Electric utility segment

12 Months Ended

Dec. 31, 2015

Electric utility subsidiary

Electric utility segment

4 · Electric utility segment

Regulatory assets and liabilities.  In accordance with ASC Topic 980, “Regulated Operations,” the Utilities’ financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Their continued accounting under ASC Topic 980 generally requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to and collected from customers. Management believes the Utilities’ operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Utilities expect that the regulatory assets, net of regulatory liabilities, would be charged to the statement of income in the period of discontinuance, which may result in a material adverse effect on the Company’s and the Utilities' financial condition, results of operations and/or liquidity.

Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC-authorized periods. Generally, the Utilities do not earn a return on their regulatory assets; however, they have been allowed to recover interest on certain regulatory assets and to include certain regulatory assets in rate base. Regulatory liabilities represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the future. For example, the regulatory liability for cost of removal in excess of salvage value represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire utility plant. Generally, the Utilities include regulatory liabilities in rate base or are required to apply interest to certain regulatory liabilities. In the table below, noted in parentheses are the original PUC authorized amortization or recovery periods and, if different, the remaining amortization or recovery periods as of December 31, 2015 are noted.

Regulatory assets were as follows:

December 31	2015		2014
(in thousands)
Retirement benefit plans (balance primarily varies with plans’ funded statuses)	$	679,766	$	683,243
Income taxes, net (1 to 55 years)	88,039		86,836
Decoupling revenue balancing account and RAM regulatory asset (1 to 2 years)	74,462		91,353
Unamortized expense and premiums on retired debt and equity issuances (19 to 30 years; 6 to 18 years remaining)	14,089		15,569
Vacation earned, but not yet taken (1 year)	10,420		10,248
Postretirement benefits other than pensions (18 years; less than 1 year remaining)	—		18
Other (1 to 50 years; 1 to 46 years remaining)	29,955		17,997
	$	896,731	$	905,264
Included in:
Current assets	$	72,231	$	71,421
Long-term assets	824,500		833,843
	$	896,731	$	905,264

Regulatory liabilities were as follows:

December 31	2015		2014
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$	357,825	$	331,000
Retirement benefit plans (5 years beginning with respective utility’s next rate case)	9,835		12,413
Other (5 years; 1 to 2 years remaining)	3,883		1,436
	$	371,543	$	344,849
Included in:
Current liabilities	$	2,204	$	632
Long-term liabilities	369,339		344,217
	$	371,543	$	344,849

The regulatory asset and liability relating to retirement benefit plans was recorded as a result of pension and OPEB tracking mechanisms adopted by the PUC in rate case decisions for the Utilities in 2007 (see Note 10).

Major customers.  The Utilities received 11% ($265 million), 12% ($350 million) and 11% ($340 million) of their operating revenues from the sale of electricity to various federal government agencies in 2015, 2014 and 2013, respectively.

Cumulative preferred stock. The following series of cumulative preferred stock are redeemable only at the option of the respective company at the following prices in the event of voluntary liquidation or redemption:

December 31, 2015	Voluntary liquidation price		Redemption price
Series
C, D, E, H, J and K (Hawaiian Electric)	$	20	$	21
I (Hawaiian Electric)	20		20
G (Hawaii Electric Light)	100		100
H (Maui Electric)	100		100

Hawaiian Electric is obligated to make dividend, redemption and liquidation payments on the preferred stock of each of its subsidiaries if the respective subsidiary is unable to make such payments, but this obligation is subordinated to Hawaiian Electric's obligation to make payments on its own preferred stock.

Related-party transactions. HEI charged the Utilities $6.5 million, $7.0 million and $6.2 million for general management and administrative services in 2015, 2014 and 2013, respectively. The amounts charged by HEI to its subsidiaries for services provided by HEI employees are allocated primarily on the basis of time expended in providing such services.

Hawaiian Electric’s short-term borrowings totaled nil at December 31, 2015 and 2014. The interest charged on short-term borrowings from HEI is based on the lower of HEI’s or Hawaiian Electric’s effective weighted average short-term external borrowing rate. If both HEI and Hawaiian Electric do not have short-term external borrowings, the interest is based on the average of the effective rate for 30-day dealer-placed commercial paper quoted by the Wall Street Journal plus 0.15%.

Borrowings among the Utilities are eliminated in consolidation. Interest charged by HEI to Hawaiian Electric was nil in each of 2015, 2014 and 2013.

Commitments and contingencies.

Fuel contracts.  The Utilities have contractual agreements to purchase minimum quantities of fuel oil, diesel fuel and biodiesel for multi-year periods, some through October 2017. 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. West Coast and U.S. Midwest. Based on the average price per barrel as of December 31, 2015, the estimated cost of minimum purchases under the fuel supply contracts is $245 million in 2016, $4 million in 2017 and nil in 2018. The actual cost of purchases in 2016 and future years could vary substantially from this estimate of minimum purchases as a result of changes in market prices, quantities actually purchased, entry into new supply contracts and/or other factors. The Utilities purchased $0.6 billion, $1.1 billion and $1.1 billion of fuel under contractual agreements in 2015, 2014 and 2013, respectively.

Hawaiian Electric and Chevron Products Company (Chevron), a division of Chevron USA, Inc., are parties to the Low Sulfur Fuel Oil Supply Contract (LSFO Contract) for the purchase/sale of low sulfur fuel oil (LSFO), which terminates on December 31, 2016 and may automatically renew for annual terms thereafter unless earlier terminated by either party. The PUC approved the recovery of costs incurred under this contract on April 30, 2013.

On August 27, 2014, Chevron and Hawaiian Electric entered into a first amendment of the LSFO Contract. The amendment reduces the price of fuel above certain volumes, allows for increases in the volume of fuel, and modifies the specification of certain petroleum products supplied under the contract. In addition, Chevron agreed to supply a blend of LSFO and diesel as soon as January 2016 (for supply through the end of the contract term, December 31, 2016) to help Hawaiian Electric meet more stringent EPA air emission requirements known as Mercury and Air Toxics Standards. In March 2015, the amendment was approved by the PUC.

The Utilities are also parties to amended contracts for the supply of industrial fuel oil and diesel fuels with Chevron and Hawaii Independent Energy, LLC, (HIE), respectively, which were scheduled to end December 31, 2015, but have been extended through December 31, 2016. Both agreements may be automatically renewed for annual terms thereafter unless earlier terminated by either of the respective parties.

In August 2014, Chevron and the Utilities entered into a third amendment to the Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract (Inter-island Fuel Supply Contract), which amendment extended the term of the contract through December 31, 2016 and provided for automatic renewal for annual terms thereafter unless earlier terminated by either party. In February 2015, Hawaiian Electric executed a similar extension, through December 31, 2016, of the corresponding Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract with HIE.

In June 2015, the Utilities issued Requests for Proposals (RFP) for most of their fuel needs with supplies beginning in 2017 after the expiration of Chevron LSFO and Chevron/HIE Interisland contracts on December 31, 2016. Proposals were received in July 2015.

On February 18, 2016, Hawaiian Electric and Chevron entered into a fuel supply contract for LSFO, diesel and fuel to meet MATS requirements (2016 LSFO Contract) for the island of Oahu which terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party. Also on February 18, 2016, the Utilities and Chevron entered into a supply contract for industrial fuel oil, diesel and ultra-low sulfur diesel (Petroleum Fuels Contract) for the islands of Oahu, Maui, Molokai and the island of Hawaii , which terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party. Finally, on February 18, 2016, Hawaii Electric Light and Chevron entered into a fuels terminalling agreement which terminates on December 31, 2019 for the island of Hawaii and may automatically renew for annual terms thereafter unless earlier terminated by either party. Currently, terminalling services are provided for under the Inter-island Fuel Supply Contract with Chevron that expires on December 31, 2016. Each of these contracts are for a term of three years and become effective upon PUC approval and each can be terminated if PUC approval is not received by October 1, 2016. Additionally, Chevron is required to comply with the agreed upon fuel specifications as set forth in the 2016 LSFO Contract and the Petroleum Fuels Contract.

The energy charge for energy purchased from Kalaeloa Partners, L.P. (Kalaeloa) under Hawaiian Electric’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays HIE for LSFO under a Facility Fuel Supply Contract (fuel contract) between them (assigned to HIE upon its purchase of the assets of Tesoro Hawaii Corp. as described above). The term of the fuel contract between Kalaeloa and HIE ends May 31, 2016 and may be extended for terms thereafter unless terminated by one of the parties.

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, 2015, the Utilities had five firm capacity PPAs for a total of 551 megawatts (MW) of firm capacity. Purchases from these five independent power producers (IPPs) and all other IPPs totaled $0.6 billion, $0.7 billion and $0.7 billion for 2015, 2014 and 2013, 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 as amended) 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 2016 through 2020 and a total of $0.5 billion in the period from 2021 through 2035.

In general, the Utilities 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. The Utilities pass on changes in the fuel component of the energy charges to customers through the ECAC in their rate schedules. The Utilities 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 Hawaiian Electric 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 PUC has approved purchased power adjustment clauses (PPACs) for the Utilities. Purchased power capacity, O&M and other non-energy costs previously recovered through base rates are now recovered in the PPACs and, subject to approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPACs outside of a rate case. Purchased energy costs continue to be recovered through the ECAC to the extent they are not recovered through base rates.

