5 ·Commitments and contingencies

Utility projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income.

In May 2011, the PUC ordered independently conducted regulatory audits on the reasonableness of costs incurred for HECO’s East Oahu Transmission Project (EOTP), Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, and Customer Information System (CIS) project. However, in March 2012, the PUC eliminated the requirement for a regulatory audit for the EOTP Phase I in connection with an approved settlement of the EOTP Phase I project cost issues and, in March 2013, the PUC eliminated the requirement for an audit of the CIP CT-1 and CIS project costs as described below.

On January 28, 2013, HECO and its subsidiaries and the Consumer Advocate, signed a settlement agreement (2013 Agreement), subject to PUC approval, to write-off $40 million of costs in lieu of conducting the regulatory audits of the CIP CT-1 project and the CIS project. Based on the 2013 Agreement, as of December 31, 2012, the utilities recorded an after-tax charge to net income of approximately $24 million—$17.1 million for HECO, $3.4 million for HELCO, and $3.2 million for MECO. The remaining recoverable costs of $52 million were included in rate base as of December 31, 2012.

As part of the 2013 Agreement, HELCO would withdraw its 2013 test year rate case, and delay filing a new rate case until a 2016 test year. Additionally, HECO would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. For both utilities, the existing terms of the last rate case decisions would continue. HECO would also be allowed to record Revenue Adjustment Mechanism (RAM) revenues starting on January 1 of 2014, 2015 and 2016. The cash collection of RAM revenues would remain unchanged, starting June 1 of each year through May 31 of the following year.

On March 19, 2013, the PUC issued a decision and order (2013 D&O) approving the 2013 Agreement, with the following clarifications, none of which changed the financial impact recorded as of December 31, 2012: (1) the PUC reiterated its authority to examine and ascertain what post go-live CIS costs would be subject to regulatory review in future rate cases; (2) the PUC discouraged requesting single issue cost deferral accounting and/or cost recovery mechanisms during the period of rate case deferral by HECO and HELCO; (3) the PUC approved the agreed-upon recovery of CIP CT-1 and CIS project costs through the RAM, as set forth in the 2013 Agreement, however not setting a precedent for future projects; and (4) the PUC reaffirmed its right to rule on the substance of the MECO 2012 test year rate case in its ongoing rate case proceeding. On May 31, 2013, the PUC issued a final D&O in the MECO 2012 test year rate case. See “MECO 2012 test year rate case” below.

Renewable energy projects. HECO and its subsidiaries are committed to achieving or exceeding the State’s Renewable Portfolio Standard (RPS) goal of 40% renewable energy by 2030 and to meeting their commitments relating to decreasing the State’s dependence on imported fossil fuels under their 2008 Energy Agreement with the Governor, the State Department of Business, Economic Development and Tourism and the Consumer Advocate (Energy Agreement). The utilities continue to evaluate and pursue opportunities with developers of proposed projects to integrate power into its grid from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave, geothermal and others. In December 2009, the PUC allowed HECO to defer the costs of studies for the large wind project for later review of prudence and reasonableness. In April 2013, the PUC approved the recovery of $3.9 million in costs for stage 1 studies for the large wind project over a three-year period, with carrying costs to be accrued over the recovery period at the rate of 1.75% per annum, through the Renewable Energy Infrastructure Program (REIP) Surcharge.

In November 2011, HECO and MECO filed their application to seek PUC approval to defer for later recovery approximately $555,000 (split evenly between HECO and MECO) also through the REIP surcharge for additional studies to determine the value proposition of interconnecting the islands of Oahu and of Maui County (Maui, Lanai, and Molokai) and if doing so would be operationally beneficial and cost-effective. In August 2012, the PUC allowed HECO and MECO to defer the outside service costs for the additional studies for later review of prudence and reasonableness. The specific amount to be recovered, as well as the recovery mechanism and the terms of the recovery mechanism, were to be determined at a later date.

