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Commitments and Contingencies | 12 Months Ended
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Dec. 31, 2016
Commitments and Contingencies | 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, 2016. The remaining balance of these assets is $1.6 million as of December 31, 2016, 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 $1.3 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the next five 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. Rate Case Activity Unitil Energy—Base Rates—On April 29, 2016 Unitil Energy filed for an increase in distribution base rates with the New Hampshire Public Utilities Commission (NHPUC). The Company’s filing seeks an increase in base rates of approximately $6.3 million or 3.6 percent above present rates. The Company also requested a long-term rate plan for the annual recovery in future years of the costs associated with utility plant additions. On June 28, 2016 the NHPUC approved a settlement agreement between the Company, Commission Staff and the Office of Consumer Advocate on a $2.4 million temporary rate increase effective July 1, 2016. The temporary rate increase will remain in effect until a permanent rate increase decision is issued. Once a permanent rate is decided, it will be reconciled back to the effective date of the temporary rate increase. The Company is currently engaged in settlement discussions with the Commission and the Office of the Consumer Advocate on the remaining issues in the rate case. Any settlement in the rate case or additional investigation and litigation is expected to be completed for final approval by NHPUC by the end of April, 2017. Fitchburg—Base Rates—Electric—On April 29, 2016 the Massachusetts Department of Public Utilities (MDPU) issued an order approving a $2.1 million increase in Fitchburg’s electric base revenue decoupling target, effective May 1, 2016. The MDPU also approved a capital cost recovery mechanism, providing for annual adjustments to target revenues to account for capital spending. In 2016, Fitchburg made its first capital cost adjustment filing documenting its capital investments for calendar year 2015 and requesting $0.5 million of the associated revenue requirements for recovery beginning January 1, 2017. On December 27, 2016 the MDPU approved this filing subject to further investigation and reconciliation. Fitchburg—Base Rates—Gas—On April 29, 2016, the MDPU issued an order approving a $1.6 million increase in Fitchburg’s gas base revenue decoupling target, effective May 1, 2016. Fitchburg—Gas Operations—On October 31, 2015, Fitchburg submitted its second annual filing to recover the estimated costs to be incurred in 2016 under its approved 20 year gas system enhancement plan program. The program was established pursuant to legislation that provided for the establishment of comprehensive replacement programs to address aging natural gas pipeline infrastructure. Effective May 1, 2016, the MDPU approved the Company’s request to collect in rates $0.9 million for the estimated costs of its cumulative capital investments in the program through the end of 2016. On October 31, 2016, Fitchburg submitted its third annual filing to recover the estimated cost to be incurred in 2017 under the gas system enhancement plan program, seeking approval to collect an additional $0.9 million to recover the cumulative cost of investments in the program through the end of 2017. In addition, the Company seeks a waiver of the 1.5 percent cap on annual changes in the revenue requirement eligible for recovery. The MDPU’s decision on this request is pending and is expected by the end of April, 2017, for rates effective May 1, 2017. Northern Utilities—Base Rates—Maine—The rate case settlement in Northern Utilities’ Maine division’s last rate case allowed the Company to implement a Targeted Infrastructure Replacement Adjustment (TIRA) rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects. The TIRA has an initial term of four years and covers targeted capital expenditures in 2013 through 2016. The 2016 TIRA, for 2015 expenditures, was filed on February 29, 2016, and provides for an annual increase in distribution base revenue of $1.5 million, effective May 1, 2016, and was approved by the MPUC on April 28, 2016. Northern Utilities—Targeted Area Build-out Program—Maine—On December 22, 2015 the MPUC approved a new Targeted Area Build-out 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 and is being initially piloted in the City of Saco. 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. This pilot program is planned to be built out over the next three years and has the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco pilot area. The Company will continue to evaluate the success of the program and ways to economically reach new targeted service areas. Northern Utilities—Base Rates—New Hampshire—Northern Utilities’ New Hampshire division’s last rate case resulted in a settlement agreement providing for an increase of $4.6 million in distribution base revenue and an additional step increase in revenue of $1.4 million for investments in gas mains extensions and infrastructure replacement projects, effective May 1, 2014, and a step adjustment that provided for an annual increase of $1.8 million in revenue effective May 1, 2015. Northern Utilities—Pipeline Refund—On February 19, 2015, the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers. In New Hampshire, the refund is being credited to all customers over a three year period as directed by the NHPUC. In Maine, the refund has been divided into two parts, as directed by the MPUC. Maine retail customers who purchase their gas directly from Northern Utilities are being credited their portion of the refund over a three year period. The second part of the refund was paid on October 5, 2015 as a one-time lump sum payment directly to marketers who transport gas on Northern Utilities’ distribution