AES Hawaii, Inc. Under a PPA entered into in March 1988, as amended, for a period of 30 years beginning September 1992, Hawaiian Electric agreed to purchase 180 MW of firm capacity from AES Hawaii. In August 2012, Hawaiian Electric filed an application with the PUC seeking an exemption from the PUC’s Competitive Bidding Framework to negotiate an amendment to the PPA to purchase 186 MW of firm capacity, and amend the energy pricing formula in the PPA. The PUC approved the exemption in April 2013, but Hawaiian Electric and AES Hawaii were not able to reach agreement on an amendment. In June 2015, AES Hawaii filed an arbitration demand regarding a dispute about whether Hawaiian Electric was obligated to buy up to 9 MW of additional capacity based on a 1992 letter. Hawaiian Electric responded to the arbitration demand and, in October 2015, AES Hawaii and Hawaiian Electric entered into a Settlement Agreement to stay the arbitration proceeding. The Settlement Agreement includes certain conditions precedent which, if satisfied will release the parties from the claims under the arbitration proceeding. Among the conditions precedent is the successful negotiation of an amendment to the existing purchase power agreement and PUC approval of such amendment.

On November 13, 2015, Hawaiian Electric entered into Amendment No. 3 to the PPA, subject to PUC approval. Amendment No. 3 provides more favorable pricing for the additional 9 MW than the existing pricing, the benefit of which will be passed on to customers, and among other things, provides (1) for an increase in firm capacity of up to 9 MW (the Additional Capacity) above the 180 MW capacity of the AES Hawaii facility, subject to a demonstration of such increased available capacity, (2) for the payment for the Additional Capacity to include a Priority Peak Capacity Charge, a Non-Peak Capacity Charge, a Priority Peak Energy Charge and a Non-Peak Energy Charge, and (3) that AES will make certain operational commitments to improve reliability, and Hawaiian Electric will pay a reliability bonus according to a schedule for reduced Full Plant Trips. On January 22, 2016, Amendment No. 3 was filed with the PUC for approval. If such approval is obtained, the final condition to the Settlement Agreement’s release of the parties from the arbitration claims will be satisfied. The arbitration proceeding has been stayed to allow the PUC approval proceeding to proceed.

Liquefied natural gas. On May 31, 2015, the previous August 2014 agreement with Fortis BC Energy Inc. (Fortis) for liquefaction capacity for liquefied natural gas (LNG) was superseded with a liquefaction Heads of Agreement by and between FortisBC Holdings Inc. and Hawaiian Electric. The agreement, which is subject to PUC approval, other regulatory approvals and permits and other conditions precedent before it becomes effective, provides for LNG liquefaction capacity purchases of 700,000 tonnes per year for the first five years, 600,000 tonnes per year for the next five years and 500,000 tonnes per year for the last ten years. Fortis must also obtain regulatory and other approvals for the agreement to become effective. The Fortis agreement is assignable and can be assigned to the selected bidder in the Utilities’ RFP for the supply of containerized LNG and will help ensure that liquefaction capacity is available at pricing that management believes will lower customer bills.

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. 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 Hawaiian Electric’s consolidated net income.

Renewable energy project matters.  In November 2013, Hawaiian Electric and Maui Electric filed an application for recovery of its actual deferred costs totaling $405,000 (split evenly between Hawaiian Electric and Maui Electric) for outside contractor services for additional studies to determine the value proposition of interconnecting the islands of Oahu and of Maui County (Maui, Lanai, and Molokai) through the Renewable Energy Infrastructure Program (REIP) surcharge. In July 2015, the PUC approved recovery of the deferred costs for Hawaiian Electric over a four-month period, and over a two-year period for Maui Electric.

In February 2012, the PUC granted Hawaiian Electric’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. Through December 31, 2013, Hawaiian Electric deferred $3.1 million related to outside contractor service costs incurred with the Oahu 200 MW RFP, and began amortizing such costs over 3 years beginning in July 2014.

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, Hawaii Electric Light filed an application to defer 2012 costs related to the Geothermal RFP. In November  2015, the PUC approved the deferral of $2.1 million of costs related to the Geothermal RFP, and will review the prudency and reasonableness of the deferred costs in the next Hawaii Electric Light rate case.In February 2013, Hawaii Electric Light issued the Final Geothermal RFP. Six bids were received, but Hawaii Electric Light notified bidders that none of the submitted bids sufficiently met both the low-cost and technical requirements of the Geothermal RFP. In October 2014, Hawaii Electric Light issued Addendum No. 1 (Best and Final Offer) and Attachment A (Best and Final Offer Bidder's Response Package) directly to five eligible bidders. The submittals received in January 2015 will be considered for final selection of one project to proceed with PPA negotiations. In February 2015, Ormat Technologies, Inc. was selected for an award and began PPA negotiations with Hawaii Electric Light. In February 2016, Hawaii Electric Light provided the PUC with a status update notifying the PUC that the selected bidder had determined the proposed project not to be economically and financially viable, resulting in conclusion of PPA negotiations.

Enterprise Resource Planning/Enterprise Asset Management (ERP/EAM) Implementation Project. The Utilities submitted its Enterprise Information System Roadmap to the PUC in June 2014 and refiled an application for an ERP/EAM implementation project in July 2014 with an estimated cost of $82.4 million. The refiled application addressed the concerns raised by the PUC, in the initial application, regarding the benefits to customers of completing this project. The estimated cost of the project included the cost of ERP software that had been purchased and recorded as a deferred cost.

To address the Consumer Advocate’s position that the proceeding should be stayed to determine if the project as proposed in the application is reasonable and necessary for future operations as an indirect NEE subsidiary, in May 2015, the Utilities filed a report describing the impact the pending merger with NEE would have on the scope, costs and benefits of the ERP/EAM project. The report indicated that the two viable courses of action for replacing its current system are Option A (to proceed with the project as initially scoped in the Application), and Option B (to move the Utilities to NEE’s existing ERP/EAM solutions). Option B is estimated to cost approximately $20.8 million less than Option A, but can only be pursued if the merger is approved. The Utilities requested the PUC to approve the commencement of work on Option B if the merger is approved; and in the alternative, Option A if the merger is not approved.

In October 2015, the PUC issued a D&O (1) finding that there is a need to replace the existing ERP/EAM system, and (2) deferring any ruling on whether it is reasonable and in the public interest for the Utilities to commence with the project under Options B or A.

In the D&O, the PUC denied the Utilities request to defer the cost for the ERP software purchased in 2012. As a result, the Utilities expensed the ERP software costs of $4.8 million in the third quarter of 2015.

The D&O requires the Utilities to file their bottom-up low-level benefits analysis for both Options A and B, and specified additional information required as part of the their Cost/Benefit Analysis, which will be due by April 8, 2016.

Management cannot predict the further outcome of this proceeding.

Schofield Generating Station Project. In August 2012, the PUC approved a waiver from the competitive bidding framework to allow Hawaiian Electric to negotiate with the U.S. Army for the construction of a 50 MW utility owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks. In September 2015, the PUC approved Hawaiian Electric’s application to expend $167 million for the project. In approving the project, the PUC placed a cap of $167 million for the project, stated 90% of the cap is allowed for cost recovery through cost recovery mechanisms other than base rates, and stated the $167 million cap will be adjusted downward due to any reduction in the cost of the engine contract due to a reduction in the foreign exchange rate. Hawaiian Electric is required to take all necessary steps to lock in the lowest possible exchange rate. On January 5, 2016, Hawaiian Electric executed a window forward agreement which lowered the cost of the engine contract by $9.7 million, resulting in a revised project cap of $157.3 million. The generating station is now expected to be placed in service in the first quarter of 2018.

Environmental regulation.  The Utilities 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 and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.

On August 14, 2014, the EPA published in the Federal Register the final 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 regulations were effective October 14, 2014 and apply to the cooling water systems for the steam generating units at Hawaiian Electric’s power plants on the island of Oahu. The regulations prescribe a process, including a number of required site-specific studies, for states to develop facility-specific entrainment and impingement controls to be incorporated in each facility’s National Pollutant Discharge Elimination System permit. In the case of Hawaiian Electric’s power plants, there are a number of studies that have yet to be completed before Hawaiian Electric and the State of Hawaii Department of Health (DOH) can determine what entrainment or impingement controls, if any, might be necessary at the affected facilities to comply with the new 316(b) rule.

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 Hawaiian Electric’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, Hawaiian Electric 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. Hawaiian Electric requested and received a one-year extension, resulting in a MATS compliance date of April 16, 2016. Hawaiian Electric submitted to the EPA a Petition for Reconsideration and Stay dated April 16, 2012, which asked the EPA to revise an emissions standard for non-continental oil-fired EGUs on the grounds that the promulgated standard was incorrectly derived. On April 21, 2015, the EPA denied Hawaiian Electric's Petition. Hawaiian Electric appealed the EPA’s denial of the Petition. On June 29, 2015, the U.S. Supreme Court found that the EPA’s determination that it was appropriate and “necessary” to regulate hazardous air pollutants from power plants was flawed because the EPA did not take the costs of compliance into account. The Supreme Court sent the MATS rule case back to the D.C. Circuit Court of Appeals for further proceedings. On December 15, 2015, the D.C. Circuit ordered the EPA to update its “appropriate and necessary” finding and ordered that the costs of compliance must be considered. The D.C. Circuit did not stay the MATS rule so all requirements of the MATS rule, including the April 16, 2016 compliance deadline remain in effect.

