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Electric utility segment (Details 2) (USD $)
 12 Months Ended 0 Months Ended 1 Months Ended 6 Months Ended 12 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended 0 Months Ended 1 Months Ended 12 Months Ended 0 Months Ended 1 Months Ended 3 Months Ended
Dec. 31, 2013
agreement
May 31, 2013
Hawaiian Electric Company, Inc (HECO)
Feb. 21, 2014
Hawaiian Electric Company, Inc (HECO)
project
Nov. 30, 2013
Hawaiian Electric Company, Inc (HECO)
project
Jun. 30, 2013
Hawaiian Electric Company, Inc (HECO)
project
Apr. 30, 2013
Hawaiian Electric Company, Inc (HECO)
Dec. 31, 2013
Hawaiian Electric Company, Inc (HECO)
project
Dec. 31, 2013
Hawaiian Electric Company, Inc (HECO)
agreement
Dec. 31, 2012
Hawaiian Electric Company, Inc (HECO)
Dec. 31, 2011
Hawaiian Electric Company, Inc (HECO)
Feb. 16, 2012
Hawaiian Electric Company, Inc (HECO)
generation_unit
Dec. 31, 2013
Hawaii Electric Light Company, Inc. (HELCO)
Dec. 31, 2012
Hawaii Electric Light Company, Inc. (HELCO)
Dec. 31, 2011
Hawaii Electric Light Company, Inc. (HELCO)
Sep. 30, 2013
Maui Electric Company, Limited (MECO)
Dec. 31, 2013
Maui Electric Company, Limited (MECO)
Dec. 31, 2012
Maui Electric Company, Limited (MECO)
Dec. 31, 2011
Maui Electric Company, Limited (MECO)
Mar. 31, 2012
Maui Electric Company, Limited (MECO)
Oct. 19, 2012
Hawaiian Electric Company, Inc. and Subsidiaries
Oct. 31, 2013
Hawaiian Electric Company, Inc. and Subsidiaries
Apr. 30, 2013
Hawaiian Electric Company, Inc. and Subsidiaries
bid
May 31, 2012
Hawaiian Electric Company, Inc. and Subsidiaries
MW
Feb. 28, 2012
Hawaiian Electric Company, Inc. and Subsidiaries
Nov. 30, 2011
Hawaiian Electric Company, Inc. and Subsidiaries
Dec. 31, 2009
Hawaiian Electric Company, Inc. and Subsidiaries
Dec. 31, 2013
Hawaiian Electric Company, Inc. and Subsidiaries
MW
Dec. 31, 2012
Hawaiian Electric Company, Inc. and Subsidiaries
MW
Dec. 31, 2011
Hawaiian Electric Company, Inc. and Subsidiaries
Feb. 07, 2014
Hawaiian Electric Company, Inc. and Subsidiaries
Subsequent Event [Member]
Feb. 07, 2014
Hawaiian Electric Company, Inc. and Subsidiaries
Subsequent Event [Member]
Minimum
Feb. 07, 2014
Hawaiian Electric Company, Inc. and Subsidiaries
Subsequent Event [Member]
Maximum
Mar. 31, 2012
East Oahu Transmission Project Phase 1
Hawaiian Electric Company, Inc. and Subsidiaries
Dec. 31, 2011
East Oahu Transmission Project Phase 1
Hawaiian Electric Company, Inc. and Subsidiaries
Fuel contracts                                                                    
Estimated cost of minimum purchase within 2014 year                                                     $ 900,000,000              
Estimated cost of minimum purchase in 2015 year                                                     700,000,000              
Estimated cost of minimum purchase in 2016 year                                                     400,000,000              
Cost of purchases                                                     1,100,000,000 1,300,000,000 1,300,000,000          
Power purchase agreements                                                                    
Number of power purchase agreements (PPAs) 6             6                                                    
Power purchase capacity excluding agreements with smaller IPPs (in megawatts)                                                     567              
Purchased power               527,839,000 540,802,000 522,503,000   128,368,000 145,386,000 137,453,000   54,474,000 38,052,000 29,696,000                 710,681,000 724,240,000 689,652,000          
Expected fixed capacity charges per year for 2014 through 2018, minimum                                                     100,000,000              
Expected fixed capacity charges from 2019 through 2033                                                     600,000,000              
Renewable projects                                                                    
Gross plant cost agreed to be written-off in lieu of regulatory audit                                                                 9,500,000  
After-tax charge to net income due to settlement agreement                                                                   6,000,000
Additional increase in test year rate case                                                                 5,000,000  
Deferred cost to be recovered subject to PUC approval                                                   3,900,000                
Additional deferred cost to be recovered subject to PUC approval                                                 555,000                  
Integration from renewable energy sources (in megawatts)                                                       200            
Maximum deferred cost recovery                                               5,890,000                    
Integration from firm renewable geothermal dispatchable energy (in megawatts)                                             50                      
Number of bids received                                           6                        
