Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2013
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Exact Name of Registrant as
Commission
I.R.S. Employer
Specified in Its Charter
File Number
Identification No.
HAWAIIAN ELECTRIC INDUSTRIES, INC.
1-8503
99-0208097
and Principal Subsidiary
HAWAIIAN ELECTRIC COMPANY, INC.
1-4955
99-0040500
State of Hawaii
(State or other jurisdiction of incorporation or organization)
Hawaiian Electric Industries, Inc. – 1001 Bishop Street, Suite 2900, Honolulu, Hawaii 96813
Hawaiian Electric Company, Inc. – 900 Richards Street, Honolulu, Hawaii 96813
(Address of principal executive offices and zip code)
Hawaiian Electric Industries, Inc. – (808) 543-5662
Hawaiian Electric Company, Inc. – (808) 543-7771
(Registrant’s telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Hawaiian Electric Industries, Inc. Yes x No o
Hawaiian Electric Company, Inc. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Hawaiian Electric Industries, Inc. Yes o No x
Hawaiian Electric Company, Inc. Yes o No x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Hawaiian Electric Industries, Inc.
Large accelerated filer x
Hawaiian Electric Company, Inc.
Large accelerated filer o
Accelerated filer o
Non-accelerated filer o
Non-accelerated filer x
(Do not check if a smaller reporting company)
Smaller reporting company o
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.
Class of Common Stock
Outstanding July 31, 2013
Hawaiian Electric Industries, Inc. (Without Par Value)
99,128,257 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)
14,665,264 Shares (not publicly traded)
Hawaiian Electric Industries, Inc. and Subsidiaries
Hawaiian Electric Company, Inc. and Subsidiaries
Form 10-Q—Quarter ended June 30, 2013
INDEX
Page No.
ii
Glossary of Terms
iv
Forward-Looking Statements
PART I. FINANCIAL INFORMATION
1
Item 1.
Financial Statements
Consolidated Statements of Income - three and six months ended June 30, 2013 and 2012
2
Consolidated Statements of Comprehensive Income - three and six months ended June 30, 2013 and 2012
3
Consolidated Balance Sheets - June 30, 2013 and December 31, 2012
4
Consolidated Statements of Changes in Shareholders’ Equity - six months ended June 30, 2013 and 2012
5
Consolidated Statements of Cash Flows - six months ended June 30, 2013 and 2012
6
Notes to Consolidated Financial Statements
30
31
32
Consolidated Statements of Changes in Common Stock Equity - six months ended June 30, 2013 and 2012
33
34
54
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
HEI Consolidated
59
Electric Utilities
68
Bank
78
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
79
Item 4.
Controls and Procedures
PART II.
OTHER INFORMATION
80
Legal Proceedings
Item 1A.
Risk Factors
Item 5.
Other Information
81
Item 6.
Exhibits
82
Signatures
i
GLOSSARY OF TERMS
Terms
Definitions
AFTAP
Adjusted Funding Target Attainment Percentage
AFUDC
Allowance for funds used during construction
AOCI
Accumulated other comprehensive income/(loss)
ARO
Asset retirement obligation
ASB
American Savings Bank, F.S.B., a wholly-owned subsidiary of American Savings Holdings, Inc.
ASHI
American Savings Holdings, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.
ASU
Accounting Standards Update
CIP CT-1
Campbell Industrial Park 110 MW combustion turbine No. 1
CIS
Customer Information System
Company
Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc. and its subsidiaries (listed under HECO); American Savings Holdings, Inc. and its subsidiary, American Savings Bank, F.S.B.; HEI Properties, Inc.; Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive financing entities); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.).
Consumer Advocate
Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii
DBEDT
State of Hawaii Department of Business, Economic Development and Tourism
D&O
Decision and order
Dodd-Frank Act
Dodd-Frank Wall Street Reform and Consumer Protection Act
DOH
Department of Health of the State of Hawaii
DRIP
HEI Dividend Reinvestment and Stock Purchase Plan
DSM
Demand-side management
ECAC
Energy cost adjustment clauses
EIP
2010 Equity and Incentive Plan
EGU
Electrical generating unit
Energy Agreement
Agreement dated October 20, 2008 and signed by the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and HECO, for itself and on behalf of its electric utility subsidiaries committing to actions to develop renewable energy and reduce dependence on fossil fuels in support of the HCEI
EPA
Environmental Protection Agency — federal
EPS
Earnings per share
ERISA
Employee Retirement Income Security Act of 1974, as amended
EVE
Economic value of equity
Exchange Act
Securities Exchange Act of 1934
FASB
Financial Accounting Standards Board
FDIC
Federal Deposit Insurance Corporation
federal
U.S. Government
FHLB
Federal Home Loan Bank
FHLMC
Federal Home Loan Mortgage Corporation
FNMA
Federal National Mortgage Association
FRB
Federal Reserve Board
GLOSSARY OF TERMS, continued
GAAP
U.S. generally accepted accounting principles
GHG
Greenhouse gas
GNMA
Government National Mortgage Association
HCEI
Hawaii Clean Energy Initiative
HECO
Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, HECO Capital Trust III (unconsolidated financing subsidiary), Renewable Hawaii, Inc. and Uluwehiokama Biofuels Corp.
HEI
Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., American Savings Holdings, Inc., HEI Properties, Inc., Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.)
HEIRSP
Hawaiian Electric Industries Retirement Savings Plan
HELCO
Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
HPOWER
City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
IPP
Independent power producer
IRP
Integrated resource planning
Kalaeloa
Kalaeloa Partners, L.P.
KW
Kilowatt
KWH
Kilowatthour
LTIP
Long-term incentive plan
MAP-21
Moving Ahead for Progress in the 21st Century Act
MECO
Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.
MW
Megawatt/s (as applicable)
NII
Net interest income
NQSO
Nonqualified stock option
O&M
Other operation and maintenance
OCC
Office of the Comptroller of the Currency
OPEB
Postretirement benefits other than pensions
PPA
Power purchase agreement
PPAC
Purchased power adjustment clause
PUC
Public Utilities Commission of the State of Hawaii
RAM
Revenue adjustment mechanism
RBA
Revenue balancing account
RFP
Request for proposal
REIP
Renewable Energy Infrastructure Program
RHI
Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc.
ROACE
Return on average common equity
RORB
Return on average rate base
RPS
Renewable portfolio standard
SAR
Stock appreciation right
SEC
Securities and Exchange Commission
See
Means the referenced material is incorporated by reference
SOIP
1987 Stock Option and Incentive Plan, as amended
TDR
Troubled debt restructuring
UBC
Uluwehiokama Biofuels Corp., a non-regulated subsidiary of Hawaiian Electric Company, Inc.
VIE
Variable interest entity
iii
FORWARD-LOOKING STATEMENTS
This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects or possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.
Risks, uncertainties and other important factors that could cause actual results to differ materially from those described in forward-looking statements and from historical results include, but are not limited to, the following:
· international, national and local economic conditions, including the state of the Hawaii tourism, defense and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value and/or the actual performance of collateral underlying loans held by American Savings Bank, F.S.B. (ASB), which could result in higher loan loss provisions and write-offs), decisions concerning the extent of the presence of the federal government and military in Hawaii (including the effects of sequestration), the implications and potential impacts of U.S. and foreign capital and credit market conditions and federal, state and international responses to those conditions, and the potential impacts of global developments (including global economic conditions and uncertainties, unrest, conflict and the overthrow of governmental regimes in North Africa and the Middle East, terrorist acts, the war on terrorism, continuing U.S. presence in Afghanistan and potential conflict or crisis with North Korea or Iran);
· weather and natural disasters (e.g., hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of climate change, such as more severe storms and rising sea levels), including their impact on Company operations and the economy;
· the timing and extent of changes in interest rates and the shape of the yield curve;
· the ability of the Company to access credit markets to obtain commercial paper and other short-term and long-term debt financing (including lines of credit) and to access capital markets to issue HEI common stock under volatile and challenging market conditions, and the cost of such financings, if available;
· the risks inherent in changes in the value of the Company’s pension and other retirement plan assets and ASB’s securities available for sale;
· changes in laws, regulations, market conditions and other factors that result in changes in assumptions used to calculate retirement benefits costs and funding requirements;
· the impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (Dodd-Frank Act) and of the rules and regulations that the Dodd-Frank Act requires to be promulgated;
· increasing competition in the banking industry (e.g., increased price competition for deposits, or an outflow of deposits to alternative investments, which may have an adverse impact on ASB’s cost of funds);
· the implementation of the Energy Agreement with the State of Hawaii and Consumer Advocate (Energy Agreement), setting forth the goals and objectives of a Hawaii Clean Energy Initiative (HCEI), and the fulfillment by the electric utilities of their commitments under the Energy Agreement (given the Public Utilities Commission of the State of Hawaii (PUC) approvals needed; the PUC’s potential delay in considering (and potential disapproval of actual or proposed) HCEI-related costs; reliance by the Company on outside parties such as the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding wind power, proposed undersea cables, biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);
· capacity and supply constraints or difficulties, especially if generating units (utility-owned or IPP-owned) fail or measures such as demand-side management (DSM), distributed generation, combined heat and power or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand;
· fuel oil price changes, performance by suppliers of their fuel oil delivery obligations and the continued availability to the electric utilities of their energy cost adjustment clauses (ECACs);
· the continued availability to the electric utilities of other cost recovery mechanisms, including the purchased power adjustment clauses (PPACs), revenue adjustment mechanisms (RAMs) and pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, and the continued decoupling of revenues from sales;
· the impact of fuel price volatility on customer satisfaction and political and regulatory support for the utilities;
· the risks associated with increasing reliance on renewable energy, as contemplated under the Energy Agreement, including the availability and cost of non-fossil fuel supplies for renewable energy generation and the operational impacts of adding intermittent sources of renewable energy to the electric grid;
· the ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs);
· the ability of the electric utilities to negotiate, periodically, favorable fuel supply and collective bargaining agreements;
· new technological developments that could affect the operations and prospects of HEI and its subsidiaries (including HECO and its subsidiaries and ASB) or their competitors;
· cyber security risks and the potential for cyber incidents, including potential incidents at HEI, ASB and HECO and their subsidiaries (including at ASB branches and at the electric utility plants) and incidents at data processing centers they use, to the extent not prevented by intrusion detection and prevention systems, anti-virus software, firewalls and other general information technology controls;
· federal, state, county and international governmental and regulatory actions, such as existing, new and changes in laws, rules and regulations applicable to HEI, HECO, ASB and their subsidiaries (including changes in taxation, increases in capital requirements, regulatory changes resulting from the HCEI, environmental laws and regulations (including resulting compliance costs and risks of fines and penalties and/or liabilities), the regulation of greenhouse gas (GHG) emissions, governmental fees and assessments (such as Federal Deposit Insurance Corporation assessments), and potential carbon “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation);
· decisions by the PUC in rate cases and other proceedings (including the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallowance of project costs as a result of adverse regulatory audit reports or otherwise);
· decisions by the PUC and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions, restrictions and penalties that may arise, such as with respect to environmental conditions or renewable portfolio standards (RPS));
· potential enforcement actions by the Office of the Comptroller of the Currency, the Federal Reserve Board (FRB), the Federal Deposit Insurance Corporation (FDIC) and/or other governmental authorities (such as consent orders, required corrective actions, restrictions and penalties that may arise, for example, with respect to compliance deficiencies under existing or new banking and consumer protection laws and regulations or with respect to capital adequacy);
· the ability of the electric utilities to recover increasing costs and earn a reasonable return on capital investments not covered by revenue adjustment mechanisms;
· the risks associated with the geographic concentration of HEI’s businesses and ASB’s loans, ASB’s concentration in a single product type (i.e., first mortgages) and ASB’s significant credit relationships (i.e., concentrations of large loans and/or credit lines with certain customers);
· changes in accounting principles applicable to HEI, HECO, ASB and their subsidiaries, including the possible adoption of International Financial Reporting Standards or new U.S. accounting standards, the potential discontinuance of regulatory accounting and the effects of potentially required consolidation of variable interest entities (VIEs) or required capital lease accounting for PPAs with IPPs;
· changes by securities rating agencies in their ratings of the securities of HEI and HECO and the results of financing efforts;
· faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage-servicing assets of ASB;
· changes in ASB’s loan portfolio credit profile and asset quality which may increase or decrease the required level of allowance for loan losses and charge-offs;
· changes in ASB’s deposit cost or mix which may have an adverse impact on ASB’s cost of funds;
· the final outcome of tax positions taken by HEI, HECO, ASB and their subsidiaries;
· the risks of suffering losses and incurring liabilities that are uninsured (e.g., damages to the utilities’ transmission and distribution system and losses from business interruption) or underinsured (e.g., losses not covered as a result of insurance deductibles or other exclusions or exceeding policy limits); and
· other risks or uncertainties described elsewhere in this report and in other reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by HEI and/or HECO with the Securities and Exchange Commission (SEC).
Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI, HECO, ASB and their subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
v
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Income (unaudited)
Three months
Six months
ended June 30
(in thousands, except per share amounts)
2013
2012
Revenues
Electric utility
$
730,688
789,552
1,449,961
1,539,162
66,027
64,721
130,783
129,973
Other
15
(5
)
50
(7
Total revenues
796,730
854,268
1,580,794
1,669,128
Expenses
669,550
728,056
1,335,870
1,420,412
41,322
42,847
84,327
85,187
3,488
3,959
7,570
8,307
Total expenses
714,360
774,862
1,427,767
1,513,906
Operating income (loss)
61,138
61,496
114,091
118,750
24,705
21,874
46,456
44,786
(3,473
(3,964
(7,520
(8,314
Total operating income
82,370
79,406
153,027
155,222
Interest expense—other than on deposit liabilities and other bank borrowings
(19,613
(20,199
(39,401
(38,738
Allowance for borrowed funds used during construction
398
893
1,128
1,763
Allowance for equity funds used during construction
1,560
1,997
2,775
3,937
Income before income taxes
64,715
62,097
117,529
122,184
Income taxes
23,654
22,824
42,316
44,122
Net income
41,061
39,273
75,213
78,062
Preferred stock dividends of subsidiaries
473
946
Net income for common stock
40,588
38,800
74,267
77,116
Basic earnings per common share
0.41
0.40
0.75
0.80
Diluted earnings per common share
Dividends per common share
0.31
0.62
Weighted-average number of common shares outstanding
98,660
96,693
98,399
96,430
Net effect of potentially dilutive shares
589
286
562
389
Adjusted weighted-average shares
99,249
96,979
98,961
96,819
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Comprehensive Income (unaudited)
Three months ended June 30
Six months ended June 30
(in thousands)
Other comprehensive income (loss), net of taxes:
Net unrealized gains (losses) on securities:
Net unrealized gains (losses) on securities arising during the period, net of (taxes) benefits of $5,485 and ($721) for the three months ended June 30, 2013 and 2012 and $6,032 and ($572) for the six months ended June 30, 2013 and 2012, respectively
(8,307
1,093
(9,135
867
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $488 and $53 for the three months ended June 30, 2013 and 2012 and $488 and $53 for the six months ended June 30, 2013 and 2012, respectively
(738
(81
Derivatives qualified as cash flow hedges:
Less: reclassification adjustment to net income, net of tax benefits of $38 for the three months ended June 30, 2013 and 2012 and $75 for the six months ended June 30, 2013 and 2012
118
Retirement benefit plans:
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $3,630 and $2,405 for the three months ended June 30, 2013 and 2012 and $7,476 and $4,878 for the six months ended June 30, 2013 and 2012, respectively
5,680
3,768
11,701
7,641
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,184 and $2,095 for the three months ended June 30, 2013 and 2012 and $6,568 and $4,257 for the six months ended June 30, 2013 and 2012, respectively
(4,999
(3,289
(10,312
(6,684
Other comprehensive income (loss), net of taxes
(8,305
1,550
(8,366
1,861
Comprehensive income attributable to Hawaiian Electric Industries, Inc.
32,283
40,350
65,901
78,977
Consolidated Balance Sheets (unaudited)
(dollars in thousands)
June 30, 2013
December 31, 2012
Assets
Cash and cash equivalents
153,712
219,662
Accounts receivable and unbilled revenues, net
359,259
362,823
Available-for-sale investment and mortgage-related securities
560,172
671,358
Investment in stock of Federal Home Loan Bank of Seattle
94,281
96,022
Loans receivable held for investment, net
3,912,630
3,737,233
Loans held for sale, at lower of cost or fair value
34,073
26,005
Property, plant and equipment, net of accumulated depreciation of $2,161,681 in 2013 and $2,125,286 in 2012
3,701,905
3,594,829
Regulatory assets
885,025
864,596
454,898
494,414
Goodwill
82,190
Total assets
10,238,145
10,149,132
Liabilities and shareholders’ equity
Liabilities
Accounts payable
175,038
212,379
Interest and dividends payable
25,503
26,258
Deposit liabilities
4,276,243
4,229,916
Short-term borrowings—other than bank
125,786
83,693
Other bank borrowings
187,884
195,926
Long-term debt, net—other than bank
1,422,877
1,422,872
Deferred income taxes
474,197
439,329
Regulatory liabilities
336,065
322,074
Contributions in aid of construction
419,337
405,520
Defined benefit pension and other postretirement benefit plans liability
639,898
656,394
496,375
526,613
Total liabilities
8,579,203
8,520,974
Preferred stock of subsidiaries - not subject to mandatory redemption
34,293
Commitments and contingencies (Notes 3 and 4)
Shareholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none
—
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 99,044,053 shares in 2013 and 97,928,403 shares in 2012
1,429,371
1,403,484
Retained earnings
230,067
216,804
Accumulated other comprehensive income (loss), net of taxes
Net unrealized gains on securities
888
10,761
Unrealized losses on derivatives
(642
(760
Retirement benefit plans
(35,035
(34,789
(36,424
(26,423
Total shareholders’ equity
1,624,649
1,593,865
Total liabilities and shareholders’ equity
Consolidated Statements of Changes in Shareholders’ Equity (unaudited)
Common stock
Retained
Accumulated other comprehensive
Shares
Amount
Earnings
loss
Total
Balance, December 31, 2012
97,928
Other comprehensive loss, net of tax benefits
Issuance of common stock, net
1,116
25,887
Common stock dividends ($0.62 per share)
(61,004
Balance, June 30, 2013
99,044
Balance, December 31, 2011
96,038
1,349,446
198,397
(19,137
1,528,706
Other comprehensive income, net of taxes
985
27,980
Dividend equivalents paid on equity-classified awards
(96
(59,791
Balance, June 30, 2012
97,023
1,377,426
215,626
(17,276
1,575,776
Consolidated Statements of Cash Flows (unaudited)
Cash flows from operating activities
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation of property, plant and equipment
79,843
75,517
Other amortization
2,868
2,999
Provision for loan losses
899
5,924
Loans receivable originated and purchased, held for sale
(128,276
(161,344
Proceeds from sale of loans receivable, held for sale
148,243
161,713
Change in deferred income taxes
40,403
41,541
Change in excess tax benefits from share-based payment arrangements
(445
(40
(2,775
(3,937
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net
3,564
(42,428
Decrease (increase) in fuel oil stock
43,974
(35,893
Increase in regulatory assets
(37,586
(35,476
Increase (decrease) in accounts, interest and dividends payable
(43,384
3,578
Change in prepaid and accrued income taxes and utility revenue taxes
(33,822
(12,998
Contributions to defined benefit pension and other postretirement benefit plans
(41,521
(53,356
Other increase in defined benefit pension and other postretirement benefit plans liability
41,191
31,204
Change in other assets and liabilities
(17,597
(58,638
Net cash provided by (used in) operating activities
130,792
(3,572
Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased
(39,721
(93,808
Principal repayments on available-for-sale investment and mortgage-related securities
62,819
75,407
Proceeds from sale of available-for-sale investment and mortgage-related securities
71,367
3,548
Net increase in loans held for investment
(201,184
(61,214
Proceeds from sale of real estate acquired in settlement of loans
5,712
6,036
Capital expenditures
(158,830
(145,263
17,188
26,981
2,364
Net cash used in investing activities
(240,285
(188,313
Cash flows from financing activities
Net increase in deposit liabilities
46,326
66,709
Net increase in short-term borrowings with original maturities of three months or less
42,093
27,419
Net decrease in retail repurchase agreements
(8,054
(14,556
Proceeds from other bank borrowings
25,000
Repayments of other bank borrowings
(25,000
Proceeds from issuance of long-term debt
50,000
417,000
Repayment of long-term debt
(50,000
(328,500
445
40
Net proceeds from issuance of common stock
11,994
11,909
Common stock dividends
(48,921
(47,851
(946
606
(2,055
Net cash provided by financing activities
43,543
129,169
Net decrease in cash and cash equivalents
(65,950
(62,716
Cash and cash equivalents, beginning of period
270,265
Cash and cash equivalents, end of period
207,549
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1 · Basis of presentation
The accompanying unaudited consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto in HEI’s Form 10-K for the year ended December 31, 2012 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2013.
In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the Company’s financial position as of June 30, 2013 and December 31, 2012, the results of its operations for the three and six months ended June 30, 2013 and 2012 and its cash flows for the six months ended June 30, 2013 and 2012. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.
2 · Segment financial information
Three months ended June 30, 2013
Revenues from external customers
730,682
21
Intersegment revenues (eliminations)
(6
Income (loss) before income taxes
47,517
(7,507
Income taxes (benefit)
18,325
8,786
(3,457
Net income (loss)
29,192
15,919
(4,050
499
(26
Net income (loss) for common stock
28,693
(4,024
Six months ended June 30, 2013
1,449,949
62
12
(12
86,839
46,457
(15,767
32,719
16,383
(6,786
54,120
30,074
(8,981
998
(52
53,122
(8,929
Assets (at June 30, 2013)
5,161,819
5,068,771
7,555
Three months ended June 30, 2012
789,539
8
13
(13
48,501
21,873
(8,277
18,626
7,684
(3,486
29,875
14,189
(4,791
29,376
(4,765
Six months ended June 30, 2012
1,539,113
42
49
(49
93,708
45,337
(16,861
36,034
15,271
(7,183
57,674
30,066
(9,678
56,676
(9,626
Assets (at December 31, 2012)
5,108,793
5,041,673
(1,334
Intercompany electricity sales of the electric utilities to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by consolidated HECO, the profit on such sales is nominal and the elimination of electric sales revenues and expenses could distort segment operating income and net income for common stock.
Bank fees that ASB charges the electric utility and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution, the profit on such fees is nominal and the elimination of bank fee income and expenses could distort segment operating income and net income for common stock.
3 · Electric utility subsidiary
For consolidated HECO financial information, including its commitments and contingencies, see HECO’s consolidated financial statements beginning on page 30 through Note 10 on page 44.
7
4 · Bank subsidiary
Selected financial information
American Savings Bank, F.S.B.
Statements of Income Data
Interest income
Interest and fees on loans
43,624
44,473
86,227
89,361
Interest on investment and mortgage-related securities
3,234
3,297
6,698
7,102
Total interest income
46,858
47,770
92,925
96,463
Interest expense
Interest on deposit liabilities
1,296
1,696
2,608
3,475
Interest on other borrowings
1,178
1,214
2,342
2,475
Total interest expense
2,474
2,910
4,950
5,950
44,384
44,860
87,975
90,513
Provision (credit) for loan losses
(959
2,378
Net interest income after provision (credit) for loan losses
45,343
42,482
87,076
84,589
Noninterest income
Fees from other financial services
7,996
7,463
15,639
14,800
Fee income on deposit liabilities
4,433
4,322
8,747
8,600
Fee income on other financial products
1,780
1,532
3,574
3,081
Mortgage banking income
2,003
2,185
5,349
4,220
Gain on sale of securities
1,226
134
Other income
1,731
1,315
3,323
2,675
Total noninterest income
19,169
16,951
37,858
33,510
Noninterest expense
Compensation and employee benefits
20,063
18,696
40,151
37,342
Occupancy
4,219
4,241
8,342
8,466
Data processing
2,827
2,489
5,814
4,600
Services
2,328
2,221
4,431
4,004
Equipment
1,870
1,807
3,644
3,537
Other expense
8,500
8,106
16,095
14,813
Total noninterest expense
39,807
37,560
78,477
72,762
Statements of Comprehensive Income Data
Net unrealized gains (losses) on securities arising during the period, net of (taxes) benefits, of $5,485 and ($721) for the three months ended June 30, 2013 and 2012 and $6,032 and ($572) for the six months ended June 30, 2013 and 2012, respectively
Less: reclassification adjustment for net realized gains, included in net income , net of taxes, of $488 and $53 for the three months ended June 30, 2013 and 2012 and $488 and $53 for the six months ended June 30, 2013 and 2012, respectively
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $308 and $168 for the three months ended June 30, 2013 and 2012 and $1,732 and $332 for the six months ended June 30, 2013 and 2012, respectively
466
255
2,623
503
(8,579
1,267
(7,250
1,289
Comprehensive income
7,340
15,456
31,355
Balance Sheets Data
143,912
184,430
Loans receivable held for investment
3,953,634
3,779,218
Allowance for loan losses
(41,004
(41,985
241,513
244,435
Liabilities and shareholder’s equity
Deposit liabilities—noninterest-bearing
1,168,937
1,164,308
Deposit liabilities—interest-bearing
3,107,306
3,065,608
Other borrowings
102,516
117,752
4,566,643
4,543,594
Commitments and contingencies (see “Litigation” below)
334,937
333,712
189,837
179,763
(23,534
(22,646
(26,157
(15,396
Total shareholder’s equity
502,128
498,079
Total liabilities and shareholder’s equity
Other assets
Bank-owned life insurance
127,851
125,726
Premises and equipment, net
68,124
62,458
Prepaid expenses
4,064
13,199
Accrued interest receivable
13,472
13,228
Mortgage-servicing rights
11,363
10,818
Real estate acquired in settlement of loans, net
2,987
6,050
13,652
12,956
Other liabilities
Accrued expenses
17,103
Federal and state income taxes payable
30,932
35,408
Cashier’s checks
22,737
23,478
Advance payments by borrowers
10,300
9,685
23,091
32,078
Bank-owned life insurance is life insurance purchased by ASB on the lives of certain key employees, with ASB as the beneficiary. The insurance is used to fund employee benefits through tax-free income from increases in the cash value of the policies and insurance proceeds paid to ASB upon an insured’s death.
9
Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $138 million and $50 million, respectively, as of June 30, 2013 and $146 million and $50 million, respectively, as of December 31, 2012.
Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the balance sheet. All such agreements are subject to master netting arrangements, which provide for conditional right of set-off in case of default by either party; however, ASB presents securities sold under agreements to repurchase on a gross basis in the balance sheet. The following tables present information about the securities sold under agreements to repurchase, including the related collateral received from or pledged to counterparties:
(in millions)
Gross amount of recognized liabilities
Gross amount offset in the Balance Sheet
Net amount of liabilities presented in the Balance Sheet
Repurchase agreements
138
146
Gross amount not offset in the Balance Sheet
Financial instruments
Cash collateral pledged
Net amount
Financial institution
Commercial account holders
88
96
Investment and mortgage-related securities portfolio.
Available-for-sale securities. The book value (amortized cost), gross unrealized gains and losses, estimated fair value and gross unrealized losses (fair value and amount by duration of time in which positions have been held in a continuous loss position) for securities held in ASB’s “available-for-sale” portfolio by major security type were as follows:
Gross
Estimated
Gross unrealized losses
Amortized
unrealized
fair
Less than 12 months
12 months or longer
cost
gains
losses
value
Fair value
Federal agency obligations
99,963
561
(1,460
99,064
30,383
Mortgage-related securities- FNMA, FHLMC and GNMA
381,281
6,257
(5,494
382,044
178,144
Municipal bonds
77,455
1,929
(320
79,064
26,561
558,699
(7,274
235,088
168,324
3,167
171,491
407,175
10,412
(204
417,383
32,269
77,993
4,491
82,484
653,492
18,070
The unrealized losses on ASB’s investments in mortgage-related securities and obligations issued by federal agencies were caused by interest rate movements. The contractual terms of these investments do not permit the issuer to settle the securities at a price less than the amortized cost basis of the investments. Because ASB does
10
not intend to sell the securities and has determined it is more likely than not that it will not be required to sell the investments before recovery of their amortized costs basis, which may be at maturity, ASB did not consider these investments to be other-than-temporarily impaired at June 30, 2013.