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 (SO₂) National Ambient Air Quality Standard (NAAQS) implementation plans. In August 2015, the EPA published the final data requirements rule for states to characterize their air quality in relation to the one-hour SO₂ NAAQS. Under this rule, the EPA expects to designate areas as attaining, or not attaining, the one-hour SO₂ NAAQS in December 2017 or December 2020, depending on whether the area was characterized through modeling or monitoring. Hawaiian Electric will work with the DOH in implementing the one-hour SO₂ NAAQS and in developing cost-effective strategies for NAAQS compliance, if needed.

Depending upon the rules and guidance developed for compliance with the more stringent NAAQS, the Utilities may be required to incur material capital expenditures and other compliance costs, but such amounts and their timing are not determinable at this time. Additionally, the combined effects of the CWA 316(b) regulations, the MATS rule and the more stringent NAAQS may contribute to a decision to retire or deactivate certain generating units earlier than anticipated.

Hawaiian Electric, Hawaii Electric Light and Maui Electric, like other utilities, periodically encounter petroleum or other chemical releases into the environment associated with current or previous operations. The Utilities report and take action on these releases when and as required by applicable law and regulations. The Utilities believe the costs of responding to such releases identified to date will not have a material adverse effect, individually or in the aggregate, on Hawaiian Electric’s consolidated results of operations, financial condition or liquidity.

Potential Clean Air Act Enforcement.  On July 1, 2013, Hawaii Electric Light and Maui Electric 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 parties are continuing to negotiate toward a resolution of the DOJ’s claims. As part of the ongoing negotiations, the DOJ proposed in November 2014 entering into a consent decree pursuant to which the Utilities would install certain pollution controls and pay a penalty. The Utilities continue to have discussions with, and provide information to, the DOJ, but are unable to estimate the amount or effect of a consent decree, if any, at this time.

Former Molokai Electric Company generation site.  In 1989, Maui Electric 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 Maui Electric never operated at the Site and operations there had stopped four years before the merger, in discussions with the EPA and the DOH, Maui Electric 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 Maui Electric contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, Maui Electric is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, residual fuel oils, and other subsurface contaminants. Maui Electric has a reserve balance of $3.6 million as of December 31, 2015 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. The final site investigation plan was submitted to the DOH and EPA in December 2014 for their approval. The DOH formally approved the investigation plan on September 14, 2015. The EPA determined that their formal approval is not required until the next phase of work that determines cleanup actions for the site. Sampling of the site per the investigation plan will proceed after securing required permits and access agreements.

Pearl Harbor sediment study. In July 2014, the U.S. Navy notified Hawaiian Electric of the Navy’s determination that Hawaiian Electric is responsible for cleanup of PCB contamination in sediment in the area offshore of the Waiau Power Plant. The Navy has also requested that Hawaiian Electric reimburse the costs incurred by the Navy to date to investigate the area, and is asking Hawaiian Electric to engage in negotiations regarding the financing and undertaking of future response actions to address the sediment contamination offshore from the Waiau Power Plant. The extent of the contamination, the appropriate remedial measures to address it, and Hawaiian Electric’s potential responsibility for any associated costs, including any past costs incurred by the Navy, have not yet been determined. The Navy has completed a remedial investigation and a feasibility study (FS) for the remediation of contaminated sediment at several locations in Pearl Harbor. The Navy’s study identified elevated levels of PCBs in the sediment in East Loch of Pearl Harbor, offshore from the Waiau Power Plant. The Navy issued its Final FS Report on June 29, 2015. The Navy has indicated that additional data collection is necessary and will be conducted as part of the remedial design, and that the results will be used to finalize the remediation plan and to better define the areas where remediation is necessary to reduce the potential environmental risks. Hawaiian Electric has requested to participate with the Navy in the preparation of the remedial design for the contaminated sediment offshore from the Waiau Power Plant, and in particular in the development of the work plan for additional data collection, and refinement of the environmental risk analysis, the final remedy, and the response costs for the offshore area. To date, Hawaiian Electric’s role in the development of the remedial design and response costs is uncertain.

On March 23, 2015, Hawaiian Electric received a letter from the EPA requesting that Hawaiian Electric submit a work plan to assess potential sources and extent of PCB contamination onshore at the Waiau Power Plant. Hawaiian Electric submitted a sampling and analysis (SAP) work plan to the EPA and the DOH. Sampling of outfall sediments at the Waiau Power Plant was completed in accordance with the SAP in December 2015. The extent of the onshore contamination, the appropriate remedial measures to address it, and any associated costs have not yet been determined.

As of December 31, 2015, the reserve account recorded by Hawaiian Electric to address the PCB contamination stands at $4.7 million. The reserve represents the probable and reasonably estimable cost to complete the onshore and offshore investigations and the remediation of PCB contamination in the offshore sediment. The final remediation costs will depend on the results of the onshore investigation and assessment of potential source control requirements, as well as the further investigation of contaminated sediment offshore from the Waiau Power Plant.

Hawaiian Electric has also conducted a search for other potential sources of sediment contamination in the Waiau area that are unrelated to electric power generation at its Waiau Power Plant. Hawaiian Electric has identified a potential source east of the plant: a former Naval Reserve (a Formerly Used Defense Site (FUDS)) where a used drum storage area, a waste oil burning pit, and an oil/water separator were operated by the Navy from the 1940s until approximately 1962. This FUDS is located on the property currently occupied by the City and County (C&C) of Honolulu’s Neal S. Blaisdell Park. To further assess this former Naval Reserve site, Hawaiian Electric has requested environmental investigation reports, environmental data, and permits for this property and the adjacent Waimalu Stream (e.g., dredging permits and related environmental impact assessments and studies) from several federal and state agencies, as well as the C&C of Honolulu. The contribution of PCBs to sediment contamination in East Loch from this potential source has not yet been determined.

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

In July 2007, the State Legislature passed 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. On June 20, 2014, the Governor signed the final regulations required to implement Act 234 (i.e., the final GHG rule), which went into effect on June 30, 2014. In general, Act 234 and the corresponding GHG rule require affected sources (that have the potential to emit GHGs in excess of established thresholds) to reduce their GHG emissions by 16% below 2010 emission levels by 2020. In accordance with the GHG rule, the Utilities submitted their Emissions Reduction Plan (EmRP) to the DOH on June 30, 2015. Hawaiian Electric, Maui Electric, and Hawaii Electric Light have a total of 11 facilities affected by the state GHG rule. Hawaiian Electric made use of the partnering provisions in the DOH GHG rule to prepare one EmRP for all 11 of the Utilities’ affected facilities. In this plan, the Utilities have committed to a 16% reduction in GHG emissions company-wide. Pursuant to the State’s GHG rule, the DOH will incorporate the proposed facility-specific GHG emission limits into each facility’s covered source permit based on the 2020 levels specified in Hawaiian Electric’s approved EmRP. The GHG rule also requires affected sources to pay an annual fee that is based on tons per year of GHG emissions starting on the effective date of the regulations. The fee for the Utilities is estimated to be approximately $0.5 million annually. The latest assessment of the proposed federal and final state GHG rules is that the continued growth in renewable power generation will significantly reduce the compliance costs and risk for the Utilities.

On September 22, 2009, the EPA issued its “Final Mandatory Reporting of Greenhouse Gases Rule,” which requires sources that emit GHGs above certain threshold levels to monitor and report their GHG emissions. Following these requirements, the Utilities have submitted the required reports for 2010 through 2014 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 to address GHG emissions from stationary sources, like the Utilities’ EGUs.

As part of President Obama’s Climate Action Plan, the EPA has been directed to adopt GHG emission limits for new and existing EGUs. The EPA issued the final federal rule for GHG emission reductions from existing EGUs, also known as the Clean Power Plan, on August 3, 2015. The final federal GHG rule for existing EGUs sets interim state-wide emissions limits for EGUs operating in the 48 contiguous states that must be met on average from 2022 through 2029; final limits will apply from 2030. The EPA did not issue final guidelines for Alaska, Hawaii, Puerto Rico or Guam because the Best System of Emission Reduction established for the contiguous states is not appropriate for these locations. The EPA has said it will work with the state and territorial governments for Alaska, Hawaii, Puerto Rico and Guam and other stakeholders to gather additional information regarding the emissions reduction measures available in these jurisdictions, particularly with respect to renewable generation. Hawaiian Electric plans to participate in this process. Management’s latest assessment of the Clean Power Plan is that the continued growth of renewable power generation and the expected use of LNG as a transitional fuel by the Utilities in the future will significantly reduce the compliance costs and risk for the Utilities. To date, no timetable has been established by the EPA to develop GHG emission limits for Alaska, Hawaii, Puerto Rico or Guam, and such timing has become more uncertain in light of the decision of the U.S. Supreme Court on February 9, 2016, blocking implementation of the Clean Power Plan while it is being challenged in court.