A revised draft Request for Proposals (RFP) for 200 MW or more of renewable energy to be delivered to Oahu from any of the Hawaiian Islands was posted on HECO’s website prior to the issuance of a proposed final RFP. In February 2012, the PUC granted HECO’s request for deferred accounting treatment for the inter-island project support costs. The amount of the deferred costs was limited to $5.89 million. On July 11, 2013, the PUC issued orders related to the 200 MW RFP. First, it issued an order that HECO shall amend its current draft of the Oahu 200 MW RFP to remove references to the Lanai Wind Project, eliminate solicitations for an undersea transmission cable, and amend the draft RFP to reflect other guidance provided in the order. Second, it initiated an investigative proceeding to review the progress of the Lanai Wind Project stating that there was an uncertainty whether the project developer retained an equivalent ability to develop the project as when it submitted its bid in 2008 and its term sheet in 2011. The PUC also stated that it will review the PPA (if one is completed) and, as part of that process, determine whether the Lanai Wind Project should be developed taking into account potential as-available renewable energy projects and grid infrastructure options. The PUC stated it intends to evaluate the project as a combined resources proposal (i.e., wind project and generation tie transmission cable between the islands of Oahu and Lanai). Third, it initiated a proceeding to solicit information and evaluate whether an interisland grid interconnection transmission system between the islands of Oahu and Maui is in the public interest, given the potential for large-scale wind and solar projects on Maui.

In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50 MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii, and in July 2012, HELCO filed an application to defer 2012 costs related to the Geothermal RFP. In February 2013, HELCO issued the Final Geothermal RFP. Six bids were received in April 2013 and are being evaluated.

In June 2013, HECO filed an application to seek PUC approval of Waivers from the Framework for Competitive Bidding for five projects (4 photovoltaic and 1 wind) selected as part of HECO’s “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding.”

Environmental regulation. HECO and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. In recent years, legislative, regulatory and governmental activities related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.

On April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at HECO’s power plants on the island of Oahu. If adopted as proposed, management believes the proposed regulations would require significant capital and annual other operation and maintenance (O&M) expenditures. On June 11, 2012, the EPA published additional information on the section 316(b) rule making that indicates that the EPA is considering establishing lower cost compliance alternatives in the final rule. The EPA has delayed issuance of the final section 316(b) rule until November 2013.

On February 16, 2012, the Federal Register published the EPA’s final rule establishing the EPA’s National Emission Standards for Hazardous Air Pollutants for fossil fuel-fired steam electrical generating units (EGUs). The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at HECO’s power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Based on a review of the final rule and the benefits and costs of alternative compliance strategies, HECO has selected a MATS compliance strategy based on switching to lower emission fuels. The use of lower emission fuels will provide for MATS compliance at lower overall costs and avoid the reduction in operational flexibility imposed by emissions control equipment. As provided in the MATS regulations, HECO will be requesting a one-year extension resulting in a MATS compliance date of April 16, 2016. On February 6, 2013, the EPA issued a guidance document titled “Next Steps for Area Designations and Implementation of the Sulfur Dioxide National Ambient Air Quality Standard,” which outlines a process that will provide the states additional flexibility and time for their development of one-hour sulfur dioxide NAAQS implementation plans. HECO will work with the Hawaii Department of Health (DOH) and the EPA in the rulemaking process for these implementation plans to insure development of cost-effective strategies for NAAQS compliance. Based on the February 6, 2013 EPA guidance document, current estimates of the compliance date for the one-hour sulfur dioxide NAAQS is in the 2022 or later timeframe.

Depending upon the final outcome of the CWA 316(b) regulations, the specific measures required for MATS compliance, and the rules and guidance developed for implementation of more stringent National Ambient Air Quality Standards, HECO and its subsidiaries may be required to incur material capital expenditures and other compliance costs, but such amounts are not determinable at this time. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire or deactivate certain generating units earlier than anticipated.

HECO, HELCO and MECO, like other utilities, periodically experience petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. HECO and its subsidiaries believe the costs of responding to such releases identified to date will not have a material adverse effect, individually or in the aggregate, on HECO’s consolidated results of operations, financial condition or liquidity.

Potential Clean Air Act Enforcement. On July 1, 2013, HELCO and MECO received a letter from the U.S. Department of Justice (DOJ) asserting potential violations of the Prevention of Significant Deterioration (PSD) and Title V requirements of the Clean Air Act involving the Hill and Kahului Power Plants. The EPA referred the matter to the DOJ for enforcement based on HELCO’s and MECO’s responses to information requests in 2010 and 2012. The letter expresses an interest in resolving the matter without the issuance of a notice of violation, and invites HELCO and MECO to engage in settlement negotiations. HELCO and MECO are in contact with the DOJ to seek additional information and to begin making arrangements for settlement discussions. HELCO and MECO cannot currently estimate the amount or effect of a settlement, if any. Neither HELCO nor MECO has identified at this time any projects or work relating to the information requests that may have been noncompliant with PSD or Title V requirements, and continue to investigate the potential bases for the DOJ’s claims.