The fair values of ASB’s investment securities could decline if interest rates rise or spreads widen.
The following table details the contractual maturities of available-for-sale securities. All positions with variable maturities (e.g. callable debentures and mortgage-related securities) are disclosed based upon the bond’s contractual maturity. Actual maturities will likely differ from these contractual maturities because borrowers have the right to prepay obligations with or without prepayment penalties.
Amortized cost
Due in one year or less
28,120
28,192
Due after one year through five years
34,885
35,220
Due after five years through ten years
89,055
90,477
Due after ten years
25,358
24,239
177,418
178,128
Mortgage-related securities-FNMA,FHLMC and GNMA
Total available-for-sale securities
Allowance for loan losses. ASB must maintain an allowance for loan losses that is adequate to absorb estimated probable credit losses associated with its loan portfolio. The allowance for loan losses consists of an allocated portion, which estimates credit losses for specifically identified loans and pools of loans, and an unallocated portion.
The allowance for loan losses (balances and changes) and financing receivables were as follows:
Residential
Commercial real
Home equity line
Commercial
Consumer
1-4 family
estate
of credit
land
construction
loans
Unallocated
Allowance for loan losses:
Beginning balance
6,068
2,965
4,493
4,275
2,023
15,931
4,019
2,202
41,985
Charge-offs
(1,056
(235
(1,350
(1,404
(4,783
Recoveries
1,225
256
500
612
310
2,903
Provision
120
1,152
(2,353
282
1,114
(526
107
Ending balance
6,357
4,117
5,009
2,187
2,305
14
16,307
2,399
2,309
41,004
Ending balance: individually evaluated for impairment
944
820
1,641
3,367
6,772
Ending balance: collectively evaluated for impairment
5,413
546
12,940
34,232
Financing Receivables:
2,001,035
382,735
673,727
21,836
50,114
9,664
719,519
104,759
3,963,389
21,417
3,811
837
16,041
21,431
20
63,557
1,979,618
378,924
672,890
5,795
698,088
104,739
3,899,832
Year ended December 31, 2012
6,500
1,688
4,354
3,795
1,888
14,867
3,806
1,004
37,906
(3,183
(716
(2,808
(3,606
(2,517
(12,830
1,328
108
1,443
649
498
4,026
1,423
1,277
747
1,845
135
4,021
2,232
1,198
12,883
384
535
3,221
2,659
6,799
5,684
2,430
1,054
13,272
35,186
1,866,450
375,677
630,175
25,815
43,988
6,171
721,349
121,231
3,790,856
25,279
6,751
18,563
20,298
22
72,473
1,841,171
368,926
628,615
7,252
701,051
121,209
3,718,383
11
Credit quality. ASB performs an internal loan review and grading on an ongoing basis. The review provides management with periodic information as to the quality of the loan portfolio and effectiveness of its lending policies and procedures. The objectives of the loan review and grading procedures are to identify, in a timely manner, existing or emerging credit trends so that appropriate steps can be initiated to manage risk and avoid or minimize future losses. Loans subject to grading include commercial and industrial, commercial real estate and commercial construction loans.
A dual ten-point risk rating system is used to reflect the probability of default (borrower risk rating) and loss given default (transaction risk rating). The borrower risk rating addresses risk presented by the individual borrower and is based on the overall assessment of the borrower’s financial and operating strength including earnings, operating cash flow, debt service capacity, asset and liability structure, competitive issues, experience and quality of management, financial reporting quality and industry/economic factors. Separately, the transaction risk rating addresses risk in the transaction and is a function of the type of collateral control exercised over the collateral, loan structure, guarantees, and other structural support or enhancements to the loan.
The numerical representation of the risk categories are:
1- Substantially risk free
2- Minimal risk
3- Modest risk
4- Better than average risk
5- Average risk
6- Acceptable risk
7- Special mention
8- Substandard
9- Doubtful
10- Loss
Grades 1 through 6 are considered pass grades. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral.
The credit risk profile by internally assigned grade for loans was as follows:
Commercial real estate
Commercial construction
Grade:
Pass
319,751
44,703
629,293
314,182
39,063
638,854
Special mention
36,141
19,655
25,437
4,925
24,511
Substandard
23,032
5,411
66,925
29,308
53,538
Doubtful
3,646
6,750
4,446
Loss
The credit risk profile based on payment activity for loans was as follows:
30-59 days past due
60-89 days past due
Greater than 90 days
Total past due
Current
Total financing receivables
Recorded investment> 90 days and accruing
Real estate loans:
Residential 1-4 family
2,656
580
17,899
21,135
1,979,900
Home equity line of credit
923
126
975
2,024
671,703
Residential land
167
852
9,493
10,512
11,324
Residential construction
Commercial loans
577
834
5,528
6,939
712,580
Consumer loans
408
161
136
705
104,054
Total loans
4,731
2,553
37,842
45,126
3,918,263
6,353
1,741
24,054
32,148
1,834,302
85
6,835
368,842
1,077
142
1,319
2,538
627,637
2,851
75
7,788
10,714
15,101
3,052
2,814
1,098
6,964
714,385
131
598
348
424
1,370
119,861
242
14,016
5,120
41,433
60,569
3,730,287
373
The credit risk profile based on nonaccrual loans and accruing loans 90 days or more past due was as follows:
Nonaccrual loans
Accruing loans 90 days or more past due
21,392
26,721
2,160
2,349
7,565
8,561
21,935
20,222
263
284
57,126
64,887
The total carrying amount and the total unpaid principal balance of impaired loans, with and without recorded allowance for loan losses and combined, were as follows:
Recorded investment
Unpaid principal balance
Related Allowance
Average recorded investment
Interest income recognized*
With no related allowance recorded
10,921
14,527
12,380
98
13,568
232
1,604
536
637
646
8,429
9,809
8,502
122
8,167
219
4,306
6,408
4,393
24,212
31,841
25,932
221
28,312
452
With an allowance recorded
7,172
7,193
7,069
6,039
176
3,834
8,341
151
7,221
6,229
6,356
6,379
89
7,632
202
17,125
18,427
15,073
15,147
34,337
35,810
36,862
315
36,039
534
18,093
21,720
19,449
173
19,607
8,825
14,658
16,165
14,881
211
15,799
421
24,835
19,466
19,453
58,549
67,651
62,794
64,351
986
Related allowance
14,633
20,247
16,688
294
2,929
7,771
237
581
1,374
632
7,691
10,624
21,589
1,185
4,265
6,994
24,605
23
30,120
42,189
71,308
2,703
4,803
4,204
250
3,821
3,840
1,295
26
9,984
10,364
7,428
575
16,033
16,912
34,641
35,919
21,382
848
19,436
25,050
20,892
544
6,769
9,066
658
17,675
20,988
29,017
1,760
23,906
33,034
1,009
64,761
78,108
92,690
3,551
* Since loan was classified as impaired.
Troubled debt restructurings. A loan modification is deemed to be a troubled debt restructuring (TDR) when ASB grants a concession it would not otherwise consider were it not for the borrower’s financial difficulty. When a borrower experiencing financial difficulty fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to improve the collectability of the loan and maximize the likelihood of full repayment. At times, ASB may modify or restructure a loan to help a distressed borrower improve its financial position to eventually be able to fully repay the loan, provided the borrower has demonstrated both the willingness and the ability to fulfill the modified terms. TDR loans are considered an alternative to foreclosure or liquidation with the goal of minimizing losses to ASB and maximizing recovery.
ASB may consider various types of concessions in granting a TDR including maturity date extensions, extended amortization of principal, temporary deferral of principal payments, and temporary interest rate reductions. ASB rarely grants principal forgiveness in its TDR modifications. Residential loan modifications generally involve interest rate reduction, extending the amortization period, or capitalizing certain delinquent amounts owed not to exceed the original loan balance. Land loans at origination are typically structured as a three-year term, interest-only monthly payment with a balloon payment due at maturity. Land loan TDR modifications typically involve extending the maturity date up to five years and converting the payments from interest-only to principal and interest monthly, at the same or higher interest rate. Commercial loan modifications generally involve extensions of maturity dates, extending the amortization period, and temporary deferral of principal payments. ASB does not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.
All TDR loans are classified as impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment: (1) present value of expected future cash flows discounted at the loan’s effective original contractual rate, (2) fair value of collateral less cost to sell, or (3) observable market price. The financial impact of the calculated impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.
Loan modifications that occurred were as follows for the indicated periods:
Number of
Outstanding recorded investment
contracts
Pre-modification
Post-modification
Troubled debt restructurings
4,645
4,775
18
5,767
5,838
462
215
1,163
2,040
2,031
714
6,475
6,652
8,983
8,798
3,056
2,872
4,469
4,282
1,774
1,580
3,508
3,021
1,869
2,029
6,699
6,321
51
10,006
9,332
ASB did not have any loans modified in TDRs that experienced a payment default of 90 or more days in 2013, and for which the payment default occurred within one year of the modification. Loans modified in TDRs that experienced a payment default of 90 days or more in 2012, and for which the payment default occurred within one year of the modification, were as follows:
Number of contracts
Troubled debt restructurings that subsequently defaulted
847
The three commercial loans that subsequently defaulted were modified by temporarily lowering the monthly payments and deferring principal payments for a short period of time. There are no commitments to lend additional funds to borrowers whose loan terms have been impaired or modified in TDRs as of June 30, 2013.
Litigation. In March 2011, a purported class action lawsuit was filed in the First Circuit Court of the State of Hawaii by a customer who claimed that ASB had improperly charged overdraft fees on debit card transactions. The lawsuit
16
is still in its preliminary stage, thus, the probable outcome and range of reasonably possible loss are not determinable at this time.
ASB is subject in the normal course of business to pending and threatened legal proceedings. Management does not anticipate that the aggregate ultimate liability arising out of these pending or threatened legal proceedings will be material to its financial position. However, ASB cannot rule out the possibility that such outcomes could have a material adverse effect on the results of operations or liquidity for a particular reporting period in the future.
5 · Retirement benefits
Defined benefit pension and other postretirement benefit plans information. For the first six months of 2013, the Company contributed $42 million (primarily by the utilities) to its pension and other postretirement benefit plans, compared to $53 million (primarily by the utilities) in the first six months of 2012. The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 2013 is $83 million ($81 million by the utilities, $2 million by HEI and nil by ASB), compared to $78 million ($63 million by the utilities, $2 million by HEI and $13 million by ASB) in 2012. In addition, the Company expects to pay directly $2 million ($1 million each by the utilities and HEI) of benefits in 2013, compared to $1 million paid in 2012.
On July 6, 2012, President Obama signed the Moving Ahead for Progress in the 21st Century Act (MAP-21), which included provisions related to the funding and administration of pension plans. This law does not affect the Company’s accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The Company elected to apply MAP-21 for 2012, which improved the plans’ Adjusted Funding Target Attainment Percentage (AFTAP) for funding and benefit distribution purposes and thereby reduced the 2012 minimum funding requirement and lifted the restrictions on accelerated distribution options (which restrictions were in effect April 1, 2011 to September 30, 2012) for HEI and HECO and its subsidiaries. The effects of MAP-21 are expected to cause the minimum required funding under Employee Retirement Income Security Act of 1974, as amended (ERISA) to be less than the net periodic cost for 2013 and 2014; therefore, the Company expects to contribute the net periodic cost for these years. If the AFTAP falls below 80% in the future, the restrictions on accelerated distribution options may apply again.
The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels, more conservative assumptions must be used to value obligations under the pension plan. The HEI Retirement Plan fell below these thresholds in 2011 and the minimum required contribution for 2012 incorporated the more conservative assumptions required. However, the HEI Retirement Plan met the threshold requirements in each of 2012 and 2013 so that the more conservative assumptions do not apply for either the 2013 or 2014 valuation of plan liabilities for purposes of calculating the minimum required contribution. Other factors could cause changes to the required contribution levels.
The components of net periodic benefit cost for consolidated HEI were as follows:
Pension benefits
Other benefits
Service cost
14,121
11,397
1,103
1,008
28,210
21,588
2,152
2,104
Interest cost
16,973
1,855
2,223
32,413
33,744
3,786
4,504
Expected return on plan assets
(18,182
(17,736
(2,521
(2,557
(36,267
(35,592
(5,083
(5,178
Amortization of prior service gain
(25
(82
(449
(163
(897
Amortization of net actuarial loss
9,499
6,403
299
19,318
12,826
805
752
Net periodic benefit cost
16,955
272
524
43,625
32,403
763
1,285
Impact of PUC D&Os
(5,286
(4,977
(187
(416
(12,722
(8,834
(584
(1,096
Net periodic benefit cost (adjusted for impact of PUC D&Os)
16,434
11,978
30,903
23,569
179
189
Consolidated HEI recorded retirement benefits expense of $23 million and $17 million in the first six months of 2013 and 2012, respectively, and charged the remaining amounts primarily to electric utility plant.
The utilities have implemented pension and OPEB tracking mechanisms under which all of their retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with
17
GAAP are recovered over time. Under the tracking mechanisms, these retirement benefit costs that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the respective utility’s next rate case.
Defined contribution plans information. For the first six months of 2013 and 2012, the Company’s expense for its defined contribution pension plans under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan was $2.0 million and $1.8 million, respectively, and cash contributions were $3.0 million and $2.7 million, respectively.
6 · Share-based compensation
Under the 2010 Equity and Incentive Plan (EIP), HEI can issue an aggregate of 4 million shares of common stock as incentive compensation to selected employees in the form of stock options, stock appreciation rights, restricted shares, restricted stock units, performance shares and other share-based and cash-based awards.
As of June 30, 2013, there were 3.6 million shares remaining available for future issuance under the EIP of which an estimated 2.6 million shares could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals under long-term incentive plans (based on the assumption that long-term incentive plan (LTIP) awards are achieved at maximum levels).
Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), grants and awards of an estimated 1,000 shares of common stock (based on the June 30, 2013 market price of shares as the price on the exercise dates) were outstanding as of June 30, 2013 to selected employees in the form of stock appreciation rights (SARs) and dividend equivalents. As of May 11, 2010 (when the EIP became effective), no new awards may be granted under the SOIP. After the shares of common stock for the outstanding SOIP grants and awards are issued or such grants and awards expire, the remaining shares registered under the SOIP will be deregistered and delisted.
The Company’s share-based compensation expense and related income tax benefit were as follows:
Share-based compensation expense (1)
1.1
1.7
3.0
3.5
Income tax benefit
0.4
0.6
1.2
(1) The Company has not capitalized any share-based compensation cost.
Nonqualified stock options. As of December 31, 2012, nonqualified stock options (NQSOs) outstanding totaled 14,000 (representing the same number of underlying shares), with a weighted-average exercise price of $20.49. As of June 30, 2013, there were no NQSOs outstanding.
NQSO activity and statistics were as follows:
(dollars in thousands, except prices)
Shares exercised
12,000
21,500
14,000
33,500
Weighted-average exercise price
20.49
20.93
21.20
Cash received from exercise
246
450
287
710
Intrinsic value of shares exercised (1)
113
174
128
265
Tax benefit realized for the deduction of exercises
44
103
(1) Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option.
Stock appreciation rights. Information about HEI’s SARs was as follows:
Outstanding & Exercisable (Vested)
Year of grant
Range of exercise prices
Number of shares underlying SARs
Weighted-average remaining contractual life
2004
$26.02
62,000
0.8
26.02
2005
26.18
102,000
1.8
$26.02 –26.18
164,000
1.4
26.12
As of December 31, 2012, the shares underlying SARs outstanding totaled 164,000, with a weighted-average exercise price of $26.12. As of June 30, 2013, all SARs outstanding were exercisable and had no aggregate intrinsic value.
SARs activity and statistics were as follows:
Shares underlying SARS exercised
112,000
Weighted-average price of shares exercised
26.17
194
76
(1) Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalent rights exceeds the exercise price of the right.
Restricted shares and restricted stock awards. Information about HEI’s grants of restricted shares and restricted stock awards was as follows:
(1)
Outstanding, beginning of period
9,005
22.21
38,107
23.83
46,807
24.45
Granted
Vested
(23,300
24.71
(32,000
25.38
Forfeited
Outstanding, end of period
14,807
22.45
(1) Weighted-average grant-date fair value per share based on the closing or average price of HEI common stock on the date of grant.
As of June 30, 2013, there was $0.1 million of total unrecognized compensation cost related to nonvested restricted shares and restricted stock awards. The cost is expected to be recognized over a weighted-average period of 1.4 years.
For the first six months of 2012, total restricted stock vested had a grant-date fair value of $0.8 million and the tax benefits realized for tax deductions related to restricted stock awards were $0.2 million.
Restricted stock units. Information about HEI’s grants of restricted stock units was as follows:
301,145
25.15
318,551
22.80
315,094
22.82
247,286
21.80
2,334
(2)
26.75
107,231
(3)
26.89
94,846
(4)
26.00
(832
26.60
(250
26.25
(114,044
20.34
(21,497
24.97
(1,564
25.53
(7,968
25.26
300,313
319,071
22.81
(1) Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.
(2) Total weighted-average grant-date fair value of $62,000.
(3) Total weighted-average grant-date fair value of $2.9 million.
(4) Total weighted average grant date fair value of $2.5 million.
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As of June 30, 2013, there was $4.9 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 2.8 years.
For the first six months of 2013 and 2012, total restricted stock units that vested and related dividends had a grant-date fair value of $3.5 million and $0.6 million, respectively, and the related tax benefits were $1.0 million and $0.2 million, respectively.
LTIP payable in stock. The 2011-2013 LTIP, 2012-2014 LTIP and the 2013-2015 LTIP provide for performance awards under the EIP of shares of HEI common stock based on the satisfaction of performance goals and service conditions. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made subject to the achievement of specified performance levels. The potential payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for the LTIP periods include awards with a market goal based on total return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the applicable three-year period. In addition, the 2011-2013 LTIP, the 2012-2014 LTIP and the 2013-2015 LTIP have performance goals related to levels of HEI consolidated net income, HEI consolidated return on common equity (ROACE), HECO consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets — all based on the applicable three-year averages.
LTIP linked to TRS. Information about HEI’s LTIP grants linked to TRS was as follows:
235,064
32.87
239,470
29.12
239,256
197,385
25.94
1,442
30.71
89,533
32.69
78,924
(87,753
(35,397
14.85
(1,505
30.39
(5,972
32.96
239,407
(1) Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model.
(2) Total weighted-average grant-date fair value of $2.4 million.
On February 4, 2013, LTIP grants (under the 2013-2015 LTIP) were made payable in 89,533 shares of HEI common stock (based on the grant date price of $26.89 and target TRS performance levels) with a weighted-average grant date fair value of $2.9 million based on the weighted-average grant date fair value per share of $32.69.
The following table summarizes the assumptions used to determine the fair value of the LTIP awards linked to TRS and the resulting fair value of LTIP awards granted:
Risk-free interest rate
0.38%
0.33%
Expected life in years
Expected volatility
19.4%
25.3%
Range of expected volatility for Peer Group
12.4% to 25.3%
15.5% to 34.5%
Grant date fair value (per share)
$32.69
$30.71
For the six months ended June 30, 2013 and 2012, total vested LTIP awards linked to TRS and related dividends had a fair value of $2.2 million and $0.6 million, respectively, and the related tax benefits were $0.9 million and $0.2 million, respectively.
As of June 30, 2013, there was $3.6 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 1.6 years.
LTIP awards linked to other performance conditions. Information about HEI’s LTIP awards payable in shares linked to other performance conditions was as follows:
341,824
297,602
23.92
247,175
25.04
182,498
22.63
3,600
118,895
118,704
(18,275
18.95
Cancelled
(37,351
24.96
(6,018
24.23
(5,971
304,473
295,184
23.95
(2) Total weighted-average grant-date fair value of $0.1 million (at target performance levels).
(3) Total weighted-average grant-date fair value of $3.1 million (at target performance levels).
On February 4, 2013, LTIP grants (under the 2013-2015 LTIP) were made payable in 118,895 shares of HEI common stock (based on the grant date price of $26.89 and target performance levels relating to performance goals other than TRS), with a weighted-average grant date fair value of $3.2 million based on the weighted-average grant date fair value per share of $26.89.
For the six months ended June 30, 2013, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $0.6 million and the related tax benefits were $0.2 million.
As of June 30, 2013, there was $4.5 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 1.7 years.
7 · Earnings per share and shareholders’ equity
Earnings per share. Under the two-class method of computing earnings per share (EPS), EPS was comprised as follows for both participating securities and unrestricted common stock:
Basic and diluted
Distributed earnings
Undistributed earnings (loss)
0.10
0.09
0.13
0.18
As of June 30, 2013, the antidilutive effects of SARs of 102,000 shares of HEI common stock for which the exercise prices were greater than the closing market price of HEI’s common stock were not included in the computation of dilutive EPS. As of June 30, 2012, there were no shares that were antidilutive.
Shareholders’ equity.
Equity forward transaction. On March 19, 2013, HEI entered into an equity forward transaction in connection with a public offering on that date of 6.1 million shares of HEI common stock at $26.75 per share. On March 19, 2013, HEI common stock closed at $27.01 per share. On March 20, 2013, the underwriters exercised their over-allotment option in full and HEI entered into an equity forward transaction in connection with the resulting additional 0.9 million shares of HEI common stock.
The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with the Company’s capital investment plans. Pursuant to the terms of these transactions, a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and sold them to a group of underwriters for $26.75 per share, less an underwriting discount equal to $1.00312 per share. Under the terms of
the equity forward transactions, to the extent that the transactions are physically settled, HEI would be required to issue and deliver shares of HEI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $25.74688 per share at the time the equity forward transactions were entered into, and the amount of cash to be received by HEI upon physical settlement of the equity forward is subject to certain adjustments in accordance with the terms of the equity forward transactions. The equity forward transactions must be settled fully by March 25, 2015. Except in specified circumstances or events that would require physical settlement, HEI is able to elect to settle the equity forward transactions by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to March 25, 2015.
The equity forward transactions had no initial fair value since they were entered into at the then market price of the common stock. HEI will not receive any proceeds from the sale of common stock until the equity forward transactions are settled, and at that time HEI will record the proceeds, if any, in equity. HEI concluded that the equity forward transactions were equity instruments based on the accounting guidance in ASC 480 and ASC 815 and that they qualified for an exception from derivative accounting under ASC 815 because the forward sale transactions were indexed to its own stock. HEI anticipates settling the equity forward transactions through physical settlement.
At June 30, 2013, the equity forward transactions could have been settled with physical delivery of the shares to the forward counterparty in exchange for cash of $178 million. At June 30, 2013, the equity forward transactions could also have been cash settled, with delivery of cash of approximately $8 million (which amount includes $7 million of underwriting discount) to the forward counterparty, or net share settled with delivery of approximately 282,000 shares of common stock to the forward counterparty.
Prior to their settlement, the equity forward transactions will be reflected in HEI’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of HEI’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the equity forward transactions less the number of shares that could be purchased by HEI in the market (based on the average market price during that reporting period) using the proceeds receivable upon settlement of the equity forward transactions (based on the adjusted forward sale price at the end of that reporting period). The excess number of shares is weighted for the portion of the reporting period in which the equity forward transactions are outstanding.
Accordingly, before physical or net share settlement of the equity forward transactions, and subject to the occurrence of certain events, HEI anticipates that the forward sale agreement and additional forward sale agreement will have a dilutive effect on HEI’s earnings per share only during periods when the applicable average market price per share of HEI’s common stock is above the per share adjusted forward sale price, as described above. However, if HEI decides to physically or net share settle the forward sale agreement and additional forward sale agreement, any delivery by HEI of shares upon settlement could result in dilution to HEI’s earnings per share.
For the six months ended June 30, 2013, the equity forward transactions did not have a material dilutive effect on HEI’s earnings per share.
Accumulated other comprehensive income. Reclassifications out of accumulated other comprehensive income/(loss) (AOCI) were as follows:
Amount reclassified from AOCI
Affected line item in the Statement of Income
Net realized gains on securities
Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges
Interest rate contracts (settled in 2011)
Retirement benefit plan items
Amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost
See Note 5 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets
Total reclassifications
457
769
994
8 · Commitments and contingencies
See Note 4, “Bank subsidiary,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements,” below.
9 · Fair value measurements
Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company uses its own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.
The Company groups its financial assets measured at fair value in three levels outlined as follows:
Level 1: Inputs to the valuation methodology are quoted prices, unadjusted, for identical assets or liabilities in active markets. A quoted price in an active market provides the most reliable evidence of fair value and is used to measure fair value whenever available.
Level 2: Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.
Level 3: Inputs to the valuation methodology are unobservable and significant to the fair value measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.
The Company used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:
Short term borrowings—other than bank. The carrying amount approximated fair value because of the short maturity of these instruments.
Investment and mortgage-related securities. To determine the fair value of investment securities held in ASB’s available-for-sale portfolio, independent third-party vendor or broker pricing is used on an unadjusted basis. Prices for investments and mortgage-related securities are based on observable inputs, including historical trading levels or sector yields, using market-based valuation techniques. The third party pricing service uses applications, models and pricing matrices that correlate security prices to benchmark securities which are adjusted for various inputs. Inputs include: benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark security bids and offers, TBA (to be announced) prices, monthly payment information, and reference data including market research. The pricing service may prioritize inputs differently on any given day for any security, and not all inputs are available for use in the evaluation process on any given day or for each security. The pricing vendor corroborates its finding on an on-going basis by monitoring market activity and events.
Third party pricing services provide security prices in good faith using rigorous methodologies; however, they do not warrant or guarantee the adequacy or accuracy of their information. Therefore, ASB utilizes a separate third party pricing vendor to corroborate security pricing of the first pricing vendor. If the pricing differential between the two pricing sources exceeds an established threshold, a pricing inquiry will be sent to both vendors or to an independent broker to determine a price that can be supported based on observable inputs found in the market. Such challenges to pricing are required infrequently and are generally resolved using additional security-specific information that was not available to a specific vendor.
Loans receivable. The estimated fair value of loans receivable is determined based on characteristics such as loan category, repricing features and remaining maturity, and includes prepayment estimates.
For residential real estate loans, fair values were estimated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual characteristics and remaining maturity.
For other types of loans, fair values were estimated by discounting contractual cash flows using discount rates that reflect current industry pricing for loans with similar characteristics and remaining maturity. Where industry pricing is not available, discount rates are based on ASB’s current pricing for loans with similar characteristics and remaining maturity.
The fair value of all loans was adjusted to reflect current assessments of loan collectability. Also see “Fair value measurements on a nonrecurring basis” below.
Deposit liabilities. The fair value of savings, negotiable orders of withdrawal, demand and money market deposits was the amount payable on demand at the reporting date. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.
Other bank borrowings. Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and remaining maturities.
Long-term debt. Fair value was obtained from third-party financial services providers based on the current rates offered for debt of the same or similar remaining maturities and from discounting the future cash flows using the current rates offered for debt of the same or similar remaining maturities.
Derivative financial instruments. See “Fair value measurements on a recurring basis” below.
Off-balance sheet financial instruments. The fair value of loans serviced for others was calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams were estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. The fair value of commitments to originate loans was estimated based on the change in current primary market prices of new
24
commitments. Since lines of credit can expire without being drawn and customers are under no obligation to utilize the lines, no fair value was assigned to unused lines of credit. The fair value of letters of credit was estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements.
