second solicitation pursuant to Section 83C and with the

MDPU

’s approval of the Vineyard Wind contracts for 800 MW of offshore wind energy generation as a result of the first solicitation, the remaining obligation under 83C is to procure an additional 800 MW of offshore wind energy generation. The EDCs selected an 800 MW project submitted by Mayflower Wind and contracts are to be executed by January 10, 2020. A filing with the

MDPU

will follow.

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

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

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. On November

2019

the FERC issued an order in

EL14

-12

Midcontinent Independent System Operator ROE, in which FERC outlined a new methodology for calculating the ROE. On December

2019

in response to the FERC order in EL

-12

the New England Transmission Owners (NETOs) filed a motion to reopen the record and submitted a supplemental brief. Responses to that filing are due January

2020

Also pending at FERC is a Section 206 proceeding concerning the justness and reasonableness of

ISO-New

England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates. On August 17, 2018 a joint settlement agreement among a number of the parties was filed with the FERC. FERC rejected the settlement agreement on May 22, 2019 and remanded the proceeding to the Chief Administrative Law Judge to resume

hearing procedures. On May 24, 2019 the judge appointed a Dispute Resolution Facilitator to aid parties in settlement negotiations. The procedural schedule was suspended September 24, 2019 in order to allow participants to focus on settlement negotiations. On October 24, 2019, the NETO’s filed an unopposed motion to suspend the procedural schedule and waiver of answer period indicating that the NETO’s, Municipal PTF Owners and the Commission Trial Staff have reached agreement in principle on the terms of a settlement to resolve all open issues in the proceeding. 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.

Contractual Obligations

The table below lists the Company’s known specified gas and electric supply contractual obligations as of December 31, 2019.


			Payments Due by Period
Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2019	Total		2020		2021		2022		2023		2024		2025 & Beyond
Gas Supply Contracts	$	584.8	$	45.6	$	48.7	$	48.0	$	45.5	$	36.5	$	360.5
Electric Supply Contracts		14.2		2.0		1.2		1.2		1.2		1.2		7.4

Total	$	599.0	$	47.6	$	49.9	$	49.2	$	46.7	$	37.7	$	367.9

The Company and its subsidiaries have material energy supply commitments that are discussed in Note 7 to the accompanying Consolidated Financial Statements. Cash outlays for the purchase of electricity and natural gas to serve customers are subject to reconciling recovery through periodic changes in rates, with carrying charges on deferred balances. From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time. Rate recovery mechanisms are typically designed to collect the under-recovered cash or refund the over-collected cash over subsequent periods of less than a year.

Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types,

including those

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.

Environmental Matters

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 December 31, 2019, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. Based on the Company’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

Northern Utilities Manufactured Gas Plant Sites—

Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites, which were operated from the

mid-1800s

through the

mid-1900s.

In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough.

Northern Utilities has worked with the Maine Department of Environmental Protection and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have completed remediation activities at all sites; however, on site monitoring continues at several sites which may result in future remedial actions as directed by the applicable regulatory agency. In July 2019, the NH DES requested that Northern Utilities review modeled expectations for groundwater contaminants against observed data at the Rochester site. The results of the review, along with recommendations regarding remedial action, will be submitted to the NH DES in January 2020. While any recommendation is subject to approval by the NH DES, the Company has accrued $0.7 million for estimated costs to complete the remediation at the Rochester site, which is included in the Environmental Obligations table below.

The NHPUC and MPUC have approved regulatory mechanisms for the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding seven-year periods. For Northern Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five-year periods.

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

Fitchburg’s Manufactured Gas Plant Site—

Fitchburg has worked with the Massachusetts Department of Environmental Protection to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring will continue and it is possible that future activities may be required.

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 the current and long-term portions of the Company’s environmental obligations, which are included in Other Current Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s Consolidated Balance Sheets as of December 31, 2019 and 2018.

Environmental Obligations


	(millions)
	Fitchburg				Northern Utilities				Total
	2019		2018		2019		2018		2019		2018
Total Balance at Beginning of Period	$	—	$	0.1	$	2.0	$	2.0	$	2.0	$	2.1
Additions		—		—		0.9		0.3		0.9		0.3
Less: Payments / Reductions		—		0.1		0.2		0.3		0.2		0.4

Total Balance at End of Period	$	—	$	—	$	2.7	$	2.0	$	2.7	$	2.0

Less: Current Portion		—		—		0.6		0.6		0.6		0.6

Noncurrent Balance at December 31,	$	—	$	—	$	2.1	$	1.4	$	2.1	$	1.4