system. The Company has recorded current and noncurrent Regulatory Liabilities related to these refunds of $4.4 million and $2.4 million, respectively, on its Consolidated Balance Sheets as of December 31, 2016. Granite State—Base Rates—Granite State has in place a FERC-approved second amended settlement agreement under which it is permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a specific cost cap. On June 24, 2016 Granite State filed for an annual revenue and rate increase under this provision of $0.3 million, effective August 1, 2016. This filing was approved by the FERC on July 13, 2016. Other Matters NHPUC Energy Efficiency Resource Standard Proceeding—In May 2015, the NHPUC opened a proceeding to establish 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. On April 27, 2016, a comprehensive settlement agreement was filed by the parties, including Unitil Energy and Northern Utilities, which was approved by the NHPUC on August 2, 2016. The settlement provides for: extending the 2014-2016 Core program an additional year (through 2017); establishing an EERS; establishing a recovery mechanism to compensate the utilities for lost-revenue related to the EERS programs; and approving the performance incentives and processes for stakeholder involvement, evaluation, measurement and verification, and oversight of the EERS programs. 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 has engaged a consultant to direct a Working Group to investigate these issues and to prepare a final report with recommendations for the Commission. The report is expected to be filed in early 2017. Unitil Energy is an active participant in the Working Group. 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 legislation requires that a decision on this matter must be issued by the NHPUC by March 2, 2017. The NHPUC approved an extension of the current net metering tariffs on an interim basis until it issues its final decision on June 2, 2017. Unitil Energy is an active participant in this proceeding. Fitchburg—Electric Operations—On November 17, 2016, Fitchburg submitted its 2016 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were given final approval by the MDPU on December 29, 2016, effective January 1, 2017. Fitchburg—Service Quality—On March 1, 2016, Fitchburg submitted its 2015 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. Fitchburg’s annual gas and electric divisions’ Service Quality Reports for the periods up through 2014 have all been approved by the MDPU. On September 30, 2016 the MDPU approved Fitchburg’s 2015 electric division Service Quality Report as filed, and on November 22, 2016 the MDPU approved Fitchburg’s 2015 gas division Service Quality Report. In December 2015, the MDPU issued its final order adopting new and revised Service Quality Guidelines. The Company has generally been able to meet or exceed the performance metrics of the previous Service Quality Guidelines and believes that it will continue to meet or exceed the performance metrics under the new and revised Guidelines. Fitchburg—Solar Generation—On August 19, 2016, Fitchburg filed a petition with the MDPU seeking approval to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts. The proposal includes a cost recovery mechanism that would share the costs and benefits of the project among all Fitchburg customers. On October 27, 2016 a Settlement Agreement supporting the proposal was reached between the Company, the Attorney General of Massachusetts, and the Low-Income Weatherization and Fuel Assistance Program Network. The Settlement Agreement was approved by the MDPU on November 9, 2016. Construction of the solar generating facility is expected to be completed by the end of November 2017. Fitchburg—Energy Diversity—Governor Baker signed into law H4568 “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) 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 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. 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 and joint evaluation activities are ongoing. Selection of contracts concluded during the fourth quarter of 2016 and contract negotiations are underway for several proposed projects. Fitchburg’s final contracts will be subject to review and approval of the MDPU. Fitchburg—Other—On September 23, 2016, the Massachusetts Department of Energy Resources (“DOER”) presented its Solar Incentive Straw Proposal in accordance with Chapter 75 of the Acts of 2016 which directed the DOER to develop a statewide solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers throughout the commonwealth. The program would replace the state’s expiring solar incentive program, which uses solar renewable energy credits (“SRECs”) and is known as SREC-2, with a tariff program. The tariff would provide for incentive payments which would be net of energy value (i.e., total tariff rate minus value of energy). The program also includes a variety of tariff adders, including incentives for location, such as landfill site, for off-takers, such as a community aggregation program, and for other technologies, such as behind-the-meter storage. Cost recovery of tariff payments and administrative costs may be made through a fixed, non-bypassable monthly charge to all distribution customers. Comments on the straw proposal were filed on October 28, 2016. The DOER’s implementation schedule includes filing emergency regulations, conducting a rulemaking during winter 2017 to permanently promulgate emergency regulation, MDPU review of model tariffs in spring 2017, and final program implementation in summer 2017. On May 11, 2016, the MDPU issued an Order commencing a rulemaking proceeding to adopt emergency regulations amending 220 C.M.R. § 18.00 et seq. (“Net Metering Regulations”). Specifically, the MDPU amended its Net Metering Regulations to implement the net metering provisions of An Act Relative to Solar Energy, St. 2016, c. 75, §§ 3-9, and to make additional clerical changes to the