The estimated fair values of certain of the Company’s financial instruments were as follows:
Carrying or notional
Estimated fair value
amount
Level 1
Level 2
Level 3
Financial assets
Money market funds
Loans receivable, net
3,946,703
4,075,387
Derivative assets
54,192
625
538
Financial liabilities
4,279,284
200,813
1,450,844
Derivative liabilities
19,350
525
3,763,238
3,957,752
4,235,527
212,163
1,481,004
As of June 30, 2013 and December 31, 2012, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.6 billion and $1.5 billion, respectively, and their estimated fair value on such dates were $0.1 million and $1.2 million, respectively. As of June 30, 2013 and December 31, 2012, loans serviced by ASB for others had notional amounts of $1.3 billion and the estimated fair value of the servicing rights for such loans was $14.0 million and $11.9 million, respectively.
Fair value measurements on a recurring basis.
Securities. While securities held in ASB’s investment portfolio trade in active markets, they do not trade on listed exchanges nor do the specific holdings trade in quoted markets by dealers or brokers. All holdings are valued using market-based approaches that are based on exit prices that are taken from identical or similar market transactions, even in situations where trading volume may be low when compared with prior periods. Inputs to these valuation techniques reflect the assumptions that consider credit and nonperformance risk that market participants would use in pricing the asset based on market data obtained from independent sources. Available-for-sale securities were comprised of federal agency obligations and mortgage-backed securities and municipal bonds.
Derivative financial instruments. ASB enters into interest rate lock commitments (IRLC) for residential mortgage loans, which commit ASB to lend funds to a potential borrower at a specific interest rate and within a specified period of time. The estimated fair value of commitments to originate residential mortgage loans for sale is based on quoted prices for similar loans in active markets. IRLCs are classified as Level 2 measurements.
ASB utilizes forward commitments as economic hedges against potential changes in the values of the IRLCs and loans held for sale. To reduce the impact of price fluctuations of IRLC and mortgage loans held for sale, ASB will purchase to be announced (TBA) mortgage-backed securities forward commitments, mandatory and best effort
25
commitments. These commitments help protect our loan sale profit margin from fluctuations in interest rates. The changes in the fair value of these commitments are recognized as part of mortgage banking income on the consolidated statements of income. TBA forward commitments are classified as Level 1, and consist of publicly-traded debt securities for which identical fair values can be obtained through quoted market prices in active exchange markets. The fair values of ASB’s best efforts and mandatory delivery loan sale commitments are determined similarly to the IRLCs using quoted prices in the market place that are observable and are classified as Level 2 measurements.
Assets measured at fair value on a recurring basis were as follows:
Fair value measurements using
Quoted prices in
Significant other
Significant
active markets for identical
observable inputs
unobservable inputs
assets (Level 1)
(Level 2)
(Level 3)
Money market funds (“other” segment)
Available-for-sale securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA
Derivative assets (1)
Interest rate lock commitments
Forward commitments
327
Derivative liabilities (1)
52
(1) Derivatives are carried at fair value with changes in value reflected in the balance sheet in other assets or other liabilities and included in mortgage banking income.
Fair value measurements on a nonrecurring basis. From time to time, the Company may be required to measure certain assets at fair value on a nonrecurring basis in accordance with GAAP. These adjustments to fair value usually result from the writedowns of individual assets. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments based on the current appraised value of the collateral securing the loans or unobservable market assumptions. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan. ASB may also be required to measure goodwill at fair value on a nonrecurring basis. During the first six months of 2013, it was not required that a measurement of the fair value of goodwill be calculated and goodwill was not measured at fair value.
Assets measured at fair value on a nonrecurring basis were as follows:
Fair value measurements
Balance
Loans
Real estate acquired in settlement of loans
For the first six months of 2013 and 2012, there were no adjustments to fair value for ASB’s loans held for sale.
Residential loans. The fair value of ASB’s residential loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.
Home equity lines of credit. The fair value of ASB’s home equity lines of credit that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.
Commercial loans. The fair value of ASB’s commercial loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, the value placed on the assets of the business and cash flows generated by the business entity, and therefore, is classified as a Level 3 measurement.
Real estate acquired in settlement of loans. The fair value of ASB’s real estate acquired in settlement of loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.
For loans and real estate acquired in settlement of loans classified as Level 3 as of June 30, 2013, the significant unobservable inputs used in the fair value measurement were as follows:
($ in thousands)
Fair value at June 30, 2013
Valuation technique
Significant unobservable input
Significant unobservable input value
Residential loans
13,840
Fair value of property or collateral
Appraised value
13 - 96%
Home equity lines of credit
25 - 82%
Commercial loan
220
Insurance proceeds
59%
892
Fair value of business assets
37 - 92%
1,739
Discounted cash flow
Present value of expected future cash flows based on anticipated debt restructuring
Discount rate
Paydown of loan — 59% 4.5%
Total commercial loans
2,036
81 — 100%
Significant increases (decreases) in any of those inputs in isolation would result in significantly higher (lower) fair value measurement.
27
10 · Cash flows
Supplemental disclosures of cash flow information
Interest paid to non-affiliates
43
Income taxes paid
Supplemental disclosures of noncash activities
Common stock dividends reinvested in HEI common stock (1)
Increases in common stock related to director and officer compensatory plans
Additions to electric utility property, plant and equipment - Unpaid invoices and other
Loans transferred from held-for-investment to held-for-sale
(1) The amounts shown represent common stock dividends reinvested in HEI common stock under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) in noncash transactions.
11 · Recent accounting pronouncements
Obligations resulting from joint and several liability. In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date,” which provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The guidance requires entities to measure these obligations as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amount of the obligation as well as other information. This guidance is effective for all fiscal years, and interim periods within those years, beginning after December 31, 2013.
The Company will retrospectively adopt ASU No. 2013-04 in the first quarter of 2014 and does not expect it to have a material impact on the Company’s results of operations, financial condition or liquidity.
Unrecognized tax benefit. In July 2013, the FASB issued ASU No. 2013-11, “Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists,” which clarifies that a liability for an unrecognized tax benefit should be presented as a reduction of a deferred tax asset when settlement of the liability with the taxing authority results in the reduction of a net operating loss or tax credit carryforward. ASU No. 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.
The Company will prospectively adopt ASU No. 2013-11 in the first quarter of 2014 and does not expect it to have a material impact on the Company’s results of operations, financial condition or liquidity.
12 · Credit agreement and long-term debt
Credit agreement. HEI maintains an amended revolving noncollateralized credit agreement, which established a line of credit facility of $125 million, with a letter of credit sub-facility, expiring on December 5, 2016, with a syndicate of eight financial institutions. The credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HEI’s short-term and long-term indebtedness, to make investments in or loans to subsidiaries and for HEI’s working capital and general corporate purposes.
Changes in long-term debt.
March 6, 2013 notes. On March 6, 2013, HEI entered into a First Supplement (the First Supplement) to the Master Note Purchase Agreement dated March 24, 2011 (the Note Agreement). Under the First Supplement, HEI issued $50 million of its unsecured, 3.99% Series 2013A Senior Notes, due March 6, 2023, via a private placement with The Prudential Insurance Company of America, Prudential Arizona Reinsurance Captive Company and The Lincoln National Life Insurance Company.
The Note Agreement, as modified by the First Supplement (which includes representations that supersede and supplement the representations in the Note Agreement), contains customary representations and warranties,
28
affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the Notes then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s existing amended revolving noncollateralized credit agreement described above and in HEI’s Form 10-K for the year ended December 31, 2012. For example, under the Note Agreement, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less (actual ratio of 18% as of June 30, 2013, as calculated under the agreement) or “Consolidated Net Worth” of at least $975 million (actual Net Worth of $1.7 billion as of June 30, 2013, as calculated under the agreement).
The net proceeds from the issuance of the Notes were used by HEI to refinance $50 million of its unsecured, 5.25% Medium-Term Notes, Series D, which matured on March 7, 2013.
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Operating revenues
728,793
787,685
1,444,990
1,535,623
Operating expenses
Fuel oil
289,278
331,064
594,378
658,903
Purchased power
178,444
188,352
331,808
353,141
Other operation
66,184
64,516
137,607
126,365
Maintenance
27,340
31,235
57,042
61,273
Depreciation
38,590
36,133
76,870
72,615
Taxes, other than income taxes
68,759
76,304
136,446
147,299
18,333
18,574
32,428
35,939
Total operating expenses
686,928
746,178
1,366,579
1,455,535
Operating income
41,865
41,507
78,411
80,088
Other, net
940
1,414
3,252
2,723
Income tax benefit (expense)
(51
(291
(95
Total other income
2,508
3,360
5,736
6,565
Interest and other charges
Interest on long-term debt
14,614
15,323
29,228
29,706
Amortization of net bond premium and expense
647
661
1,294
1,406
Other interest charges (credits)
318
(99
633
(370
(398
(893
(1,128
(1,763
Total interest and other charges
15,181
14,992
30,027
28,979
229
458
Net income attributable to HECO
28,963
29,646
53,662
57,216
Preferred stock dividends of HECO
270
540
HEI owns all of the common stock of HECO. Therefore, per share data with respect to shares of common stock of HECO are not meaningful.
The accompanying notes for HECO are an integral part of these consolidated financial statements.
Other comprehensive income, net of taxes:
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $3,195 and $2,142 for the three months ended June 30, 2013 and 2012 and $6,590 and $4,354 for the six months ended June 30, 2013 and 2012, respectively
5,016
3,364
10,347
6,836
35
152
Comprehensive income attributable to Hawaiian Electric Company, Inc.
28,710
29,451
53,157
56,828
(dollars in thousands, except par value)
Utility plant, at cost
Land
51,622
51,568
Plant and equipment
5,492,118
5,364,400
Less accumulated depreciation
(2,082,532
(2,040,789
Construction in progress
166,902
151,378
Net utility plant
3,628,110
3,526,557
Current assets
8,617
17,159
Customer accounts receivable, net
196,643
210,779
Accrued unbilled revenues, net
139,187
134,298
Other accounts receivable, net
10,059
28,176
Fuel oil stock, at average cost
117,445
161,419
Materials and supplies, at average cost
58,224
51,085
Prepayments and other
38,301
32,865
63,672
51,267
Total current assets
632,148
687,048
Other long-term assets
821,353
813,329
Unamortized debt expense
9,948
10,554
70,260
71,305
Total other long-term assets
901,561
895,188
Capitalization and liabilities
Capitalization
Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 14,665,264 shares)
97,788
Premium on capital stock
468,045
919,606
907,273
Accumulated other comprehensive loss, net of income tax benefits-retirement benefit plans
(935
(970
Common stock equity
1,484,504
1,472,136
Cumulative preferred stock — not subject to mandatory redemption
Long-term debt, net
1,147,877
1,147,872
Total capitalization
2,666,674
2,654,301
Commitments and contingencies (Note 5)
Current liabilities
Short-term borrowings from nonaffiliates
53,992
150,877
186,824
Interest and preferred dividends payable
20,325
21,092
Taxes accrued
218,850
251,066
77,895
62,879
Total current liabilities
521,939
521,861
Deferred credits and other liabilities
456,952
417,611
327,254
Unamortized tax credits
69,526
66,584
605,026
620,205
95,111
100,637
Total deferred credits and other liabilities
1,553,869
1,527,111
Total capitalization and liabilities
Consolidated Statements of Changes in Common Stock Equity (unaudited)
Premium on capital
stock
earnings
income (loss)
14,665
(40,789
14,234
94,911
426,921
881,041
(32
1,402,841
(36,522
Common stock issue expense
426,922
901,195
1,423,148
2,884
2,770
38,780
42,524
Change in tax credits, net
2,997
2,880
Decrease (increase) in accounts receivable
32,253
(10,958
Increase in accrued unbilled revenues
(4,889
(32,053
Increase in materials and supplies
(7,139
(7,599
Increase (decrease) in accounts payable
(41,234
5,931
(38,123
(21,141
(40,586
(52,086
41,575
31,166
(9,419
(37,942
111,702
(21,525
(150,251
(141,618
623
(132,440
(114,637
Preferred stock dividends of HECO and subsidiaries
(998
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less
44,242
(9
(1,929
12,196
93,293
(8,542
(42,869
48,806
5,937
The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto incorporated by reference in HECO’s Form 10-K for the year ended December 31, 2012 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2013.
In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the financial position of HECO and its subsidiaries as of June 30, 2013 and December 31, 2012, the results of their operations for the three and six months ended June 30, 2013 and 2012 and their cash flows for the six months ended June 30, 2013 and 2012. All such adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.
2 · Unconsolidated variable interest entities
HECO Capital Trust III. HECO Capital Trust III (Trust III) was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to HECO, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by HECO in the principal amount of $31.5 million and issued by Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) each in the principal amount of $10 million, (iii) making distributions on these trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are currently redeemable at the issuer’s option without premium. The 2004 Debentures, together with the obligations of HECO, HELCO and MECO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of HELCO and MECO under their respective debentures, are the sole assets of Trust III. Taken together, HECO’s obligations under the HECO debentures, the HECO indenture, the subsidiary guarantees, the trust agreement, the expense agreement and trust guarantee provide, in the aggregate, a full, irrevocable and unconditional guarantee of payments of amounts due on the Trust Preferred Securities. Trust III has at all times been an unconsolidated subsidiary of HECO. Since HECO, as the common security holder, does not absorb the majority of the variability of Trust III, HECO is not the primary beneficiary and does not consolidate Trust III in accordance with accounting rules on the consolidation of variable interest entities (VIEs). Trust III’s balance sheets as of June 30, 2013 and December 31, 2012 each consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statements for the six months ended June 30, 2013 and 2012 each consisted of $1.7 million of interest income received from the 2004 Debentures, $1.6 million of distributions to holders of the Trust Preferred Securities, and $0.1 million of common dividends on the trust common securities to HECO. As long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro-rata distributions, subject to certain subordination
provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.
Power purchase agreements. As of June 30, 2013, HECO and its subsidiaries had six PPAs for firm capacity and other PPAs with smaller independent power producers (IPPs) and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kW or less who buy power from or sell power to the utilities), none of which are currently required to be consolidated as VIEs. Approximately 91% of the firm capacity is purchased from AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs were as follows:
AES Hawaii
37
60
72
83
143
HEP
Other IPPs
41
38
69
Total IPPs
178
188
332
353
Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization,” and thus excluded from the scope of accounting standards for VIEs. A windfarm and Kalaeloa provided sufficient information, as required under their PPAs or amendments, such that HECO could determine that consolidation was not required. Management has concluded that the consolidation of some IPPs is not required as HECO and its subsidiaries do not have variable interests in the IPPs because the PPAs do not require them to absorb any variability of the IPPs.