Former Molokai Electric Company generation site. In 1989, MECO acquired by merger Molokai Electric Company. Molokai Electric Company had sold its former generation site (Site) in 1983, but continued to operate at the Site under a lease until 1985. The EPA has since performed Brownfield assessments of the Site that identified environmental impacts in the subsurface. Although MECO never operated at the Site and operations there had stopped four years before the merger, in discussions with the EPA and the DOH, MECO agreed to undertake additional investigations at the Site and an adjacent parcel that Molokai Electric Company had used for equipment storage (the Adjacent Parcel) to determine the extent of impacts of subsurface contaminants. A 2011 assessment by a MECO contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, MECO is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, fuel oils, and other subsurface contaminants. In March 2012, MECO accrued an additional $3.1 million (reserve balance of $3.6 million as of June 30, 2013) for the additional investigation and estimated cleanup costs at the Site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation. A revised draft site investigation work plan for site characterization was submitted to the DOH and EPA in June 2013.

Global climate change and greenhouse gas emissions reduction. National and international concern about climate change and the contribution of GHG emissions (including carbon dioxide emissions from the combustion of fossil fuels) to global warming have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions.

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. The electric utilities participated in a Task Force established under Act 234, which was charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as those being implemented under the Energy Agreement. On October 19, 2012, the DOH posted the proposed regulations required by Act 234 for public hearing and comment. In general, the proposed regulations would require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce GHG emissions by 25% below 2010 emission levels by 2020. The proposed regulations also assess affected sources an annual fee based on tons per year of GHG emissions, beginning with emissions in calendar year 2012. The proposed DOH GHG rule also tracks the federal “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule, see below) and would create new thresholds for GHG emissions from new and existing stationary source facilities. HECO submitted comments on the proposed regulations in January 2013. HECO continues to monitor this rulemaking proceeding and will participate in the further development of the regulations.

Several approaches (e.g., “cap and trade”) to GHG emission reduction have been either introduced or discussed in the U.S. Congress; however, no federal legislation has yet been enacted.

On September 22, 2009, the EPA issued its Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions. The utilities have submitted the required reports for 2010, 2011 and 2012 to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, the EPA has also issued rules that begin to address GHG emissions from stationary sources, like the utilities’ EGUs.

In June 2010, the EPA issued its GHG Tailoring Rule. Effective January 2, 2011, under the Prevention of Significant Deterioration program, permitting of new or modified stationary sources that have the potential to emit GHGs in greater quantities than the thresholds in the GHG Tailoring Rule will entail GHG emissions evaluation, analysis and, potentially, control requirements. On March 27, 2012, the Federal Register published the EPA’s proposed New Source Performance Standard regulating carbon dioxide emissions from affected new fossil fuel-fired generating units. As proposed, the rule does not apply to non-continental units (i.e., in Hawaii and U.S. Territories) and therefore does not apply to the utilities. On June 25, 2013, President Obama directed the EPA Administrator to issue a new proposal no later than September 20, 2013. In addition, the President directed the Administrator to issue proposed standards, regulations, or guidelines for GHG emissions from existing power plants by no later than June 1, 2014, and final standards no later than June 1, 2015. HECO will participate in the federal GHG rulemaking process and support an exclusion for both new and existing non-continental sources.

HECO and its subsidiaries have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including, but not limited to, supporting DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, burning renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected MECO generating units, and testing biofuel blends in other HECO and MECO generating units. The utilities are also working with the State of Hawaii and other entities to pursue the use of liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used. Management is unable to evaluate the ultimate impact on the utilities’ operations of eventual comprehensive GHG regulation. However, management believes that the various initiatives it is undertaking will provide a sound basis for managing the electric utilities’ carbon footprint and meeting GHG reduction goals that will ultimately emerge.

While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate change on the weather (for example, floods or hurricanes), sea levels, and water availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquidity of the electric utilities. For example, severe weather could cause significant harm to the electric utilities’ physical facilities.