Net Metering Regulations. On July 15, 2016, the MDPU issued an order approving Final Net Metering Regulations. The distribution companies were required to submit draft net metering tariffs to comply with the new regulations, which they did on September 1, 2016. On January 6, 2017, the MDPU approved the model tariff and ordered the utilities to file compliance tariffs on January 20, 2017. This matter remains pending. On August 23, 2016 the MDPU held a technical session to discuss its straw proposal for a monthly minimum reliability contribution (“MMRC”). The purpose of the MMRC is for all distribution company customers to contribute to the fixed costs that ensure the reliability, proper maintenance, and safety of the electric distribution system. Parties in the proceeding filed alternative proposals on October 11, 2016. On January 13, 2017, the MDPU issued an order noting that no consensus was reached with respect to its straw proposal. The MDPU stated that it has the authority to consider proposals for an MMRC and sets limitations on when and how it may approve such a proposal, and that it is each distribution company’s discretion whether to file an MMRC proposal and what such a proposal would include. In December 2013, the MDPU opened an investigation into Modernization of the Electric Grid. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices.” In June 2014, the MDPU issued its first Grid Modernization order, setting forth a requirement that each electric distribution company submit a ten-year strategic Grid Modernization Plan (GMP). As part of the GMP, each company must include a five-year Short-Term Investment Plan (STIP), which must include an approach to achieving advanced metering functionality within five years of the Department’s approval of the GMP. The filing of a GMP is a recurring obligation and must be updated as part of subsequent base distribution rate cases, which by statute must occur no less often than every five years. Capital investments contained in the STIP are eligible for pre-authorization, meaning that the MDPU will not revisit in later filings whether the Company should have proceeded with these investments. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015. These filings are currently under MDPU review and remain pending. On January 28, 2016 the MDPU approved Fitchburg’s Three-Year Energy Efficiency Plan for 2016-2018, subject to limited modifications and directives in the Order. The Department found that the savings goals included in each Three-Year Plan are reasonable and are consistent with the achievement of all available cost-effective energy efficiency; approved each Program Administrator’s program implementation cost budget for the Three-Year Plans; approved the performance incentive pool, mechanism, and payout rates; found that all proposed energy efficiency programs are cost-effective; found that funding sources are reasonable and that each Program Administrator may recover the funds to implement its energy efficiency plan through its EES; and found that each Program Administrator’s Three-Year Plan is consistent with the Green Communities Act, the Guidelines, and Department precedent. FERC Transmission Formula Rate Proceeding—On December 28, 2015, FERC issued an order, pursuant to Section 206 of the Federal Power Act, instituting a 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. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that this proceeding results in any changes to the rates being charged, a refund period will begin retroactive to January 4, 2016. The Company does not believe this investigation 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 (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The 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 that this suit is without merit and will continue to defend itself vigorously. The Town of Lunenburg filed a separate action in the Court arising out of the December 2008 ice storm. The Court granted the Company’s Motion for Summary Judgment on all counts in December 2016 and dismissed the Town’s complaint. The Court’s decision remains subject to a potential motion for reconsideration and appeal. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these suits 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, 2016, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, we 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 (ME DEP) and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Dover, Somersworth, Portsmouth, Lewiston, Portland and Scarborough sites, though on site monitoring continues and it is possible that future activities may be required. In December 2016, the ME DEP issued a Certificate of Completion for the Portland remediation activities completed in early 2016. Pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the Portland site will be primarily the responsibility of the State of Maine. 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 (MA DEP) 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 years ended December 31, 2016 and 2015. Environmental Obligations
|  | (millions) |
|  | Fitchburg |  |  | Northern Utilities |  |  | Total |
|  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |
Total Balance at Beginning of Period |  | $ | 1.2 |  |  | $ | 1.9 |  |  | $ | 1.6 |  |  | $ | 3.6 |  |  | $ | 2.8 |  |  | $ | 5.5 |
Additions |  |  | — |  |  |  | — |  |  |  | 1.8 |  |  |  | 2.9 |  |  |  | 1.8 |  |  |  | 2.9 |
Less: Payments / Reductions |  |  | 1.1 |  |  |  | 0.7 |  |  |  | 1.6 |  |  |  | 4.9 |  |  |  | 2.7 |  |  |  | 5.6 |
Total Balance at End of Period |  | $ | 0.1 |  |  | $ | 1.2 |  |  | $ | 1.8 |  |  | $ | 1.6 |  |  | $ | 1.9 |  |  | $ | 2.8 |
Less: Current Portion |  |  | 0.1 |  |  |  | 0.2 |  |  |  | 0.3 |  |  |  | 1.1 |  |  |  | 0.4 |  |  |  | 1.3 |
Noncurrent Balance at December 31, |  | $ | — |  |  | $ | 1.0 |  |  | $ | 1.5 |  |  | $ | 0.5 |  |  | $ | 1.5 |  |  | $ | 1.5 |

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