An enterprise with an interest in a VIE or potential VIE created before December 31, 2003, and not thereafter materially modified, is not required to apply accounting standards for VIEs to that entity if the enterprise is unable to obtain the necessary information after making an exhaustive effort. HECO and its subsidiaries have made and continue to make exhaustive efforts to get the necessary information from two firm capacity producers and other small IPPs who entered into their PPAs prior to December 31, 2003 and have not provided such information, but have been unsuccessful to date as it was not a contractual requirement to provide such information prior to 2004. If the requested information is ultimately received from the remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs. The consolidation of any significant IPP could have a material effect on the Company’s and HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities and the potential recognition of losses. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply accounting standards for VIEs.
Kalaeloa Partners, L.P. In October 1988, HECO entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, HECO and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that HECO makes to Kalaeloa include: (1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, (2) a fuel additives cost component, and (3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that HECO makes to Kalaeloa are fixed in accordance with the PPA. Kalaeloa also has a steam delivery cogeneration contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.
Pursuant to the current accounting standards for VIEs, HECO is deemed to have a variable interest in Kalaeloa by reason of the provisions of HECO’s PPA with Kalaeloa. However, management has concluded that HECO is not the primary beneficiary of Kalaeloa because HECO does not have the power to direct the activities that most
significantly impact Kalaeloa’s economic performance nor the obligation to absorb Kalaeloa’s expected losses, if any, that could potentially be significant to Kalaeloa. Thus, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor affecting the level of expected losses HECO could potentially absorb is the fact that HECO’s exposure to fuel price variability is limited to the remaining term of the PPA as compared to the facility’s remaining useful life. Although HECO absorbs fuel price variability for the remaining term of the PPA, the PPA does not currently expose HECO to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through HECO’s ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates. As of June 30, 2013, HECO’s accounts payable to Kalaeloa amounted to $23 million.
3 · Revenue taxes
HECO and its subsidiaries’ operating revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. However, HECO and its subsidiaries’ revenue tax payments to the taxing authorities in the period are based on the prior year’s billed revenues (in the case of public service company taxes and PUC fees) or on the current year’s cash collections from electric sales (in the case of franchise taxes). For the six months ended June 30, 2013 and 2012, HECO and its subsidiaries included approximately $129 million and $140 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.
4 · Retirement benefits
Defined benefit pension and other postretirement benefit plans information. For the first six months of 2013, HECO and its subsidiaries contributed $41 million to their pension and other postretirement benefit plans, compared to $52 million in the first six months of 2012. HECO and its subsidiaries’ current estimate of contributions to their pension and other postretirement benefit plans in 2013 is $81 million, compared to contributions of $63 million in 2012. In addition, HECO and its subsidiaries expect to pay directly $1.0 million of benefits in 2013, compared to $0.5 million paid in 2012.
On July 6, 2012, President Obama signed the MAP-21, which included provisions related to the funding and administration of pension plans. This law does not affect the utilities’ accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The utilities elected to apply MAP-21 for 2012, which improved the plan’s AFTAP for funding and benefit distribution purposes and thereby reduced the 2012 minimum funding requirement and lifted the restrictions on accelerated distribution options (which restrictions were in effect April 1, 2011 to September 30, 2012) for HECO and its subsidiaries. The effects of MAP-21 are expected to cause the minimum required funding under ERISA to be less than the net periodic cost for 2013 and 2014; therefore, the utilities expect to contribute the net periodic cost for these years as they did for 2012. If the AFTAP falls below 80% in the future, the restrictions on accelerated distribution options may apply again.
36
The components of net periodic benefit cost were as follows:
13,638
11,000
1,067
959
27,241
20,802
2,081
2,007
14,883
15,465
1,783
2,147
29,559
30,726
4,352
(16,185
(15,942
(2,480
(2,519
(32,275
(32,002
(5,000
(5,098
Amortization of net transition obligation
(2
(4
Amortization of net prior service gain
(116
(172
(451
(232
(344
(902
8,509
5,845
268
288
17,299
11,714
772
728
20,729
16,196
187
422
41,592
30,896
595
1,083
15,443
11,219
28,870
22,062
HECO and its subsidiaries recorded retirement benefits expense of $21 million and $15 million for the first six months of 2013 and 2012, respectively. The electric utilities charged a portion of the net periodic benefit cost to electric utility plant.
The utilities have implemented pension and OPEB tracking mechanisms under which all of their retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with GAAP are recovered over time. Under the tracking mechanisms, these retirement benefit costs that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the respective utility’s next rate case.
Accumulated other comprehensive income. Reclassifications out of AOCI were as follows:
See above
Defined contribution plan information. For the first six months of 2013 and 2012, the utilities’ expense for its defined contribution pension plan was $0.3 million and de minimis, respectively.
5 · Commitments and contingencies
Utility projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income.
In May 2011, the PUC ordered independently conducted regulatory audits on the reasonableness of costs incurred for HECO’s East Oahu Transmission Project (EOTP), Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, and Customer Information System (CIS) project. However, in March 2012, the PUC eliminated the requirement for a regulatory audit for the EOTP Phase I in connection with an approved settlement of the EOTP
Phase I project cost issues and, in March 2013, the PUC eliminated the requirement for an audit of the CIP CT-1 and CIS project costs as described below.
On January 28, 2013, HECO and its subsidiaries and the Consumer Advocate, signed a settlement agreement (2013 Agreement), subject to PUC approval, to write-off $40 million of costs in lieu of conducting the regulatory audits of the CIP CT-1 project and the CIS project. Based on the 2013 Agreement, as of December 31, 2012, the utilities recorded an after-tax charge to net income of approximately $24 million—$17.1 million for HECO, $3.4 million for HELCO, and $3.2 million for MECO. The remaining recoverable costs of $52 million were included in rate base as of December 31, 2012.
As part of the 2013 Agreement, HELCO would withdraw its 2013 test year rate case, and delay filing a new rate case until a 2016 test year. Additionally, HECO would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. For both utilities, the existing terms of the last rate case decisions would continue. HECO would also be allowed to record Revenue Adjustment Mechanism (RAM) revenues starting on January 1 of 2014, 2015 and 2016. The cash collection of RAM revenues would remain unchanged, starting June 1 of each year through May 31 of the following year.
On March 19, 2013, the PUC issued a decision and order (2013 D&O) approving the 2013 Agreement, with the following clarifications, none of which changed the financial impact recorded as of December 31, 2012: (1) the PUC reiterated its authority to examine and ascertain what post go-live CIS costs would be subject to regulatory review in future rate cases; (2) the PUC discouraged requesting single issue cost deferral accounting and/or cost recovery mechanisms during the period of rate case deferral by HECO and HELCO; (3) the PUC approved the agreed-upon recovery of CIP CT-1 and CIS project costs through the RAM, as set forth in the 2013 Agreement, however not setting a precedent for future projects; and (4) the PUC reaffirmed its right to rule on the substance of the MECO 2012 test year rate case in its ongoing rate case proceeding. On May 31, 2013, the PUC issued a final D&O in the MECO 2012 test year rate case. See “MECO 2012 test year rate case” below.
Renewable energy projects. HECO and its subsidiaries are committed to achieving or exceeding the State’s Renewable Portfolio Standard (RPS) goal of 40% renewable energy by 2030 and to meeting their commitments relating to decreasing the State’s dependence on imported fossil fuels under their 2008 Energy Agreement with the Governor, the State Department of Business, Economic Development and Tourism and the Consumer Advocate (Energy Agreement). The utilities continue to evaluate and pursue opportunities with developers of proposed projects to integrate power into its grid from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave, geothermal and others. In December 2009, the PUC allowed HECO to defer the costs of studies for the large wind project for later review of prudence and reasonableness. In April 2013, the PUC approved the recovery of $3.9 million in costs for stage 1 studies for the large wind project over a three-year period, with carrying costs to be accrued over the recovery period at the rate of 1.75% per annum, through the Renewable Energy Infrastructure Program (REIP) Surcharge.
In November 2011, HECO and MECO filed their application to seek PUC approval to defer for later recovery approximately $555,000 (split evenly between HECO and MECO) also through the REIP surcharge for additional studies to determine the value proposition of interconnecting the islands of Oahu and of Maui County (Maui, Lanai, and Molokai) and if doing so would be operationally beneficial and cost-effective. In August 2012, the PUC allowed HECO and MECO to defer the outside service costs for the additional studies for later review of prudence and reasonableness. The specific amount to be recovered, as well as the recovery mechanism and the terms of the recovery mechanism, were to be determined at a later date.
A revised draft Request for Proposals (RFP) for 200 MW or more of renewable energy to be delivered to Oahu from any of the Hawaiian Islands was posted on HECO’s website prior to the issuance of a proposed final RFP. In February 2012, the PUC granted HECO’s request for deferred accounting treatment for the inter-island project support costs. The amount of the deferred costs was limited to $5.89 million. On July 11, 2013, the PUC issued orders related to the 200 MW RFP. First, it issued an order that HECO shall amend its current draft of the Oahu 200 MW RFP to remove references to the Lanai Wind Project, eliminate solicitations for an undersea transmission cable, and amend the draft RFP to reflect other guidance provided in the order. Second, it initiated an investigative proceeding to review the progress of the Lanai Wind Project stating that there was an uncertainty whether the
project developer retained an equivalent ability to develop the project as when it submitted its bid in 2008 and its term sheet in 2011. The PUC also stated that it will review the PPA (if one is completed) and, as part of that process, determine whether the Lanai Wind Project should be developed taking into account potential as-available renewable energy projects and grid infrastructure options. The PUC stated it intends to evaluate the project as a combined resources proposal (i.e., wind project and generation tie transmission cable between the islands of Oahu and Lanai). Third, it initiated a proceeding to solicit information and evaluate whether an interisland grid interconnection transmission system between the islands of Oahu and Maui is in the public interest, given the potential for large-scale wind and solar projects on Maui.
In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50 MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii, and in July 2012, HELCO filed an application to defer 2012 costs related to the Geothermal RFP. In February 2013, HELCO issued the Final Geothermal RFP. Six bids were received in April 2013 and are being evaluated.
In June 2013, HECO filed an application to seek PUC approval of Waivers from the Framework for Competitive Bidding for five projects (4 photovoltaic and 1 wind) selected as part of HECO’s “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding.”
Environmental regulation. HECO and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. In recent years, legislative, regulatory and governmental activities related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.
On April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at HECO’s power plants on the island of Oahu. If adopted as proposed, management believes the proposed regulations would require significant capital and annual other operation and maintenance (O&M) expenditures. On June 11, 2012, the EPA published additional information on the section 316(b) rule making that indicates that the EPA is considering establishing lower cost compliance alternatives in the final rule. The EPA has delayed issuance of the final section 316(b) rule until November 2013.
On February 16, 2012, the Federal Register published the EPA’s final rule establishing the EPA’s National Emission Standards for Hazardous Air Pollutants for fossil fuel-fired steam electrical generating units (EGUs). The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at HECO’s power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Based on a review of the final rule and the benefits and costs of alternative compliance strategies, HECO has selected a MATS compliance strategy based on switching to lower emission fuels. The use of lower emission fuels will provide for MATS compliance at lower overall costs and avoid the reduction in operational flexibility imposed by emissions control equipment. As provided in the MATS regulations, HECO will be requesting a one-year extension resulting in a MATS compliance date of April 16, 2016. On February 6, 2013, the EPA issued a guidance document titled “Next Steps for Area Designations and Implementation of the Sulfur Dioxide National Ambient Air Quality Standard,” which outlines a process that will provide the states additional flexibility and time for their development of one-hour sulfur dioxide NAAQS implementation plans. HECO will work with the Hawaii Department of Health (DOH) and the EPA in the rulemaking process for these implementation plans to insure development of cost-effective strategies for NAAQS compliance. Based on the February 6, 2013 EPA guidance document, current estimates of the compliance date for the one-hour sulfur dioxide NAAQS is in the 2022 or later timeframe.
Depending upon the final outcome of the CWA 316(b) regulations, the specific measures required for MATS compliance, and the rules and guidance developed for implementation of more stringent National Ambient Air Quality Standards, HECO and its subsidiaries may be required to incur material capital expenditures and other compliance costs, but such amounts are not determinable at this time. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire or deactivate certain generating units earlier than anticipated.
39
HECO, HELCO and MECO, like other utilities, periodically experience petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. HECO and its subsidiaries believe the costs of responding to such releases identified to date will not have a material adverse effect, individually or in the aggregate, on HECO’s consolidated results of operations, financial condition or liquidity.
Potential Clean Air Act Enforcement. On July 1, 2013, HELCO and MECO received a letter from the U.S. Department of Justice (DOJ) asserting potential violations of the Prevention of Significant Deterioration (PSD) and Title V requirements of the Clean Air Act involving the Hill and Kahului Power Plants. The EPA referred the matter to the DOJ for enforcement based on HELCO’s and MECO’s responses to information requests in 2010 and 2012. The letter expresses an interest in resolving the matter without the issuance of a notice of violation, and invites HELCO and MECO to engage in settlement negotiations. HELCO and MECO are in contact with the DOJ to seek additional information and to begin making arrangements for settlement discussions. HELCO and MECO cannot currently estimate the amount or effect of a settlement, if any. Neither HELCO nor MECO has identified at this time any projects or work relating to the information requests that may have been noncompliant with PSD or Title V requirements, and continue to investigate the potential bases for the DOJ’s claims.