The Utilities 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 Hawaiian Electric’s Campbell Industrial Park combustion turbine No. 1 (CIP CT-1), using biodiesel for startup and shutdown of selected Maui Electric generating units, and testing biofuel blends in other Hawaiian Electric and Maui Electric generating units. The Utilities are also working with the State of Hawaii and other entities to pursue the use of LNG 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 more comprehensive GHG regulations that might be promulgated; however, the various initiatives that the Utilities are pursuing are likely to provide a sound basis for appropriately managing the Utilities’ carbon footprint and thereby meet both state and federal GHG reduction goals.

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. This effect could potentially result in impacts to coastal and other low-lying areas (where much of the Utilities’ electric infrastructure is sited), and result in increased flooding and storm damage due to heavy rainfall, increased rates of beach erosion, saltwater intrusion into freshwater aquifers and terrestrial ecosystems, and higher water tables in low-lying areas. The effects of climate change on the weather (for example, more intense or more frequent rain events, flooding, or hurricanes), sea levels, and freshwater availability and quality have the potential to materially adversely affect the results of operations, financial condition, and liquidity of the Utilities. For example, severe weather could cause significant harm to the Utilities’ physical facilities.

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. The Utilities’ 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 the Utilities relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.

Hawaiian Electric has recorded estimated AROs related to removing retired generating units at its Honolulu and Waiau power plants. These removal projects are ongoing, with significant activity and expenditures occurring in 2014 in partial settlement of these liabilities. Both removal projects are expected to continue through 2015.

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

(in thousands)	2015			2014
Balance, January 1	$	29,419		$	43,106
Accretion expense	24			890
Liabilities incurred	—			—
Liabilities settled	(2,595		)	(14,577		)
Revisions in estimated cash flows	—			—
Balance, December 31	$	26,848		$	29,419

Decoupling.In 2010, the PUC issued an order approving decoupling, which was implemented by Hawaiian Electric on March 1, 2011, by Hawaii Electric Light on April 9, 2012 and by Maui Electric on May 4, 2012. Decoupling is a regulatory model that is intended to facilitate meeting the State of Hawaii’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio standard. The decoupling model implemented in Hawaii delinks revenues from sales and includes annual rate adjustments for certain O&M expenses and rate base changes. The decoupling mechanism has three components: (1) a sales decoupling component via a revenue balancing account (RBA), (2) a revenue escalation component via a rate adjustment mechanism (RAM) and (3) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility exceeds the ROACE allowed in its most recent rate case. Decoupling provides for more timely cost recovery and earning on investments.

On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling and citing three years of implementation experience for Hawaiian Electric, the PUC opened an investigative docket to review whether the decoupling mechanisms are functioning as intended, are fair to the Utilities and their ratepayers, and are in the public interest. The PUC affirmed its support for the continuation of the sales decoupling (RBA) mechanism and stated its interest in evaluating the RAM to ensure it provides the appropriate balance of risks, costs, incentives and performance requirements, as well as administrative efficiency, and whether the current interest rate applied to the outstanding RBA balance is reasonable. In October 2013, the PUC issued orders that bifurcated the proceeding (into Schedule A and Schedule B issues).

On February 7, 2014, the PUC issued a decision and order (D&O) on the Schedule A issues, which made certain modifications to the decoupling mechanism. Specifically, the D&O required:

• An adjustment to the Rate Base RAM Adjustment to include 90% of the amount of the current RAM Period Rate Base RAM Adjustment that exceeds the Rate Base RAM Adjustment from the prior year, to be effective with the Utilities’ 2014 decoupling filing.

• Effective March 1, 2014, the interest rate to be applied on the outstanding RBA balances to be the short term debt rate used in each Utilities last rate case (ranging from 1.25% to 3.25%), instead of the 6% that had been previously approved.

As required, the Utilities have made available to the public, on the Utilities’ websites, performance metrics identified by the PUC. The Utilities are updating the performance metrics on a quarterly basis.

On March 31, 2015, the PUC issued an Order (the March Order) related to the Schedule B portion of the proceeding to make certain further modifications to the decoupling mechanism, and to establish a briefing schedule with respect to certain issues in the proceeding. The March Order modified the RAM portion of the decoupling mechanism to be capped at the lesser of the RAM Revenue Adjustment as currently determined (adjusted to eliminate the 90% limitation on the current RAM Period Rate Base RAM adjustment that was ordered in the Schedule A portion of the proceeding) and a RAM Revenue Adjustment calculated based on the cumulative annual compounded increase in Gross Domestic Product Price Index (GDPPI) applied to the 2014 annualized target revenues (adjusted for certain items specified in the Order). The 2014 annualized target revenues represent the target revenues from the last rate case, and RAM revenues, offset by earnings sharing credits, if any, allowed under the decoupling mechanism through the 2014 decoupling filing. The Utilities may apply to the PUC for approval of recovery of revenues for Major Projects (including related baseline projects grouped together for consideration as Major Projects) through the RAM above the RAM cap or outside of the RAM through the Renewable Energy Infrastructure Program (REIP) surcharge or other adjustment mechanism. The RAM was amended on an interim basis pending the outcome of the PUC’s review of the Utilities’ Power Supply Improvement Plans. The triennial rate case cycle required under the decoupling mechanism continues to serve as the maximum period between the filing of general rate cases, and the amendments to the RAM do not limit or dilute the ordinary opportunities for the Utilities to seek rate relief according to conventional/traditional ratemaking procedures.

In making the modifications to the RAM Adjustment, the PUC stated the changes are designed to provide the PUC with control of and prior regulatory review over substantial additions to baseline projects between rate cases. The modifications do not deprive the Utilities of the opportunity to recover any prudently incurred expenditure or limit orderly recovery for necessary expanded capital programs.

The RBA, which is the sales decoupling component, was retained by the PUC in its March Order, and the PUC made no change in the authorized return on common equity. The PUC stated that performance-based ratemaking is not adopted at this time.

On May 28, 2015, the PUC issued an Order (the May Order) related to the Utilities’ revised annual decoupling filing for tariffed rates submitted on April 15, 2015. The May Order ruled on the specific matters identified by the PUC in its information requests and by the Consumer Advocate in its Statement of Position. As a result of the May Order, on June 3, 2015, the Utilities filed revised tariff rates reflecting a reduction to the RAM portion of the tariff filing. The revision was made primarily to adjust the RAM to reflect reduced operations and maintenance expenses associated with the Utilities’ change in estimate related to the allocation of indirect costs implemented in 2014, and to exclude the GDPPI factor on the depreciation expense portion for the calculation of the 2015 RAM Cap. The May Order also requires a one-time adjustment to customers for the impact of bonus tax depreciation enacted in December 2014 on the RAM revenues used for the 2014 tariff filing.

The revised 2015 annual incremental RAM revenues for the Utilities amounts to $11.1 million compared to the $26.2 million filed on April 15, 2015 and the $31.6 million filed on March 31, 2015 based on the methodology prior to its modification in the March Order. The tariffed rates, which became effective on June 8, 2015, also include the collection or refund of the accrued RBA balance and associated revenue taxes as of December 31, 2014 and any accrued earnings sharing mechanism credits. The net refund to be provided by the three Utilities under the revised tariffs amounts to $0.4 million, compared to a collection of $14.7 million under the tariffs filed on April 15, 2015. Below is a summary of the 2015 incremental impact by company.

($ in millions)	Hawaiian Electric			Hawaii Electric Light		Maui Electric
Annual incremental RAM adjusted revenues	$	8.1		$	1.5	$	1.5
Annual change in accrued earnings sharing credits to be refunded	$	—		$	—	$	(0.1	)
Annual change in accrued RBA balance as of December 31, 2015 (and associated revenue taxes) to be collected	$	(9.2	)	$	0.1	$	(2.2	)
Net annual incremental amount to be collected under the tariffs	$	(1.1	)	$	1.5	$	(0.8	)
Impact on typical residential customer monthly bill (in dollars) *	$	(0.09	)	$	0.88	$	(0.13	)

Note: Columns may not foot due to rounding

* Based on a 500 kilowatthour (KWH) bill for Hawaiian Electric, Maui Electric, and Hawaii Electric Light. The bill impact for Lanai and Molokai customers is a decrease of $0.11, based on a 400 KWH bill.

As required by the March Order, the Parties filed initial and reply briefs related to the following issues: (1) whether and, if so, how the conventional performance incentive mechanisms proposed in this proceeding should be refined and implemented in this docket; (2) what are the appropriate steps, processes and timing for determining measures to improve the efficiency and effectiveness of the general rate case filing and review process; and (3) what are the appropriate steps, processes and timing to further consider the merits of the proposed changes to the ECAC identified in this proceeding. In identifying the issue on possible changes to the ECAC, the PUC stated that changes to the ECAC should be made with great care to avoid unintended consequences.

