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Commitments and contingencies - HECO (Hawaiian Electric Company and Subsidiaries) | 12 Months Ended
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Dec. 31, 2011
Hawaiian Electric Company and Subsidiaries |
Commitments and contingencies |
11. Commitments and contingencies Fuel contracts. HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil, diesel fuel and biodiesel for multi-year periods, some through December 31, 2014. Fossil fuel prices are tied to the market prices of crude oil and petroleum products in the Far East and U.S. West Coast and the biodiesel price is tied to the market prices of animal fat feedstocks in the U.S. Midwest. Based on the average price per barrel as of December 31, 2011, the estimated cost of minimum purchases under the fuel supply contracts is $1.0 billion in 2012, $0.5 billion in 2013 and $0.3 billion in 2014. The actual cost of purchases in 2012 and future years could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. HECO and its subsidiaries purchased $1.3 billion, $1.0 billion and $0.7 billion of fuel under contractual agreements in 2011, 2010 and 2009, respectively. HECO and Chevron Products Company (Chevron), a division of Chevron USA, Inc., are parties to an amended contract for the purchase/sale of low sulfur fuel oil (LSFO), which terminates on April 30, 2013. HECO and Tesoro Hawaii Corporation (Tesoro) are parties to an amended LSFO supply contract (LSFO contract). The term of the amended agreement runs through April 30, 2013 and may automatically renew for annual terms thereafter unless earlier terminated by either party. The energy charge for energy purchased from Kalaeloa under HECO’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays Tesoro for fuel oil under a Facility Fuel Supply Contract (fuel contract) between them. Kalaeloa and Tesoro have negotiated a proposed amendment to the pricing formula in their fuel contract. The amendment could result in higher fuel prices for Kalaeloa, which would in turn increase the energy charge paid by HECO to Kalaeloa. HECO consented to the amendment on September 7, 2010. The costs incurred under the utilities' fuel contracts are included in their respective ECACs, to the extent such costs are not recovered through the utilities’ base rates. Power purchase agreements. As of December 31, 2011, HECO and its subsidiaries had six firm capacity PPAs for a total of 548 megawatts (MW) of firm capacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $0.7 billion, $0.5 billion and $0.5 billion for 2011, 2010 and 2009, respectively. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $0.1 billion per year for 2012 through 2016 and a total of $0.6 billion in the period from 2017 through 2030. In general, HECO and its subsidiaries base their payments under the PPAs upon available capacity and actually supplied energy and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements. HECO and its subsidiaries pass on changes in the fuel component of the energy charges to customers through the ECAC in their rate schedules. HECO and its subsidiaries do not operate, or participate in the operation of, any of the facilities that provide power under the agreements. Title to the facilities does not pass to HECO or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities. Purchase power adjustment clause. The final decision and order (D&O) for the HECO 2009 test year rate case approved a purchased power adjustment clause (PPAC). HECO purchased power capacity, operation and maintenance (O&M) and other non-energy costs previously recovered through base rates are now recovered in the PPAC, and subject to approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPAC outside of a rate case. Purchased energy costs will continue to be recovered through the ECAC to the extent they are not recovered through base rates. HELCO will also implement a PPAC pursuant to the final D&O issued in its 2010 test year rate case. 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. The State and HECO are working together to ensure the supporting infrastructure needed is in place to reliably accommodate this large increment of wind power, including any required utility system connections or interfaces with the cable and the windfarm facility. In December 2009, the PUC allowed HECO to defer the costs of studies for this 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. Additionally, in July 2011, the PUC directed HECO to file 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 October 2011, HECO filed the draft RFP with the PUC. In November 2011, HECO and MECO filed their application to seek PUC approval to defer for later recovery approximately $0.6 million for additional studies to address whether an inter-island cable system that ties the Oahu, Maui, Molokai and Lanai electrical systems would be operationally beneficial and cost-effective. Interim increases. As of December 31, 2011, HECO and its subsidiaries had recognized $40 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, based upon recommendations by the Consumer Advocate in HECO’s 2009 test year rate case, 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 Project. The PUC confirmed that any revenue requirements arising from project costs being audited shall either remain interim and subject to refund until audit completion, or remain within regulatory deferral accounts. In the Interim D&O in the 2011 test year rate case, issued in July 2011, the PUC approved the portion of the settlement agreement in that proceeding allowing 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 an independently conducted regulatory audit. In the interim order in HECO’s 2011 test year rate case, the PUC 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. The PUC did not approve the agreement to defer expenses (subject to a limit to which the parties had agreed) associated with the yet-to-be completed Customer Information System. Pursuant to the PUC’s order in HECO’s 2009 test year rate case, HECO and the Consumer Advocate submitted proposals for the scope, timing, management and structure for the regulatory audits for the PUC’s review and consideration, however, the PUC has not yet issued a schedule or requirements for the regulatory audits. 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 December 31, 2011. 