Former Molokai Electric Company generation site. In 1989, MECO acquired by merger Molokai Electric Company. Molokai Electric Company had sold its former generation site (Site) in 1983, but continued to operate at the Site under a lease until 1985. The EPA has since performed Brownfield assessments of the Site that identified environmental impacts in the subsurface. Although MECO never operated at the Site and operations there had stopped four years before the merger, in discussions with the EPA and the DOH, MECO agreed to undertake additional investigations at the Site and an adjacent parcel that Molokai Electric Company had used for equipment storage (the Adjacent Parcel) to determine the extent of impacts of subsurface contaminants. A 2011 assessment by a MECO contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, MECO is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, fuel oils, and other subsurface contaminants. In March 2012, MECO accrued an additional $3.1 million (reserve balance of $3.6 million as of June 30, 2013) for the additional investigation and estimated cleanup costs at the Site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation. A revised draft site investigation work plan for site characterization was submitted to the DOH and EPA in June 2013.
Global climate change and greenhouse gas emissions reduction. National and international concern about climate change and the contribution of GHG emissions (including carbon dioxide emissions from the combustion of fossil fuels) to global warming have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions.
In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. The electric utilities participated in a Task Force established under Act 234, which was charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as those being implemented under the Energy Agreement. On October 19, 2012, the DOH posted the proposed regulations required by Act 234 for public hearing and comment. In general, the proposed regulations would require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce GHG emissions by 25% below 2010 emission levels by 2020. The proposed regulations also assess affected sources an annual fee based on tons per year of GHG emissions, beginning with emissions in calendar year 2012. The proposed DOH GHG rule also tracks the federal “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule, see below) and would create new thresholds for GHG emissions from new and existing stationary source facilities. HECO submitted comments on the proposed regulations in January 2013. HECO continues to monitor this rulemaking proceeding and will participate in the further development of the regulations.
Several approaches (e.g., “cap and trade”) to GHG emission reduction have been either introduced or discussed in the U.S. Congress; however, no federal legislation has yet been enacted.
On September 22, 2009, the EPA issued its Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions. The utilities have submitted the required reports for 2010, 2011 and 2012 to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, the EPA has also issued rules that begin to address GHG emissions from stationary sources, like the utilities’ EGUs.
In June 2010, the EPA issued its GHG Tailoring Rule. Effective January 2, 2011, under the Prevention of Significant Deterioration program, permitting of new or modified stationary sources that have the potential to emit GHGs in greater quantities than the thresholds in the GHG Tailoring Rule will entail GHG emissions evaluation, analysis and, potentially, control requirements. On March 27, 2012, the Federal Register published the EPA’s proposed New Source Performance Standard regulating carbon dioxide emissions from affected new fossil fuel-fired generating units. As proposed, the rule does not apply to non-continental units (i.e., in Hawaii and U.S. Territories) and therefore does not apply to the utilities. On June 25, 2013, President Obama directed the EPA Administrator to issue a new proposal no later than September 20, 2013. In addition, the President directed the Administrator to issue proposed standards, regulations, or guidelines for GHG emissions from existing power plants by no later than June 1, 2014, and final standards no later than June 1, 2015. HECO will participate in the federal GHG rulemaking process and support an exclusion for both new and existing non-continental sources.
HECO and its subsidiaries have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including, but not limited to, supporting DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, burning renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected MECO generating units, and testing biofuel blends in other HECO and MECO generating units. The utilities are also working with the State of Hawaii and other entities to pursue the use of liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used. Management is unable to evaluate the ultimate impact on the utilities’ operations of eventual comprehensive GHG regulation. However, management believes that the various initiatives it is undertaking will provide a sound basis for managing the electric utilities’ carbon footprint and meeting GHG reduction goals that will ultimately emerge.
While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate change on the weather (for example, floods or hurricanes), sea levels, and water availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquidity of the electric utilities. For example, severe weather could cause significant harm to the electric utilities’ physical facilities.
MECO 2012 test year rate case. On May 31, 2013, the PUC issued a final D&O in the MECO 2012 test year rate case. Final rates became effective August 1, 2013. The final D&O approved an increase in annual revenues of $5.3 million, which is $7.8 million less than the interim increase that had been in effect since June 1, 2012. Reductions from the interim D&O relate primarily to:
Lower ROACE
4.0
Customer Information System expenses
0.3
Pension and OPEB expense based on 3-year average
1.5
Integrated resource planning expenses
0.9
Operational and Renewable Energy Integration study costs
Total adjustment
7.8
According to the PUC, the reduction in the allowed ROACE from the stipulated 10% to the final approved 9% is composed of 0.5% allocation due to updated economic and financial market conditions manifested in lower interest rates in the 2012 test year and 0.5% for system inefficiencies reflected in over curtailment of renewable energy produced by independent power producers.
The PUC found that the record did not sufficiently support the normalization of 2013 and 2014 Customer Information System costs into the 2012 test year and ordered a downward adjustment to remove these costs from the test year.
The reduction in the pension and OPEB expense is due to applying a three-year average in the calculation of pension costs for the purpose of the 2012 test year. This is not a PUC decision to change the pension and OPEB tracking mechanisms, although the PUC emphasizes the need to evaluate alternatives to decrease or limit the growth in employee benefits costs.
The PUC removed integrated resource planning (IRP) expenses from the test year as it could not determine whether these expenses have been reasonably incurred for the 2012 test year as required by the PUC’s IRP Framework and stated that it will determine the appropriate level and method of cost recovery for MECO’s IRP expenses in the pending IRP proceeding.
The PUC reduced operational and renewable energy integration study costs because of the uncertainty regarding the scope of work and actual costs of these studies.
The PUC also continued MECO’s existing energy cost adjustment clause (ECAC) and power purchase adjustment clause (PPAC) design. The PUC stated that it will consider HECO, HELCO and MECO’s future actions to reduce fuel costs and increase use of renewable energy as it continues to review the design of the ECAC in the future.
On June 12, 2013, MECO filed a motion for partial reconsideration and partial clarification of the final D&O in the MECO 2012 test year rate case. The motion primarily requested reconsideration of the findings and conclusions concerning MECO’s 9% ROACE for the test year and also addressed other matters identified in the D&O, including treatment of IRP costs pending PUC determinations on such costs in a separate IRP proceeding. MECO requested a panel evidentiary hearing on ROACE, curtailment and technical studies, and pension expense. MECO also requested to partially stay the implementation of the final D&O, pending the presentation at the evidentiary hearing on its motion for partial reconsideration of the final D&O related to the ROACE reduction from 10.0% to 9.0% and the PUC’s final decision following the hearing. On July 2, 2013, the PUC issued an order denying MECO’s requests for an evidentiary hearing and for partial reconsideration, and dismissed MECO’s motion for partial stay. The order granted MECO’s motion for partial clarification to allow MECO to defer IRP costs incurred since June 2012, which through June 30, 2013 totaled approximately $0.7 million, until the level of costs are determined and a method of recovery is decided in the IRP proceeding.
Since the final rate increase was lower than the interim increase previously in effect, MECO recorded a charge, net of revenue taxes, of $7.6 million in the second quarter and will be refunding to customers approximately $9.7 million (which includes interest accrued since June 1, 2012) between September 2013 and October 2013. As a result of the D&O, in the second quarter MECO also recorded adjustments to reduce expenses by reducing employee benefits expenses by $1.8 million for adjustments to pension and OPEB costs, and to reclassify $0.7 million of IRP costs to deferred accounts.
As directed by the PUC, in June 2013, MECO filed documentation regarding the re-setting of its target heat rate to take into account the operation of the Auwahi wind farm and made its curtailment information available to the public on its website. In addition, as required by the final D&O, MECO will be filing by September 3, 2013, a System Improvement and Curtailment Reduction Plan. Management cannot predict any actions by the PUC as a result of these filings.
Asset retirement obligations. Asset retirement obligations (AROs) represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. HECO and its subsidiaries’ recognition of AROs have no impact on their earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by HECO and its subsidiaries relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.
Changes to the ARO liability included in “Other liabilities” on HECO’s balance sheet were as follows:
Balance, beginning of period
48,431
50,871
Accretion expense
363
862
Liabilities incurred
Liabilities settled
(1,506
(2,217
Revisions in estimated cash flows
(916
Balance, end of period
46,372
49,516
6 · Cash flows
Interest paid
Income taxes paid/(refunded)
7 · Fair value measurements
See Note 9 “Fair value measurements,” of HEI’s “Notes to Consolidated Financial Statements” for discussions of fair value estimates, grouping of financial instruments and methods and assumptions used to estimate the fair value of short-term borrowings and long-term debt.
The estimated fair values of certain of the electric utilities’ financial instruments were as follows:
Carrying amount
Estimated fair value (Level 2)
Short-term borrowings - nonaffiliates
Long-term debt, net, including amounts due within one year
1,164,470
1,181,631
Fair value measurements on a nonrecurring basis. From time to time, the utilities may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. The fair value of the utilities ARO (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by HECO’s credit spread. Also, see “Asset retirement obligations” in Note 5.
8 · Recent accounting pronouncements
Obligations resulting from joint and several liability. In February 2013, the FASB issued ASU No. 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date,” which provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The guidance requires entities to measure these obligations as the sum of the
amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amount of the obligation as well as other information. This guidance is effective for all fiscal years, and interim periods within those years, beginning after December 31, 2013.
HECO and its subsidiaries will retrospectively adopt ASU No. 2013-04 in the first quarter of 2014 and does not expect it to have a material impact on HECO and its subsidiaries’ results of operations, financial condition or liquidity.
HECO and its subsidiaries will prospectively adopt ASU No. 2013-11 in the first quarter of 2014 and does not expect it to have a material impact on the utilities’ results of operations, financial condition or liquidity.
9 · Credit agreement
HECO maintains an amended revolving noncollateralized credit agreement, which established a line of credit facility of $175 million, with a letter of credit sub-facility, expiring on December 5, 2016, with a syndicate of eight financial institutions. The credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HECO’s short-term indebtedness, to make loans to subsidiaries and for HECO’s capital expenditures, working capital and general corporate purposes.
10 · Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)
Deduct:
Income taxes on regulated activities
(18,333
(18,574
(32,428
(35,939
Revenues from nonregulated activities
(1,895
(1,867
(4,971
(3,539
Add: Expenses from nonregulated activities
955
1,719
816
Operating income from regulated activities after income taxes (per HECO consolidated statements of income)
11· Consolidating financial information
HECO is not required to provide separate financial statements or other disclosures concerning HELCO and MECO to holders of the 2004 Debentures issued by HELCO and MECO to 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 HECO. Consolidating information is provided below for these and other HECO subsidiaries for the periods ended and as of the dates indicated.
HECO also unconditionally guarantees HELCO’s and MECO’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 HELCO and MECO, (b) under their respective private placement note agreements and the HELCO notes and MECO notes issued thereunder and (c) relating to the trust preferred securities of Trust III (see Note 2 above). HECO is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on HELCO’s and MECO’s preferred stock if the respective subsidiary is unable to make such payments.