In accordance with the March Order, the Utilities and the Consumer Advocate filed on June 15, 2015, their Joint Proposed Modified REIP Framework/Standards and Guidelines regarding the eligibility of projects for cost recovery above the RAM Cap through the REIP surcharge. On the same date, the Utilities filed their proposed standards and guidelines on the eligibility of projects for cost recovery through the RAM above the RAM Cap. On June 30, 2015, the Consumer Advocate filed comments on this proposal, and the County of Hawaii filed comments on both the REIP and the RAM above the RAM Cap proposals. On October 26, 2015, Hawaiian Electric filed an application to recover the revenue requirements associated with 2015 net plant additions in the amount of $40.3 million and other associated costs for its Underground Cable Program and the 138kV Transmission and 46kV Sub-Transmission Structures Major Baseline Projects through the RAM above the 2015 RAM Cap. On October 30, 2015, Maui Electric filed an application to recover the revenue requirements associated with 2015 net plant additions in the amount of $4.3 million and other associated costs for its transmission and distribution and generation plant reliability Major Baseline Project through the RAM above the 2015 RAM Cap. In November 2015, the Consumer Advocate filed preliminary statements of position (PSOPs) on these two applications, recommending that the PUC reject the applications. In December 2015, the Utilities filed responses to the Consumer Advocate’s PSOPs, pointing out that the PUC had already authorized the filing of such applications for recovery of capital costs above the RAM Cap and requesting that the PUC proceed with review of the applications.

Potential impact of lava flows.In June 2014, lava from the Kilauea Volcano on the island of Hawaii began flowing toward the town of Pahoa. Hawaii Electric Light monitored utility property and equipment near the affected areas and protected that property and equipment to the extent possible (e.g., building barriers around poles). In March 2015 Hawaii Electric Light filed an application with the PUC requesting approval to defer costs incurred to monitor, prepare for, respond to, and take other actions necessary in connection with the June 2014 Kilauea lava flow such that Hawaii Electric Light can request PUC approval to recover those costs in a future rate case. The Consumer Advocate objected to the request. A PUC decision is pending.

April 2014 regulatory orders. In April 2014, the PUC issued four orders that collectively address certain key policy, resource planning and operational issues for the Utilities. The four orders are as follows:

Integrated Resource Planning. The PUC did not accept the Utilities’ Integrated Resource Plan and Action Plans submission, and, in lieu of an approved plan, has commenced other initiatives to enable resource planning. The PUC directed each of Hawaiian Electric and Maui Electric to file within 120 days its respective Power Supply Improvement Plans (PSIPs), and the PSIPs were filed in August 2014. The PUC also provided its inclinations on the future of Hawaii’s electric utilities in an exhibit to the order. The exhibit provides the PUC’s perspectives on the vision, business strategies and regulatory policy changes required to align the Utilities' business model with customers’ interests and the state’s public policy goals.

Reliability Standards Working Group. The PUC ordered the Utilities (and in some cases the Kauai Island Utility Cooperative (KIUC)) to take timely actions intended to lower energy costs, improve system reliability and address emerging challenges to integrate additional renewable energy. In addition to the PSIPs mentioned above, the PUC ordered certain filing requirements which include the following:

• Distributed Generation Interconnection Plan - the Utilities’ Plan was filed in August 2014.

• Plan to implement an on-going distribution circuit monitoring program to measure real-time voltage and other power quality parameters - the Utilities’ Plan was filed in June 2014.

• Action Plan for improving efficiencies in the interconnection requirements studies - the Utilities’ Plan was filed in May 2014.

• The Utilities are to file monthly reports providing details about interconnection requirements studies.

• Integrated interconnection queue for each distribution circuit for each island grid - the Utilities’ integrated interconnection queue plan was filed in August 2014 and the integrated interconnection queues were implemented in January 2015.

The PUC also stated it would be opening new dockets to address (1) reliability standards, (2) the technical, economic and policy issues associated with distributed energy resources (see “Distributed Energy Resources (DER) Investigative Proceeding” below) and (3) the Hawaii electricity reliability administrator, which is a third party position which the legislature has authorized the PUC to create by contract to provide support for the PUC in developing and periodically updating local grid reliability standards and procedures and interconnection requirements and overseeing grid access and operation.

Policy Statement and Order Regarding Demand Response Programs. The PUC provided guidance concerning the objectives and goals for demand response programs, and ordered the Utilities to develop an integrated Demand Response Portfolio Plan that will enhance system operations and reduce costs to customers. The Utilities’ Plan was filed in July 2014. Subsequently, the Utilities submitted status updates and an update and supplemental report to the Plan. On July 28, 2015, the PUC issued an order appointing a special advisor to guide, monitor and review the Utility’s Plan design and implementation. On December 30, 2015, the Utilities filed applications with the PUC (1) for approval of their proposed DR Portfolio Tariff Structure, Reporting Schedule and Cost Recovery of Program Costs through the Demand-Side Management (DSM) Surcharge, and (2) for approval to defer and recover certain computer software and software development costs for a Demand Response Management System (DRMS) through the Renewable Energy Infrastructure Program (REIP) Surcharge.

Maui Electric Company 2012 Test Year Rate Case. The PUC acknowledged the extensive analyses provided by Maui Electric in its System Improvement and Curtailment Reduction Plan (SICRP) filed in September 2013. The PUC stated that it is encouraged by the changes in Maui Electric’s operations that have led to a significant reduction in the curtailment of renewables, but stated that Maui Electric has not set forth a clearly defined path that addresses integration and curtailment of additional renewables. The PUC directed Maui Electric to present a PSIP to address present and future system operations so as to not only reduce curtailment, but to optimize the operation of its system for its customers’ benefit. The Maui Electric PSIP was filed in August 2014, and is currently being reviewed by the PUC in a new docket along with the Hawaiian Electric and Hawaii Electric Light PSIPs. Maui Electric filed its second annual SICRP status update in September 2015.

Review of PSIPs. Collectively, the PUC's April 2014 resource planning orders confirm the energy policy and operational priorities that will guide the Utilities' strategies and plans going forward.

PSIPs for Hawaiian Electric, Maui Electric and Hawaii Electric Light were filed in August 2014. The PSIPs each include a tactical plan to transform how electric utility services will be offered to meet customer needs and produce higher levels of renewable energy. Each plan contains a diversified mix of technologies, including significant distributed and utility‑scale renewable resources, that is expected to result, on a consolidated basis, in over 65% of the Utilities’ energy being produced from renewable resources by 2030. Under these plans, the Utilities will support sustainable growth of rooftop solar, expand use of energy storage systems, empower customers by developing smart grids, offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs), switch from high-priced oil to lower cost liquefied natural gas, retire higher-cost, less efficient existing oil-based steam generators and lower full service residential customer bills in real dollars.

In November 2015, the PUC issued an order in the proceeding to review the PSIPs filed. The order provided observations and concerns on the PSIPs submitted. In November 2015, as required by the order, the Utilities submitted a Proposed Revision Plan, which included a schedule and a work plan to supplement, amend and update the PSIPs in order to address the PUC’s observations and concerns, including an Interim PSIP Update filing in February 2016 and updated PSIPs by April 1, 2016. The parties and participants filed comments on the Utilities Proposed Revision Plan in January 2016. The PUC is expected to provide further guidance regarding the substance and course of the proceeding.

In February 2016, the Utilities filed their PSIP Update Interim Status Report with the PUC, which discusses the status of the Utilities’ ongoing planning and analysis for a diverse mix of energy resources to meet the state’s 100% RPS goal by 2045. The report precedes more fully updated PSIPs to be filed by April 1, 2016.

Distributed Energy Resources (DER) Investigative Proceeding. In March 2015, the PUC issued an order to address DER issues.

On June 29, 2015, the Utilities submitted their final Statement of Position in the DER proceeding, which included:

(1) new pricing provisions for future rooftop photovoltaic (PV) systems,

(2) technical standards for advanced inverters,

(3) new options for customers including battery-equipped rooftop PV systems,

(4) a pilot time-of-use rate,

(5) an improved method of calculating the amount of rooftop PV that can be safely installed, and

(6) a streamlined and standardized PV application process.

On October 12, 2015, the PUC issued a D&O establishing DER reforms that: (1) promote rapid adoption of the next generation of solar PV and other distributed energy technologies; (2) encourage more competitive pricing of distributed energy resource systems; (3) lower overall energy supply costs for all customers; and (4) help to manage DER in terms of each island’s limited grid capacity.

The D&O approved a customer self-supply tariff and a customer grid supply tariff to govern customer generators connected to the Utilities’ systems. These tariffs replace the Net Energy Metering (NEM) program.

The D&O ordered the Utilities, among other things, (a) to collaborate with inverter manufacturers to develop a test plan by December 15, 2015 for the highest priority advanced inverter functions that are not UL certified and (b) to complete the circuit-level hosting capacity analysis for all islands in the Utilities’ service territories by December 10, 2015. The DER Phase 2 of this docket began in November 2015 and focused on further developing competitive markets for distributed energy resources, including storage.

On October 21, 2015, The Alliance for Solar Choice, LLC (TASC) filed a complaint in Hawaii state court seeking an order enjoining the PUC from implementing the D&O and declaring that the D&O be reversed, modified, and/or remanded to the PUC for further proceedings. On January 19, 2016, the Circuit Court entered a final judgment against TASC on all of its claims. TASC has filed a notice of appeal from the final judgment. TASC also filed a second appeal of the D&O directly with the Intermediate Court of Appeals. The Utilities have moved to dismiss this appeal, and the motion is currently pending before the Court.