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. As of December 31, 2011, HECO’s incurred costs for Phase 1 of this project was $59 million (as a result of higher costs and the project delays), including (i) $12 million of pre-2003 planning and permitting costs, (ii) $24 million of planning, permitting and construction costs incurred after the denial of the permit and (iii) $23 million for AFUDC. The interim D&O issued in HECO’s 2011 test year rate case reflects approximately $16 million of EOTP Phase 1 costs and related depreciation expense in determining revenue requirements. See “Major projects” above regarding the regulatory audit that is to be conducted before the PUC determines the recoverability of the remaining costs for EOTP Phase 1. On February 3, 2012, HECO, the Consumer Advocate and the Department of Defense (parties in the HECO 2011 test year rate case proceeding) signed a settlement agreement, subject to PUC approval, regarding the EOTP Phase 1 project costs. The parties agreed that, in lieu of a regulatory audit, HECO would write-off $9.5 million of gross plant in service costs associated with EOTP Phase 1, and associated adjustments in the accumulated depreciation, deferred depreciation expense, accumulated deferred income taxes, unamortized state investment tax credits and carrying charges. In deciding to enter into the agreement HECO took into account a number of considerations, including (1) the significant passage of time since the initial costs for the EOTP Phase 1 project were incurred, (2) the significant resources that would be required by the PUC, HECO and the other parties to conduct a fair and meaningful regulatory audit of project costs, and (3) additional carrying charges that would be accrued to the project cost during a lengthy audit process. The settlement agreement does not address the costs that are being deferred in connection with the CIP CT-1 project or the Customer Information System Project. The settlement agreement resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million. The parties agreed to stipulate, subject to PUC approval, to an additional annual interim increase of $5 million to be effective March 1, 2012, based on 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) and offset by other minor adjustments to the interim increase that became effective on July 26, 2011. The agreement allows HECO to continue to defer depreciation expense and accrue carrying charges related to the costs not yet included in rates. For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is allowed in electric rates. 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 in 2012. As of December 31, 2011, HECO’s incurred costs for the Modified Phase 2 project amounted to $8 million (total cost $11 million less $3 million received in Smart Grid Investment funding). Management believes no adjustment to project costs of EOTP Phase 1 or Modified Phase 2 is required as of December 31, 2011. 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 Customer Information System (CIS), 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 is proceeding with the implementation of a new software system. As of December 31, 2011, HECO’s total deferred and capital cost estimate for the CIS was $57 million (of which $43 million was recorded). The PUC has ordered that this project undergo a regulatory audit, which likely will not be planned until the CIS project is complete and the CIS is operational. Management believes no adjustment to CIS project costs is required as of December 31, 2011. 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 Honolulu, Kahe and Waiau power plants on the island of Oahu. Although the proposed regulations provide some flexibility, management believes they do not adequately focus on site-specific conditions and cost-benefit factors and, if adopted as proposed, 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, which the EPA expects to issue in 2012. On December 21, 2011, the EPA issued the 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 Honolulu, Kahe and Waiau power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. The final rule is under review and a compliance plan and schedule are under development. Depending on the specifics of the compliance plan, MATS may require significant capital and annual expenditures for the installation and operation of emission control equipment on HECO’s EGUs. 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 to install emission control technology. In view of the isolated nature of HECO’s electrical system and the potential requirement to install control equipment on all HECO EGUs while maintaining system reliability, the MATS compliance schedule poses a significant challenge to HECO. 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 Regional Haze rule under the CAA, 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 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. Except as otherwise disclosed herein, HECO and its subsidiaries believe the costs of responding to their releases identified to date will not have a material adverse effect, individually or in the aggregate, on its consolidated results of operations, financial condition or liquidity. 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 Company is participating in a Task Force established under Act 234, which is charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing its GHG emissions, such as those being implemented under the Energy Agreement. Because the regulations implementing Act 234 have not yet been promulgated, management cannot predict the impact of Act 234 on the Company, 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’ reports for 2010 were submitted 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. In 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. States may need to increase fees to cover the increased level of activity caused by this rule. Effective 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. 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. 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 Company’s 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 Company. For example, severe weather could cause significant harm to the Company’s 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. In September 2009, HECO recorded an estimated ARO of $23 million related to removing retired generating units at its Honolulu power plant, including abating asbestos and lead-based paint. The obligation was subsequently increased in June 2010, due to an increase in the estimated costs of the removal project. In August 2010, HECO recorded a similar estimated ARO of $12 million related to removing retired generating units at HECO’s Waiau power plant. Changes to the ARO liability included in “Other liabilities” on HECO’s balance sheet were as follows:
(in thousands) |  | 2011 | 2010
Balance, January 1 |  | $ 48,630 |  | $ 23,746 |
Accretion expense |  | 2,202 |  | 2,519 |
Liabilities incurred |  | 256 |  | 11,949 |
Liabilities settled |  | (835 | ) | (725 | )
Revisions in estimated cash flows |  | 618 |  | 11,141 |
Balance, December 31 |  | $ 50,871 |  | $ 48,630 |
Collective bargaining agreements. As of December 31, 2011, approximately 53% of the Company’s employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, which is the only union representing employees of the Company. 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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