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Commitments and contingencies - HECO | 6 Months Ended
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Jun. 30, 2012
Commitments and contingencies |
9 · Commitments and contingencies See Note 4, “Bank subsidiary,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements,” below.
Hawaiian Electric Company, Inc. and Subsidiaries |
Commitments and contingencies |
5 · Commitments and contingencies Hawaii Clean Energy Initiative. In January 2008, the State of Hawaii (State) and the U.S. Department of Energy signed a memorandum of understanding establishing the Hawaii Clean Energy Initiative (HCEI). In October 2008, the Governor of the State, the State Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the State Department of Commerce and Consumer Affairs, and HECO, on behalf of itself and its subsidiaries, HELCO and MECO (collectively, the parties), signed an agreement setting forth goals and objectives under the HCEI and the related commitments of the parties (the Energy Agreement), including pursuing a wide range of actions to decrease the State’s dependence on imported fossil fuels through substantial increases in renewable energy and programs intended to secure greater energy efficiency and conservation. Many of the actions and programs included in the Energy Agreement require approval of the PUC. Renewable energy projects. HECO and its subsidiaries continue to negotiate 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 and others. This includes HECO’s plan to integrate wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from a windfarm proposed to be built on the island of Lanai. 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, and HECO is now seeking PUC approval to recover the deferred costs totaling $3.9 million for the Stage 1 studies through the 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. Decisions from the PUC are still pending. In October 2011, HECO filed with the PUC a draft Request for Proposal (RFP) for 200 MW or more of renewable energy to be delivered to Oahu from any of the Hawaiian islands. 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. In May 2012, the PUC instituted a proceeding for a competitive bidding process for 50 MW of dispatchable renewable geothermal firm capacity generation on the island of Hawaii, and in July 2012, HELCO filed an application to defer costs related to the geothermal firm dispatchable capacity RFPs. Interim increases. As of June 30, 2012, HECO and its subsidiaries had recognized $1 million of revenues with respect to interim orders related to general rate increase requests. Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, if they exceed amounts allowed in a final order. Major 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. Significant projects whose costs (or costs in excess of estimates) have not yet been allowed in rate base by a final PUC order include those described below. 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. In July 2011, the PUC allowed HECO to defer the portion of costs that are in excess of the prior PUC approved amounts and related depreciation for HECO’s EOTP Phase 1 ($43 million) and the CIP CT-1 project ($32 million) until completion of independently conducted regulatory audits. The PUC also approved the accrual of a carrying charge on the cost of such projects not yet included in rates and the related depreciation expense, from July 1, 2011 until the regulatory audits are completed and allowed the remaining project costs that were not deferred to be included in electric rates. For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is allowed in electric rates. Subsequently, in February 2012 and May 2012, the PUC granted HECO’s and MECO’s requests, respectively, to defer CIS project operation and maintenance expenses (limited to $2.3 million per year in 2011 and 2012 for HECO and limited to $0.6 million in 2012 for MECO) that are to be subject to a regulatory audit. The PUC also allowed them to accrue AFUDC on project costs (including deferred operation and maintenance expenses) until the completion of the regulatory audit and begin amortization of such costs when the amortization is included in rates. HELCO anticipates submitting a similar deferral request, but has not yet deferred any CIS project operation and maintenance costs. The PUC has eliminated the requirement for a regulatory audit for the EOTP Phase I (see “East Oahu Transmission Project” below) and has not yet issued a schedule or requirements for the regulatory audits of the CIP CT-1 and CIS projects. Campbell Industrial Park combustion turbine No. 1 and transmission line. HECO’s incurred costs for this project, which was placed in service in 2009, were $195 million, including $9 million of AFUDC. HECO’s current rates reflect recovery of project costs of $163 million. See “Major projects” above regarding the regulatory audit process that must be completed in connection with determining recovery of the remaining costs for this project. Management believes no adjustment to project costs is required as of June 30, 2012. East Oahu Transmission Project. HECO had planned a project to construct a partially underground transmission line to a major substation. However, in 2002, an application for a permit, which would have allowed construction in a route through conservation district lands, was denied. In 2007, the PUC approved HECO’s request to expend funds for a revised EOTP using different routes requiring the construction of subtransmission lines in two phases (then estimated at $56 million - $42 million for Phase 1 and $14 million for Phase 2), but did not address the issue as to whether the pre-2003 planning and permitting costs, and related AFUDC, should be included in the project costs. Phase 1 was placed in service on June 29, 2010 at a cost of $59 million. The interim D&O issued in July 2011 in HECO’s 2011 test year rate case reflected approximately $16 million of EOTP Phase 1 costs and related depreciation expense in determining revenue requirements. As described above under “Major projects,” a regulatory audit was to be conducted before the PUC determined the recoverability of the remaining costs for EOTP Phase 1. On March 29, 2012, the PUC approved the settlement agreement reached among HECO, the Consumer Advocate and the Department of Defense (parties in the HECO 2011 test year rate case proceeding) regarding the EOTP Phase 1 project costs. Under the settlement agreement, in lieu of a regulatory audit, HECO would write-off $9.5 million of EOTP Phase 1 gross plant in service and associated adjustments. The settlement agreement resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million. The PUC also provided for an additional interim increase of approximately $5 million in HECO’s 2011 test year rate case for the additional revenue requirements reflecting all remaining EOTP costs not previously included in rates or agreed to be written off (an increase of approximately $31 million to rate base). In addition, the PUC eliminated the requirement for a regulatory audit for the EOTP Phase 1. In the final D&O in the HECO 2011 test year rate case proceeding issued on June 29, 2012, the PUC approved the revenue requirements related to the prior interim D&Os related to the EOTP project costs. In April 2010, HECO proposed a modification of Phase 2 of the EOTP that uses smart grid technology and is estimated to cost $10 million (total cost of $15 million, less $5 million of funding through the Smart Grid Investment Grant Program of the American Recovery and Reinvestment Act of 2009). In October 2010, the PUC approved HECO’s modification request for Phase 2, which is projected for completion by the third quarter of 2012. As of June 30, 2012, HECO’s incurred costs for the Modified Phase 2 project amounted to $10 million (total cost of $14 million, less $4 million received in Smart Grid Investment funding). Management believes that no adjustment to project costs of EOTP Modified Phase 2 is required as of June 30, 2012. Customer Information System Project. In 2005, the PUC approved the utilities’ request to (i) expend the then-estimated $20 million (including $18 million for capital and deferred costs) for a new CIS project, provided that no part of the project costs may be included in rate base until the project is in service and is “used and useful for public utility purposes,” and (ii) defer certain computer software development costs, accumulate AFUDC during the deferral period, amortize the deferred costs over a specified period and include the unamortized deferred costs in rate base, subject to specified conditions. The CIS project’s new software system became operational in May 2012. As of June 30, 2012, the utilities’ total deferred and capital cost estimate for the CIS project was $58.6 million (of which $58.4 million was incurred). The PUC has ordered that this project undergo a regulatory audit. See “Major Projects” above concerning the accounting treatment of the costs of the CIS project pending completion of the regulatory audit. Management believes no adjustment to the CIS project costs is required as of June 30, 2012. 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 O&M expenditures. As proposed, the regulations would require facilities to come into compliance within 8 years of the effective date of the final rule. On June 11, 2012, the EPA published additional information on the section 316(b) rulemaking that indicates that the EPA is considering incorporating site-specific compliance alternatives in the final rule. HECO submitted formal comments on July 11, 2012 in support of site-specific compliance alternatives. In mid-July 2012, EPA decided to delay issuance of the final section 316(b) rule until June 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 is pursuing a MATS compliance strategy based on switching to lower emissions fuels. The CAA requires that facilities come into compliance with the MATS limits within 3 years of the final rule, although facilities may be granted two 1-year extensions. Potential compliance dates are after the expiration of current fuel oil contracts and future contract are planned to be amenable to fuel switching. The use of lower emissions fuels will provide for MATS compliance at lower overall costs, avoid the reduction in operational flexibility imposed by emissions control equipment, achieve timely compliance with the MATS and provide flexibility for optimizing the combined compliance strategies for MATS and the tightening of the National Ambient Air Quality Standards. On May 29, 2012, the EPA published a proposed plan to address regional haze in Hawaii. This proposed plan would establish an aggregate annual limit for sulfur dioxide emissions from five HELCO steam generating units on the island of Hawaii. No specific control technologies were proposed for any HECO or MECO generating units. The EPA expects to issue the final regional haze plan for Hawaii in September 2012. HELCO and MECO submitted comments on the proposed plan in July 2012. Depending upon the final outcome of the CWA 316(b) regulations, possible changes in CWA effluent standards, the specifics of the MATS compliance plan, the tightening of the National Ambient Air Quality Standards, and the final form of the Hawaii regional haze plan, HECO and its subsidiaries may be required to incur material capital expenditures, higher fuel charges 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 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. Former Molokai Electric Company generation site. In 1989, MECO acquired by merger Molokai Electric Company, which had been experiencing severe financial hardships and was facing bankruptcy. Molokai Electric Company 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 Hawaii Department of Health (DOH), MECO agreed to undertake additional investigations at the Site and at 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 will further investigate 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, 2012) 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. 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. The DOH is currently preparing the proposed regulations required by Act 234, but has not yet released them for public comment. Because the regulations implementing Act 234 have not yet been promulgated, management cannot predict the impact of Act 234 on the electric utilities, but compliance costs could be significant. 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 and 2011 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’ generating units. I n June 2010, the EPA issued its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule) that created new thresholds for GHG emissions from new and existing stationary source facilities. E ffective January 2, 2011, under the Prevention of Significant Deterioration program, permitting of new or modified stationary sources (such as utility electrical generating units) 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. In January 2011, the EPA announced that it plans to defer, for three years, GHG permitting requirements for carbon dioxide (CO2) emissions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of this deferral on their generation units that are or will be fired on biofuels. 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 electrical 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. 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 generation units, and testing biofuel blends in other HECO and MECO generating units. M anagement 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. 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 its 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:
(in thousands) |  | 2012 |  | 2011 |
Balance, January 1 |  | $ | 50,871 |  | $ | 48,630 |
Accretion expense |  | 862 |  | 1,134 |
Liabilities incurred |  | — |  | — |
Liabilities settled |  | (2,217 | ) | (573 | )
Revisions in estimated cash flows |  | — |  | — |
Balance, June 30 |  | $ | 49,516 |  | $ | 49,191 |
Collective bargaining agreements. As of June 30, 2012, approximately 53% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, which is the only union representing employees of the electric utilities. On March 11, 2011, the utilities’ bargaining unit employees ratified a new collective bargaining agreement and a new benefit agreement. The new collective bargaining agreement covers a term from January 1, 2011 to October 31, 2013 and provides for non-compounded wage increases (1.75%, 2.5%, and 3.0% for 2011, 2012 and 2013, respectively). The new benefit agreement covers a term from January 1, 2011 to October 31, 2014 and includes changes to medical, dental and vision plans with increased employee contributions and changes to retirement benefits for employees.

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