Consolidating financialinformation. Hawaiian Electric is not required to provide separate financial statements or other disclosures concerning Hawaii Electric Light and Maui Electric to holders of the 2004 Debentures issued by Hawaii Electric Light and Maui Electric to HECO Capital Trust III (Trust III) since all of their voting capital stock is owned, and their obligations with respect to these securities have been fully and unconditionally guaranteed, on a subordinated basis, by Hawaiian Electric. Consolidating information is provided below for Hawaiian Electric and each of its subsidiaries for the periods ended and as of the dates indicated.

Hawaiian Electric also unconditionally guarantees Hawaii Electric Light’s and Maui Electric’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of Hawaii Electric Light and Maui Electric, (b) under their respective private placement note agreements and the Hawaii Electric Light notes and Maui Electric notes issued thereunder (see Hawaiian Electric and Subsidiaries' Consolidated Statements of Capitalization) and (c) relating to the trust preferred securities of Trust III (see Note 6). Hawaiian Electric is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on Hawaii Electric Light’s and Maui Electric’s preferred stock if the respective subsidiary is unable to make such payments.

Consolidating statement of income

Year ended December 31, 2015

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Revenues	$	1,644,181		345,549		345,517		—	(81	)	[1]	$	2,335,166
Expenses
Fuel oil	458,069			71,851		124,680		—	—			654,600
Purchased power	440,983			97,503		55,610		—	—			594,096
Other operation and maintenance	284,583			63,098		65,408		—	—			413,089
Depreciation	117,682			37,250		22,448		—	—			177,380
Taxes, other than income taxes	156,871			32,312		32,702		—	—			221,885
Total expenses	1,458,188			302,014		300,848		—	—			2,061,050
Operating income	185,993			43,535		44,669		—	(81	)		274,116
Allowance for equity funds used during construction	5,641			604		683		—	—			6,928
Equity in earnings of subsidiaries	42,920			—		—		—	(42,920	)	[2]	—
Interest expense and other charges, net	(45,899		)	(10,773	)	(9,779	)	—	81		[1]	(66,370		)
Allowance for borrowed funds used during construction	1,967			215		275		—	—			2,457
Income before income taxes	190,622			33,581		35,848		—	(42,920	)		217,131
Income taxes	53,828			12,292		13,302		—	—			79,422
Net income	136,794			21,289		22,546		—	(42,920	)		137,709
Preferred stock dividends of subsidiaries	—			534		381		—	—			915
Net income attributable to Hawaiian Electric	136,794			20,755		22,165		—	(42,920	)		136,794
Preferred stock dividends of Hawaiian Electric	1,080			—		—		—	—			1,080
Net income for common stock	$	135,714		20,755		22,165		—	(42,920	)		$	135,714

Consolidating statement of comprehensive income

Year ended December 31, 2015

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Net income for common stock	$	135,714		20,755		22,165		—	(42,920	)		$	135,714
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Net gains (losses) arising during the period, net of tax benefits	5,638			(2,710	)	(1,352	)	—	4,062		[1]	5,638
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	20,381			2,728		2,503		—	(5,231	)	[1]	20,381
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(25,139		)	104		(1,107	)	—	1,003		[1]	(25,139		)
Other comprehensive income, net of tax benefits	880			122		44		—	(166	)		880
Comprehensive income attributable to common shareholder	$	136,594		20,877		22,209		—	(43,086	)		$	136,594

Consolidating statement of income

Year ended December 31, 2014

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Revenues	$	2,142,245		422,200		422,965		—	(87	)	[1]	$	2,987,323
Expenses
Fuel oil	821,246			117,215		193,224		—	—			1,131,685
Purchased power	537,821			123,226		60,961		—	—			722,008
Other operation and maintenance	283,532			65,471		61,609		—	—			410,612
Depreciation	109,204			35,904		21,279		—	—			166,387
Taxes, other than income taxes	201,426			39,521		39,916		—	—			280,863
Impairment of utility assets	—			—		—		—	—			—
Total expenses	1,953,229			381,337		376,989		—	—			2,711,555
Operating income	189,016			40,863		45,976		—	(87	)		275,768
Allowance for equity funds used    during construction	6,085			472		214		—	—			6,771
Equity in earnings of subsidiaries	40,964			—		—		—	(40,964	)	[2]	—
Interest expense and other charges, net	(44,041		)	(11,030	)	(9,773	)		87		[1]	(64,757		)
Allowance for borrowed funds used during construction	2,306			182		91		—	—			2,579
Income before income taxes	194,330			30,487		36,508		—	(40,964	)		220,361
Income taxes	55,609			11,264		13,852		—	—			80,725
Net income	138,721			19,223		22,656		—	(40,964	)		139,636
Preferred stock dividends of subsidiaries	—			534		381		—	—			915
Net income attributable to Hawaiian Electric	138,721			18,689		22,275		—	(40,964	)		138,721
Preferred stock dividends of Hawaiian Electric	1,080			—		—		—	—			1,080
Net income for common stock	$	137,641		18,689		22,275		—	(40,964	)		$	137,641

Consolidating statement of comprehensive income (loss)

Year ended December 31, 2014

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Net income for common stock	$	137,641		18,689		22,275		—	(40,964	)		$	137,641
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Net gains arising during the period, net of taxes	(218,608		)	(28,725	)	(29,352	)	—	58,077		[1]	(218,608		)
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	10,212			1,270		1,090		—	(2,360	)	[1]	10,212
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits	207,833			27,437		28,257		—	(55,694	)	[1]	207,833
Other comprehensive loss, net of tax benefits	(563		)	(18	)	(5	)	—	23			(563		)
Comprehensive income attributable to common shareholder	$	137,078		18,671		22,270		—	(40,941	)		$	137,078

Consolidating statement of income

Year ended December 31, 2013

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Revenues	$	2,124,174		431,517		424,603		—		(122	)	[1]	$	2,980,172
Expenses
Fuel oil	851,365			125,516		208,671		—		—			1,185,552
Purchased power	527,839			128,368		54,474		—		—			710,681
Other operation and maintenance	283,768			61,418		58,081		3		—			403,270
Depreciation	99,738			34,188		20,099		—		—			154,025
Taxes, other than income taxes	200,962			40,092		40,077		—		—			281,131
Impairment of utility assets	—			—		—		—		—			—
Total expenses	1,963,672			389,582		381,402		3		—			2,734,659
Operating income (loss)	160,502			41,935		43,201		(3	)	(122	)		245,513
Allowance for equity funds used    during construction	4,495			643		423		—		—			5,561
Equity in earnings of subsidiaries	41,410			—		—		—		(41,410	)	[2]	—
Interest expense and other charges, net	(39,107		)	(11,341	)	(8,953	)	—		122		[1]	(59,279		)
Allowance for borrowed funds used during construction	1,814			263		169		—		—			2,246
Income (loss) before income taxes	169,114			31,500		34,840		(3	)	(41,410	)		194,041
Income taxes	45,105			10,830		13,182		—		—			69,117
Net income (loss)	124,009			20,670		21,658		(3	)	(41,410	)		124,924
Preferred stock dividends of subsidiaries	—			534		381		—		—			915
Net income (loss) attributable to Hawaiian Electric	124,009			20,136		21,277		(3	)	(41,410	)		124,009
Preferred stock dividends of Hawaiian Electric	1,080			—		—		—		—			1,080
Net income (loss) for common stock	$	122,929		20,136		21,277		(3	)	(41,410	)		$	122,929

Consolidating statement of comprehensive income (loss)

Year ended December 31, 2013

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Net income (loss) for common stock	$	122,929		20,136		21,277		(3	)	(41,410	)		$	122,929
Other comprehensive income, net of taxes:
Retirement benefit plans:
Net losses arising during the period, net of tax benefits	203,479			30,542		27,820		—		(58,362	)	[1]	203,479
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	20,694			2,880		2,557		—		(5,437	)	[1]	20,694
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits	(222,595		)	(33,277	)	(30,254	)	—		63,531		[1]	(222,595		)
Other comprehensive income, net of taxes	1,578			145		123		—		(268	)		1,578
Comprehensive income (loss) attributable to common shareholder	$	124,507		20,281		21,400		(3	)	(41,678	)		$	124,507