Environmental regulation                                                                    
Additional accrued investigation and estimated cleanup costs                               3,600,000     3,100,000                              
Percentage of reduction in GHG emissions by 2020                                       25.00% 16.00%                          
Utilities Deferred Cost Accrual Rate Per Annum           1.75%                                                        
Percentage of renewable portfolio standard to be achieved by 2030                                                   40.00%                
Period for Deferred Cost Recovery           3 years                                                        
Number of Projects for Bidding Subject to PUC Approval       2 5                                                          
Number of PV Projects for Bidding Subject to PUC Approval       6 4                                                          
Number of Wind Projects for Bidding Subject to PUC Approval         1                                                          
Number of Projects for Bidding Subsequently Withdrawn             2                                                      
Number of Projects for Bidding Granted Waivers     3                                                              
Number of Generating Units Subject to New Regulation                     14                                              
Changes in the asset retirement obligation liability                                                                    
Balance at the beginning of the period                                                     48,431,000 50,871,000            
Accretion expense                                                     1,263,000 1,563,000            
Liabilities incurred                                                     0 0            
Liabilities settled                                                     (5,672,000) (4,003,000)            
Revisions in estimated cash flows                                                     (916,000) 0            
Balance at the end of the period                                                     43,106,000 48,431,000 50,871,000          
Public Utilities, Baseline Capital Project Value to Determine Revenue Adjustment                                                     2,500,000              
Public Utilities, Proposed Rate Base Adjustment, Percent of Previous Rate Base Adjustment                                                           90.00%        
Public Utilities, Proposed Effective Interest Rate, Revenue Balancing Account                                                             1.25% 3.25%    
Public Utilites, Effective Interest Rate, Revenue Balancing Account                                                     6.00%              
Public Utilities, Regulatory Response Period                                                           120 days        
Revenues   5,300,000           2,124,174,000 2,228,233,000 2,114,066,000   431,517,000 441,013,000 444,891,000   424,603,000 440,270,000 419,760,000                 2,980,172,000 3,109,439,000 2,978,690,000          
Lower ROACE                             4,000,000                                      
Customer Information System expenses                             300,000                                      
Pension and OPEB expense based on 3-year average                             1,500,000                                      
Integrated resource planning expenses                             900,000                                      
Operational and Renewable Energy Integration study costs                             1,100,000                                      
Total adjustment                             7,800,000 7,800,000                                    
Stipulated Return on Common Equity Percentage                               10.00%                                    
Return on Common Equity Percentage Approved by PUC                               9.00%                                    
Return on Common Equity Percentage Approved by PUC Allocated to Lower Interest Rate                               0.50%                                    
Return on Common Equity Percentage Approved by PUC Allocated for OverCurtailment of Renewable Energy                               0.50%                                    
Period as Basis for Calculation of Average Pension Cost                               3 years                                    
Deferred IRP Cost Allowed by PUC Order                               900,000                                    
Charge Recorded Net of Revenue Taxes                               7,600,000                                    
Amount to be Refunded to Customers                               9,700,000                                    
Increase(Decrease) in Employee Benefit Expenses                               1,800,000                                    
Deferred IRP Cost Allowed By PUC Order, Reclassified To Deferred Accounts                             $ 700,000