MECO 2012 test year rate case. On May 31, 2013, the PUC issued a final D&O in the MECO 2012 test year rate case. Final rates became effective August 1, 2013. The final D&O approved an increase in annual revenues of $5.3 million, which is $7.8 million less than the interim increase that had been in effect since June 1, 2012. Reductions from the interim D&O relate primarily to:

(in millions)
Lower ROACE	$	4.0
Customer Information System expenses	0.3
Pension and OPEB expense based on 3-year average	1.5
Integrated resource planning expenses	0.9
Operational and Renewable Energy Integration study costs	1.1
Total adjustment	$	7.8

According to the PUC, the reduction in the allowed ROACE from the stipulated 10% to the final approved 9% is composed of 0.5% allocation due to updated economic and financial market conditions manifested in lower interest rates in the 2012 test year and 0.5% for system inefficiencies reflected in over curtailment of renewable energy produced by independent power producers.

The PUC found that the record did not sufficiently support the normalization of 2013 and 2014 Customer Information System costs into the 2012 test year and ordered a downward adjustment to remove these costs from the test year.

The reduction in the pension and OPEB expense is due to applying a three-year average in the calculation of pension costs for the purpose of the 2012 test year. This is not a PUC decision to change the pension and OPEB tracking mechanisms, although the PUC emphasizes the need to evaluate alternatives to decrease or limit the growth in employee benefits costs.

The PUC removed integrated resource planning (IRP) expenses from the test year as it could not determine whether these expenses have been reasonably incurred for the 2012 test year as required by the PUC’s IRP Framework and stated that it will determine the appropriate level and method of cost recovery for MECO’s IRP expenses in the pending IRP proceeding.

The PUC reduced operational and renewable energy integration study costs because of the uncertainty regarding the scope of work and actual costs of these studies.

The PUC also continued MECO’s existing energy cost adjustment clause (ECAC) and power purchase adjustment clause (PPAC) design. The PUC stated that it will consider HECO, HELCO and MECO’s future actions to reduce fuel costs and increase use of renewable energy as it continues to review the design of the ECAC in the future.

On June 12, 2013, MECO filed a motion for partial reconsideration and partial clarification of the final D&O in the MECO 2012 test year rate case. The motion primarily requested reconsideration of the findings and conclusions concerning MECO’s 9% ROACE for the test year and also addressed other matters identified in the D&O, including treatment of IRP costs pending PUC determinations on such costs in a separate IRP proceeding. MECO requested a panel evidentiary hearing on ROACE, curtailment and technical studies, and pension expense. MECO also requested to partially stay the implementation of the final D&O, pending the presentation at the evidentiary hearing on its motion for partial reconsideration of the final D&O related to the ROACE reduction from 10.0% to 9.0% and the PUC’s final decision following the hearing. On July 2, 2013, the PUC issued an order denying MECO’s requests for an evidentiary hearing and for partial reconsideration, and dismissed MECO’s motion for partial stay. The order granted MECO’s motion for partial clarification to allow MECO to defer IRP costs incurred since June 2012, which through June 30, 2013 totaled approximately $0.7 million, until the level of costs are determined and a method of recovery is decided in the IRP proceeding.

Since the final rate increase was lower than the interim increase previously in effect, MECO recorded a charge, net of revenue taxes, of $7.6 million in the second quarter and will be refunding to customers approximately $9.7 million (which includes interest accrued since June 1, 2012) between September 2013 and October 2013. As a result of the D&O, in the second quarter MECO also recorded adjustments to reduce expenses by reducing employee benefits expenses by $1.8 million for adjustments to pension and OPEB costs, and to reclassify $0.7 million of IRP costs to deferred accounts.

As directed by the PUC, in June 2013, MECO filed documentation regarding the re-setting of its target heat rate to take into account the operation of the Auwahi wind farm and made its curtailment information available to the public on its website. In addition, as required by the final D&O, MECO will be filing by September 3, 2013, a System Improvement and Curtailment Reduction Plan. Management cannot predict any actions by the PUC as a result of these filings.

Asset retirement obligations. Asset retirement obligations (AROs) represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. HECO and its subsidiaries’ recognition of AROs have no impact on their earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by HECO and its subsidiaries relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.

Changes to the ARO liability included in “Other liabilities” on HECO’s balance sheet were as follows:

	Six months ended June 30
(in thousands)	2013			2012
Balance, beginning of period	$	48,431		$	50,871
Accretion expense	363			862
Liabilities incurred	—			—
Liabilities settled	(1,506		)	(2,217		)
Revisions in estimated cash flows	(916		)	—
Balance, end of period	$	46,372		$	49,516