Consolidating balance sheet

December 31, 2015

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Assets
Property, plant and equipment
Utility property, plant and equipment
Land	$	43,557		6,219		3,016		—	—			$	52,792
Plant and equipment	4,026,079			1,212,195		1,077,424		—	—			6,315,698
Less accumulated depreciation	(1,316,467		)	(486,028	)	(463,509	)	—	—			(2,266,004		)
Construction in progress	147,979			11,455		15,875		—	—			175,309
Utility property, plant and equipment, net	2,901,148			743,841		632,806		—	—			4,277,795
Nonutility property, plant and equipment, less accumulated depreciation	5,659			82		1,531		—	—			7,272
Total property, plant and equipment, net	2,906,807			743,923		634,337		—	—			4,285,067
Investment in wholly-owned subsidiaries, at equity	556,528			—		—		—	(556,528	)	[2]	0
Current assets
Cash and equivalents	16,281			2,682		5,385		101	—			24,449
Advances to affiliates	—			15,500		7,500		—	(23,000	)	[1]	—
Customer accounts receivable, net	93,515			20,508		18,755		—	—			132,778
Accrued unbilled revenues, net	60,080			12,531		11,898		—	—			84,509
Other accounts receivable, net	16,421			1,275		1,674		—	(8,962	)	[1]	10,408
Fuel oil stock, at average cost	49,455			8,310		13,451		—	—			71,216
Materials and supplies, at average cost	30,921			6,865		16,643		—	—			54,429
Prepayments and other	25,505			9,091		2,295		—	(251	)	[3]	36,640
Regulatory assets	63,615			4,501		4,115		—	—			72,231
Total current assets	355,793			81,263		81,716		101	(32,213	)		486,660
Other long-term assets
Regulatory assets	608,957			114,562		100,981		—	—			824,500
Unamortized debt expense	5,742			1,494		1,105		—	—			8,341
Other	47,731			14,693		13,062		—	—			75,486
Total other long-term assets	662,430			130,749		115,148		—	—			908,327
Total assets	$	4,481,558		955,935		831,201		101	(588,741	)		$	5,680,054
Capitalization and liabilities
Capitalization
Common stock equity	$	1,728,325		292,702		263,725		101	(556,528	)	[2]	$	1,728,325
Cumulative preferred stock–not subject to mandatory redemption	22,293			7,000		5,000		—	—			34,293
Long-term debt, net	880,546			215,000		191,000		—	—			1,286,546
Total capitalization	2,631,164			514,702		459,725		101	(556,528	)		3,049,164
Current liabilities
Short-term borrowings-affiliate	23,000			—		—		—	(23,000	)	[1]	—
Accounts payable	84,631			17,702		12,513		—	—			114,846
Interest and preferred dividends payable	15,747			4,255		3,113		—	(4	)	[1]	23,111
Taxes accrued	131,668			30,342		29,325		—	(251	)	[3]	191,084
Regulatory liabilities	—			1,030		1,174		—	—			2,204
Other	41,083			8,760		13,194		—	(8,958	)	[1]	54,079
Total current liabilities	296,129			62,089		59,319		—	(32,213	)		385,324
Deferred credits and other liabilities
Deferred income taxes	466,133			100,681		87,706		—	286		[1]	654,806
Regulatory liabilities	254,033			84,623		30,683		—	—			369,339
Unamortized tax credits	54,078			15,406		14,730		—	—			84,214
Defined benefit pension and other postretirement benefit plans liability	409,021			69,893		74,060		—	—			552,974
Other	51,273			13,243		13,916		—	(286	)	[1]	78,146
Total deferred credits and other liabilities	1,234,538			283,846		221,095		—	—			1,739,479
Contributions in aid of construction	319,727			95,298		91,062		—	—			506,087
Total capitalization and liabilities	$	4,481,558		955,935		831,201		101	(588,741	)		$	5,680,054

Consolidating balance sheet

December 31, 2014

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Assets
Property, plant and equipment
Utility property, plant and equipment
Land	$	43,819		5,464		3,016		—	—			$	52,299
Plant and equipment	3,782,438			1,179,032		1,048,012		—	—			6,009,482
Less accumulated depreciation	(1,253,866		)	(473,933	)	(447,711	)	—	—			(2,175,510		)
Construction in progress	134,376			12,421		11,819		—	—			158,616
Utility property, plant and equipment, net	2,706,767			722,984		615,136		—	—			4,044,887
Nonutility property, plant and equipment, less accumulated depreciation	4,950			82		1,531		—	—			6,563
Total property, plant and equipment, net	2,711,717			723,066		616,667		—	—			4,051,450
Investment in wholly-owned subsidiaries, at equity	538,639			—		—		—	(538,639	)	[2]	—
Current assets
Cash and equivalents	12,416			612		633		101	—			13,762
Advances to affiliates	16,100			—		—		—	(16,100	)	[1]	—
Customer accounts receivable, net	111,462			24,222		22,800		—	—			158,484
Accrued unbilled revenues, net	103,072			15,926		18,376		—	—			137,374
Other accounts receivable, net	9,980			981		2,246		—	(8,924	)	[1]	4,283
Fuel oil stock, at average cost	74,515			13,800		17,731		—	—			106,046
Materials and supplies, at average cost	33,154			6,664		17,432		—	—			57,250
Prepayments and other	20,231			10,137		3,575		—	(475	)	[1], [3]	33,468
Regulatory assets	58,550			6,745		6,126		—	—			71,421
Total current assets	439,480			79,087		88,919		101	(25,499	)		582,088
Other long-term assets
Regulatory assets	623,784			107,454		102,788		—	(183	)	[1]	833,843
Unamortized debt expense	5,640			1,438		1,245		—	—			8,323
Other	53,106			15,366		13,366		—	—			81,838
Total other long-term assets	682,530			124,258		117,399		—	(183	)		924,004
Total assets	$	4,372,366		926,411		822,985		101	(564,321	)		$	5,557,542
Capitalization and liabilities
Capitalization
Common stock equity	$	1,682,144		281,846		256,692		101	(538,639	)	[2]	$	1,682,144
Cumulative preferred stock–not subject to mandatory redemption	22,293			7,000		5,000		—	—			34,293
Long-term debt, net	830,546			190,000		186,000		—	—			1,206,546
Total capitalization	2,534,983			478,846		447,692		101	(538,639	)		2,922,983
Current liabilities
Short-term borrowings-affiliate	—			10,500		5,600		—	(16,100	)	[1]	—
Accounts payable	122,433			23,728		17,773		—	—			163,934
Interest and preferred dividends payable	15,407			3,989		2,931		—	(11	)	[1]	22,316
Taxes accrued	176,339			37,548		36,807		—	(292	)	[3]	250,402
Regulatory liabilities	191			—		441		—	—			632
Other	45,369			9,587		15,804		—	(9,096	)	[1]	61,664
Total current liabilities	359,739			85,352		79,356		—	(25,499	)		498,948
Deferred credits and other liabilities
Deferred income taxes	407,979			91,924		73,536		—	—			573,439
Regulatory liabilities	236,727			77,707		29,966		—	(183	)	[1]	344,217
Unamortized tax credits	49,865			14,902		14,725		—	—			79,492
Defined benefit pension and other postretirement benefit plans liability	446,888			72,547		75,960		—	—			595,395
Other	52,446			10,658		13,532		—	—			76,636
Total deferred credits and other liabilities	1,193,905			267,738		207,719		—	(183	)		1,669,179
Contributions in aid of construction	283,739			94,475		88,218		—	—			466,432
Total capitalization and liabilities	$	4,372,366		926,411		822,985		101	(564,321	)		$	5,557,542

Consolidating statements of changes in common stock equity

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments		Hawaiian Electric Consolidated
Balance, December 31, 2012	$	1,472,136		268,908		228,927		104		(497,939	)	$	1,472,136
Net income (loss) for common stock	122,929			20,136		21,277		(3	)	(41,410	)	122,929
Other comprehensive income, net of tax benefits	1,578			145		123		—		(268	)	1,578
Issuance of common stock, net of expenses	78,499			—		12,461		—		(12,461	)	78,499
Common stock dividends	(81,578		)	(14,387	)	(14,017	)	—		28,404		(81,578		)
Balance, December 31, 2013	$	1,593,564		274,802		248,771		101		(523,674	)	$	1,593,564
Net income for common stock	137,641			18,689		22,275		—		(40,964	)	137,641
Other comprehensive loss, net of taxes	(563		)	(18	)	(5	)	—		23		(563		)
Issuance of common stock, net of expenses	39,994			—		—		—		—		39,994
Common stock dividends	(88,492		)	(11,627	)	(14,349	)	—		25,976		(88,492		)
Balance, December 31, 2014	$	1,682,144		281,846		256,692		101		(538,639	)	$	1,682,144
Net income for common stock	135,714			20,755		22,165		—		(42,920	)	135,714
Other comprehensive income, net of tax benefits	880			122		44		—		(166	)	880
Common stock issuance expenses	(8		)	—		(1	)	—		1		(8		)
Common stock dividends	(90,405		)	(10,021	)	(15,175	)	—		25,196		(90,405		)
Balance, December 31, 2015	$	1,728,325		292,702		263,725		101		(556,528	)	$	1,728,325

Consolidating statement of cash flows

Year ended December 31, 2015

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Cash flows from operating activities
Net income	$	136,794		21,289		22,546		—	(42,920	)	[2]	$	137,709
Adjustments to reconcile net income to net cash provided by operating activities
Equity in earnings	(43,020		)	—		—		—	42,920		[2]	(100		)
Common stock dividends received from subsidiaries	25,296			—		—		—	(25,196	)	[2]	100
Depreciation of property, plant and equipment	117,682			37,250		22,448		—	—			177,380
Other amortization	4,678			2,124		2,137		—	—			8,939
Impairment of utility assets	4,573			724		724		—	—			6,021
Other	4,403			(2,476	)	(255	)	—	—			1,672
Increase in deferred income taxes	53,338			8,295		13,707		—	286		[1]	75,626
Change in tax credits, net	4,284			527		33		—	—			4,844
Allowance for equity funds used during construction	(5,641		)	(604	)	(683	)	—	—			(6,928		)
Changes in assets and liabilities:
Decrease in accounts receivable	15,652			3,420		4,617		—	38		[1]	23,727
Decrease in accrued unbilled revenues	29,733			4,593		5,767		—	—			40,093
Decrease in fuel oil stock	25,060			5,490		4,280		—	—			34,830
Decrease (increase) in materials and supplies	2,233			(201	)	789		—	—			2,821
Decrease (increase) in regulatory assets	(20,356		)	(3,930	)	104		—	—			(24,182		)
Decrease in accounts payable	(42,751		)	(6,425	)	(5,379	)	—	—			(54,555		)
Change in prepaid and accrued income taxes and revenue taxes	(50,382		)	(6,166	)	(6,548	)	—	—			(63,096		)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	870			(161	)	416		—	—			1,125
Change in other assets and liabilities	(24,197		)	(3,545	)	(4,554	)	—	(324	)	[1]	(32,620		)
Net cash provided by operating activities	238,249			60,204		60,149		—	(25,196	)		333,406
Cash flows from investing activities
Capital expenditures	(267,621		)	(48,645	)	(33,895	)	—	—			(350,161		)
Contributions in aid of construction	35,955			2,160		2,124		—	—			40,239
Advances from affiliates	16,100			(15,500	)	(7,500	)	—	6,900		[1]	—
Other	924			132		84		—	—			1,140
Net cash used in investing activities	(214,642		)	(61,853	)	(39,187	)	—	6,900			(308,782		)
Cash flows from financing activities
Common stock dividends	(90,405		)	(10,021	)	(15,175	)	—	25,196		[2]	(90,405		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,080		)	(534	)	(381	)	—	—			(1,995		)
Proceeds from issuance of long-term debt	50,000			25,000		5,000		—	—			80,000
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	23,000			(10,500	)	(5,600	)	—	(6,900	)	[2]	—
Other	(1,257		)	(226	)	(54	)	—	—			(1,537		)
Net cash (used in) provided by financing activities	(19,742		)	3,719		(16,210	)	—	18,296			(13,937		)
Net increase in cash and cash equivalents	3,865			2,070		4,752		—	—			10,687
Cash and cash equivalents, January 1	12,416			612		633		101	—			13,762
Cash and cash equivalents, December 31	$	16,281		2,682		5,385		101	—			$	24,449

Consolidating statement of cash flows

Year ended December 31, 2014

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Cash flows from operating activities
Net income	$	138,721		19,223		22,656		—	(40,964	)	[2]	$	139,636
Adjustments to reconcile net income to net cash provided by operating activities
Equity in earnings	(41,064		)	—		—		—	40,964		[2]	(100		)
Common stock dividends received from subsidiaries	26,076			—		—		—	(25,976	)	[2]	100
Depreciation of property, plant and equipment	109,204			35,904		21,279		—	—			166,387
Other amortization	4,535			2,926		2,436		—	—			9,897
Impairment of utility assets	1,866			—		—		—	—			1,866
Other	758			—		—		—	—			758
Increase in deferred income taxes	56,901			12,083		13,963		—	—			82,947
Change in tax credits, net	4,998			680		384		—	—			6,062
Allowance for equity funds used during construction	(6,085		)	(472	)	(214	)	—	—			(6,771		)
Change in cash overdraft	—			—		(1,038	)	—	—			(1,038		)
Changes in assets and liabilities:
Decrease in accounts receivable	16,213			7,150		3,483		—	(103	)	[1]	26,743
Decrease in accrued unbilled revenues	4,680			1,174		896		—	—			6,750
Decrease in fuel oil stock	25,098			378		2,565		—	—			28,041
Decrease (increase) in materials and supplies	2,357			219		(2,648	)	—	—			(72		)
Decrease (increase) in regulatory assets	(14,620		)	(3,357	)	977		—	—			(17,000		)
Decrease in accounts payable	(56,044		)	(6,645	)	(2,838	)	—	—			(65,527		)
Change in prepaid and accrued income taxes and revenue taxes	(4,166		)	(3,251	)	3,381		—	—			(4,036		)
Decrease in defined benefit pension and other postretirement benefit plans liability	(562		)	—		(399	)	—	—			(961		)
Change in other assets and liabilities	(50,180		)	(12,907	)	(3,703	)	—	103		[1]	(66,687		)
Net cash provided by operating activities	218,686			53,105		61,180		—	(25,976	)		306,995
Cash flows from investing activities
Capital expenditures	(237,970		)	(49,895	)	(48,814	)	—	—			(336,679		)
Contributions in aid of construction	30,021			7,695		4,090		—	—			41,806
Advances from affiliates	(9,261		)	1,000		—		—	8,261		[1]	—
Other	604			492		68		—	—			1,164
Investment in consolidated subsidiary	—			—		—		—	—			—
Net cash used in investing activities	(216,606		)	(40,708	)	(44,656	)	—	8,261			(293,709		)
Cash flows from financing activities
Common stock dividends	(88,492		)	(11,627	)	(14,349	)	—	25,976		[2]	(88,492		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,080		)	(534	)	(381	)	—	—			(1,995		)
Proceeds from the issuance of common stock	40,000			—		—		—	—			40,000
Repayment of long-term debt	—			(11,400	)	—		—	—			(11,400		)
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	(1,000		)	10,500		(1,239	)	—	(8,261	)	[1]	—
Other	(337		)	(50	)	(75	)	—	—			(462		)
Net cash used in financing activities	(50,909		)	(13,111	)	(16,044	)	—	17,715			(62,349		)
Net increase (decrease) in cash and cash equivalents	(48,829		)	(714	)	480		—	—			(49,063		)
Cash and cash equivalents, January 1	61,245			1,326		153		101	—			62,825
Cash and cash equivalents, December 31	$	12,416		612		633		101	—			$	13,762

Consolidating statement of cash flows

Year ended December 31, 2013

(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Cash flows from operating activities
Net income (loss)	$	124,009		20,670		21,658		(3	)	(41,410	)	[2]	$	124,924
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Equity in earnings	(41,510		)	—		—		—		41,410		[2]	(100		)
Common stock dividends received from subsidiaries	28,505			—		—		—		(28,405	)	[2]	100
Depreciation of property, plant and equipment	99,738			34,188		20,099		—		—			154,025
Other amortization	2,549			2,360		2,825		—		—			7,734
Increase in deferred income taxes	41,409			10,569		12,529		—		—			64,507
Change in tax credits, net	5,152			818		1,047		—		—			7,017
Allowance for equity funds used during construction	(4,495		)	(643	)	(423	)	—		—			(5,561		)
Change in cash overdraft	—			—		1,038		—		—			1,038
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	49,974			(1,459	)	1,178		—		(248	)	[1]	49,445
Decrease (increase) in accrued unbilled revenues	(7,152		)	(2,707	)	33		—		—			(9,826		)
Decrease in fuel oil stock	23,563			1,307		2,462		—		—			27,332
Increase in materials and supplies	(5,598		)	(1,547	)	(814	)	—		—			(7,959		)
Increase in regulatory assets	(46,047		)	(9,237	)	(10,177	)	—		—			(65,461		)
Increase (decrease) in accounts payable	18,527			1,525		(5,321	)	—		—			14,731
Change in prepaid and accrued income taxes and revenue taxes	4,632			(4,114	)	(2,546	)	—		—			(2,028		)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	2,325			(1	)	(84	)	—		—			2,240
Change in other assets and liabilities	(20,613		)	(6,894	)	(8,034	)	—		248		[1]	(35,293		)
Net cash provided by (used in) operating activities	274,968			44,835		35,470		(3	)	(28,405	)		326,865
Cash flows from investing activities
Capital expenditures	(262,562		)	(58,416	)	(57,066	)	—		—			(378,044		)
Contributions in aid of construction	21,686			7,590		2,884		—		—			32,160
Advances from affiliates	2,561			17,050		—		—		(19,611	)	[1]	—
Other	677			21		209		—		—			907
Investment in consolidated subsidiary	(12,461		)	—		—		—		12,461		[2]	—
Net cash used in investing activities	(250,099		)	(33,755	)	(53,973	)	—		(7,150	)		(344,977		)
Cash flows from financing activities
Common stock dividends	(81,578		)	(14,388	)	(14,017	)	—		28,405		[2]	(81,578		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,080		)	(534	)	(381	)	—		—			(1,995		)
Proceeds from the issuance of common stock	78,500			—		12,461		—		(12,461	)	[2]	78,500
Proceeds from the issuance of long-term debt	140,000			56,000		40,000		—		—			236,000
Repayment of long-term debt	(90,000		)	(56,000	)	(20,000	)	—		—			(166,000		)
Net decrease in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	(17,050		)	—		(2,561	)	—		19,611		[1]	—
Other	(681		)	(273	)	(195	)	—		—			(1,149		)
Net cash provided by (used in) financing activities	28,111			(15,195	)	15,307		—		35,555			63,778
Net increase (decrease) in cash and cash equivalents	52,980			(4,115	)	(3,196	)	(3	)	—			45,666
Cash and cash equivalents, January 1	8,265			5,441		3,349		104		—			17,159
Cash and cash equivalents, December 31	61,245			1,326		153		101		—			62,825

Explanation of consolidating adjustments on consolidating schedules:

[1] Eliminations of intercompany receivables and payables and other intercompany transactions.

[2] Elimination of investment in subsidiaries, carried at equity.

[3] Reclassification of accrued income taxes for financial statement presentation.