Consolidating Statement of Income (Loss) (unaudited)
Other subsidiaries
Consolidating adjustments
HECO Consolidated
521,730
106,374
100,689
203,379
33,569
52,330
135,271
29,278
13,895
48,084
10,146
7,954
19,651
4,301
3,388
25,001
8,547
5,042
49,287
9,960
9,512
12,886
3,060
2,387
493,559
98,861
94,508
28,171
7,513
6,181
Other income (loss)
1,247
192
121
Equity in earnings of subsidiaries
8,667
(8,667
702
111
(1
(39
Income tax benefits (expense)
(18
(15
Total other income (loss)
10,657
341
217
(8,706
9,901
2,751
1,962
411
117
119
(105
446
(342
(43
9,865
2,841
2,514
5,013
3,884
Preferred stock dividend of subsidiaries
133
Net income (loss) attributable to HECO
4,880
3,788
Consolidating Statement of Comprehensive Income (Loss) (unaudited)
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits
681
622
(1,303
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes
(680
(623
1,303
Comprehensive income (loss) attributable to common shareholder
4,881
3,787
45
567,527
111,741
108,417
241,393
30,616
59,055
141,136
37,395
9,821
44,621
9,947
20,542
4,885
5,808
8,301
5,095
55,440
10,423
10,441
13,361
2,831
2,382
539,230
104,399
102,549
28,297
7,342
5,868
1,654
160
183
8,250
(8,250
1,173
144
1,415
(36
11,041
259
329
(8,268
10,190
2,913
2,220
429
124
Other interest charges
(167
66
(64
(69
9,692
2,977
2,341
4,624
3,856
3,760
518
412
(930
(511
(406
917
4,498
3,766
(8,263
46
1,027,559
212,390
205,041
425,346
66,505
102,527
246,426
59,400
25,982
98,195
21,210
18,202
41,303
8,107
49,708
17,094
10,068
97,372
19,646
19,428
20,197
5,774
6,457
978,547
197,736
190,296
49,012
14,654
14,745
2,230
330
19,652
(19,652
309
(67
Income tax expense
(189
(41
(61
24,416
442
(19,719
19,803
5,501
3,924
821
234
239
563
(910
(135
(83
19,766
5,685
4,643
9,567
10,544
267
191
9,300
10,353
1,440
1,279
(2,719
(1,441
(1,279
2,720
9,299
(19,651
47
1,098,140
224,068
213,415
476,419
63,026
119,458
265,916
71,303
15,922
84,569
18,963
22,833
41,378
9,134
45,308
16,737
10,570
105,993
20,886
20,420
25,324
7,054
3,561
1,044,907
207,103
203,525
53,233
16,965
9,890
3,235
285
417
16,740
(16,740
2,266
(28
Income tax benefits
(65
22,176
485
674
(16,768
19,320
5,898
4,488
912
245
249
(554
53
159
(1,485
(115
18,193
6,081
4,733
11,369
5,831
11,102
5,640
1,050
885
(1,935
(1,037
(873
1,910
11,115
5,652
(16,765
48
Consolidating Balance Sheet (unaudited)
43,424
5,182
3,016
3,423,045
1,095,425
973,648
(1,208,090
(445,035
(429,407
131,745
21,635
13,522
2,390,124
677,207
560,779
Investment in wholly owned subsidiaries, at equity
503,388
(503,388
4,914
3,401
199
Advances to affiliates
18,000
9,600
(27,600
137,171
30,867
28,605
102,695
17,241
19,251
15,027
2,308
1,420
(8,696
84,748
9,673
23,024
35,848
6,816
15,560
26,194
5,805
6,385
51,214
5,815
6,643
475,811
91,526
101,087
(36,379
606,971
110,163
104,219
6,655
1,943
1,350
45,995
9,281
14,984
659,621
121,387
120,553
4,028,944
890,120
782,419
(539,767
271,013
232,272
Cumulative preferred stock—not subject to mandatory redemption
22,293
7,000
5,000
780,546
201,331
166,000
2,287,343
479,344
403,272
Short-term borrowings from affiliate
101,725
23,747
25,405
13,805
4,105
2,427
152,905
33,299
32,646
51,807
9,564
25,291
(8,767
383,834
70,715
103,769
330,551
74,285
52,116
222,193
70,171
34,890
42,396
13,508
13,622
449,039
78,265
77,722
65,242
16,146
13,723
1,109,421
252,375
192,073
248,346
87,686
83,305
43,370
3,325,862
1,086,048
952,490
(1,185,899
(433,531
(421,359
130,143
12,126
9,109
2,313,476
669,825
543,256
497,939
(497,939
8,265
5,441
3,349
104
9,400
18,050
(27,450
154,316
29,772
26,691
100,600
14,393
19,305
33,313
1,122
(9,275
123,176
15,485
22,758
31,779
5,336
13,970
21,708
5,146
6,011
42,675
4,056
4,536
525,232
98,801
99,636
(36,725
601,451
109,815
102,063
7,042
2,066
1,446
46,586
9,871
14,848
655,079
121,752
118,357
3,991,726
890,378
761,249
(534,664
268,908
228,927
201,326
2,274,975
477,234
399,927
Current portion of long-term debt
134,651
27,457
24,716
14,479
4,027
2,593
174,477
38,778
37,811
47,203
10,310
14,634
(9,268
388,860
80,572
89,154
302,569
68,479
46,563
218,437
67,359
36,278
39,827
13,450
13,307
459,765
80,686
79,754
68,783
17,799
14,055
1,089,381
247,773
189,957
238,510
84,799
82,211
Consolidating Statement of Changes in Common Stock Equity (unaudited)
(7,194
(7,008
14,202
280,468
235,568
(516,143
(6,569
(4,373
10,942
Common stock issue expenses
285,014
236,847
105
(521,966
Consolidating Statement of Cash Flows (unaudited)
Cash flows from operating activities:
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
(19,702
(50
Common stock dividends received from subsidiaries
14,227
(14,202
(160
716
27,560
5,584
5,636
2,598
70
(2,230
(330
(215
Changes in assets and liabilities:
35,431
(2,281
(318
(579
Decrease (increase) in accrued unbilled revenues
(2,095
(2,848
38,428
5,812
(266
(4,069
(1,480
(1,590
(25,647
(4,852
(7,087
Decrease in accounts payable
(36,971
(2,513
(1,750
Change in prepaid and accrued income and utility revenue taxes
(25,831
(6,171
(6,121
(29,766
(5,389
(5,431
30,929
5,261
5,385
(12,731
(3,171
5,929
579
(9,394
93,341
15,069
17,495
Cash flows from investing activities:
(104,846
(22,367
(23,038
11,924
4,270
Advances from (to) affiliates
(8,600
8,450
150
(100,899
(9,647
(22,044
Cash flows from financing activities:
(540
(267
(191
45,542
(150
Net cash provided by (used in) financing activities
4,207
(7,462
1,399
14,052
(3,351
(2,040
(3,150
(16,790
10,967
(10,942
347
1,418
1,005
31,673
5,857
4,994
2,641
125
114
(3,235
(285
(417
Increase in accounts receivable
(17,653
(137
(702
7,534
(21,274
(6,456
(4,323
Increase in fuel oil stock
(28,905
(514
(6,474
(6,172
(1,022
(405
(28,190
(3,234
(4,052
12,843
(6,938
(9,994
(6,347
(4,800
(38,693
(6,536
(6,857
22,947
4,089
4,130
(26,968
(3,432
(7,534
(37,917
(13,932
4,694
(1,342
(3
(111,011
(17,405
(13,202
23,693
2,327
961
(8,700
26,800
18,500
(36,600
Net cash provided by (used in) investing activities
(96,018
11,722
6,259
327,000
31,000
59,000
(219,580
(41,200
(67,720
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less
(1,058
8,700
36,600
(1,746
171
(354
67,554
(16,865
(4,938
47,542
(42,396
(21
44,819
3,383
496
2,423
2,934
475
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in HEI’s and HECO’s Form 10-K for 2012 and should be read in conjunction with the 2012 annual consolidated financial statements of HEI and HECO and notes thereto included and incorporated by reference, respectively, in HEI’s and HECO’s 2012 Form 10-K, as well as the quarterly (as of and for the three and six months ended June 30, 2013) financial statements and notes thereto included in this Form 10-Q.
RESULTS OF OPERATIONS
(in thousands, except per
Three months ended
June 30
%
Primary reason(s) for
share amounts)
change
significant change*
Decrease for the electric utility segment, partly offset by increase in bank segment
Increase for the electric utility and bank segments and a reduced operating loss for the “other” segment
Higher operating income and lower “interest expense—other than on deposit liabilities and other bank borrowings” partly offset by lower AFUDC
Higher net income, partly offset by higher weighted average shares outstanding
Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans
Six months ended
Decrease for the electric utility segment, partly offset by an increase in the bank segment and a reduced operating loss for the “other” segment
Lower operating income, higher “interest expense—other than on deposit liabilities and other bank borrowings” and lower AFUDC, partly offset by lower income taxes
Lower net income and higher weighted average shares outstanding
* Also, see segment discussions which follow.
Notes: The Company’s effective tax rates (combined federal and state) for the second quarters of 2013 and 2012 were 37%. The Company’s effective tax rates (combined federal and state) for the first six months of 2013 and 2012 were 36%.
HEI’s consolidated ROACE was 8.5% for the twelve months ended June 30, 2013 and 10.4% for the twelve months ended June 30, 2012.
Dividends. The payout ratios for the first six months of 2013 and full year 2012 were 82% and 87%, respectively. HEI currently expects to maintain the dividend at its present level; however, the HEI Board of Directors evaluates the dividend quarterly and considers many factors in the evaluation, including but not limited to the Company’s results of operations, the long-term prospects for the Company, and current and expected future economic conditions.
Economic conditions.
Note: The statistical data in this section is from public third-party sources (e.g., Department of Business, Economic Development and Tourism (DBEDT); University of Hawaii Economic Research Organization (UHERO); U.S. Bureau of Labor Statistics; Blue Chip Economic Indicators; U.S. Energy Information Administration; Hawaii Tourism Authority (HTA); Honolulu Board of REALTORS®; Bureau of Economic Analysis and national and local newspapers).
Hawaii’s tourism industry, a significant driver of Hawaii’s economy, set new records in 2012 and continues to grow in 2013, although at a slower pace. State visitor arrivals grew by 5.6% in the first half of 2013 over 2012. State visitor expenditures also grew, increasing by 6.9% in the first half of 2013 over 2012. Average daily hotel room rates also continued to rise, but hotel occupancies were weaker. The outlook for the visitor industry remains positive, but is expected to expand at a slower pace. The Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the third quarter of 2013 to increase by 1.4% over the third quarter of 2012.
Hawaii’s unemployment rate continues to decline, falling to 4.6% in June 2013, lower than the state’s 6.0% rate in June 2012 and the June 2013 national unemployment rate of 7.6%.
Hawaii real estate activity, as indicated by the home resale market, strengthened in the first half of 2013. The median sales price for single family residential homes on Oahu increased by 0.8% and closed sales increased 11.6% in the first half of 2013 as compared to the same period in 2012. Oahu condominiums maintained strong momentum with median sales prices rising 6.8% and closed sales increasing 18.8% for the first half of 2013 as compared to the first half of 2012. The announcements of several new planned condominium projects in Honolulu were met with immediate interest, and several projects generated strong pre-sale demand.
Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. The dramatic reduction in Japan’s nuclear production following the tragic earthquake and tsunami in March 2011 increased regional demand for energy supplies, including petroleum, and the prices of the utilities’ fuels have accordingly remained at the elevated 2011 level through 2012 and into 2013.
At its meeting on June 18-19, 2013, the Federal Open Market Committee (FOMC) announced that it expects to continue to hold the federal funds rate target at 0% to 0.25% for as long as the unemployment rate is above 6.5% and the inflation outlook remains no more than 0.5 percentage point above a longer-run 2% goal. The FOMC stated it will continue purchases of Treasury and agency mortgage-backed securities and employ other policy tools as appropriate to support progress toward the FOMC’s statutory mandate of maximum employment and price stability. In June 2013, however, Chairman Ben Bernanke indicated that if the economy continues improving, the Fed may slow its bond-buying program later this year and possibly end it in mid-2014, thereby putting upward pressure on interest rates.
Overall, Hawaii’s economy is expected to see increased growth in 2013 and 2014 with local economic growth supported by continued expansion of the visitor industry and recovery in the construction industry. U.S. budget cuts, continued uncertainty in global economies, heightened tensions in Asia and potential pandemics pose possible risks to local economic growth.
Despite economic improvement, the electric utilities’ KWH sales declined in 2012 and continued to decline in 2013. Based on expectations of additional customer renewable self-generation and energy-efficiency installations, the electric utilities’ 2013 and 2014 KWH sales are expected to further decline below 2012 levels.
Recent tax developments. The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 contained major tax provisions that impacted the Company through 2012, including the 50% and 100% bonus depreciation provisions for qualified property that resulted in an estimated net increase in federal tax depreciation of $116 million for 2012 over depreciation to which the Company would otherwise be entitled without the bonus provisions. The additional depreciation is attributable to the utilities. In January 2013, the American Taxpayer Relief Act of 2012 was signed into law and provided a one year extension of 50% bonus depreciation, which is estimated to increase the Company’s federal tax depreciation for 2013 by $120 million, primarily attributable to the utilities.
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The Internal Revenue Service (IRS) issued proposed and temporary regulations that provide a general framework for determining whether expenditures are deductible as repairs, effective January 1, 2014. The IRS plans to issue final regulations related to repairs deductions in 2013. In the interim, the IRS has directed its examination teams to discontinue the current examination of these repairs issues and withdraw any proposed adjustments previously made in the examination of tax years prior to 2012. Once final regulations are issued, the Company will review the regulations and will analyze any subsequently issued transitional rules and guidance for their impacts and for the opportunities they present for the current and future years.
The IRS recently released a revenue procedure relating to deductions for repairs of generation property, which provides some guidance (that is elective) for taxpayers that own steam or electric generation property. This guidance defines the relevant components of generation property to be used in determining whether such component expenditures should be deducted as repairs or capitalized and depreciated by taxpayers. The revenue procedure also provides an extrapolation methodology that could be used by taxpayers in determining deductions for prior years’ repairs without going back to the specific documentation of those years. The guidance does not provide specific methods for determining the repairs amount. The utilities have begun to evaluate the costs and benefits of adopting this guidance, in order to determine whether and when the election should be made.
Health care reform. On June 28, 2012, the US Supreme Court upheld the Patient Protection and Affordable Care Act, the 2010 health care reform law. Currently, Hawaii’s Prepaid Health Care Act generally provides greater benefits to employees and dependents because of cost sharing limitations. The Company will continue to comply with its obligations under these laws and to monitor the interaction of the state and federal laws.
Retirement benefits. For the first six month of 2013, the Company’s defined benefit pension and other postretirement benefit plans’ assets generated a gain, after investment management fees, of 7.1%. The market value of these assets as of June 30, 2013 was $1.2 billion (including $1.1 billion for the utilities) compared to $1.1 billion at December 31, 2012 (including $1.0 billion for the utilities).
The Company estimates that the cash funding for its defined benefit pension and other postretirement benefit plans in 2013 will be $83 million ($81 million by the utilities, $2 million by HEI and nil by ASB), which is expected to fully satisfy the minimum contribution requirements, including requirements of the utilities’ pension and other postretirement benefits tracking mechanisms and the plans’ funding policies.
Commitments and contingencies. See Note 4, “Bank subsidiary,” of HEI’s “Notes to Consolidated Financial Statements” and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”
Recent accounting pronouncements. See Note 11, “Recent accounting pronouncements,” of HEI’s “Notes to Consolidated Financial Statements.”
“Other” segment.
significant change
Operating loss
Lower administrative and general expenses
Net loss
Lower operating loss and interest expense
The “other” business segment includes results of the stand-alone corporate operations of HEI and American Savings Holdings, Inc. (ASHI), both holding companies; HEI Properties, Inc., a company holding passive, venture capital investments; and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; as well as eliminations of intercompany transactions.
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FINANCIAL CONDITION
Liquidity and capital resources. The Company believes that its ability to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund its contractual obligations and commercial commitments, its forecasted capital expenditures and investments, its expected retirement benefit plan contributions and other cash requirements for the foreseeable future.
The consolidated capital structure of HEI (excluding deposit liabilities and other bank borrowings) was as follows:
(dollars in millions)
84
Preferred stock of subsidiaries
1,625
1,594
3,208
100
3,135
HEI’s short-term borrowings and HEI’s line of credit facility were as follows:
Average balance
Short-term borrowings(1)
Commercial paper
Line of credit draws
Undrawn capacity under HEI’s line of credit facility (expiring December 5, 2016)
(1) This table does not include HECO’s separate commercial paper issuances and line of credit facilities and draws, which are disclosed below under “Electric utility—Financial Condition—Liquidity and capital resources.” The maximum amount of HEI’s external short-term borrowings during the first six months of 2013 was $96 million. At July 31, 2013, HEI had $70 million in outstanding commercial paper and its line of credit facility was undrawn.
HEI has a line of credit facility of $125 million (see Note 12 of HEI’s “Notes to Consolidated Financial Statements”). There are customary conditions which must be met in order to draw on it, including compliance with its covenants (such as covenants preventing HEI’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratios, as defined in the credit agreement, or meet other requirements may result in an event of default. For example, under the agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 18% as of June 30, 2013, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth of $1.7 billion as of June 30, 2013, as calculated under the agreement), or if HEI no longer owns HECO. The commitment fee and interest charges on drawn amounts under the credit agreement are subject to adjustment in the event of a change in HEI’s long-term credit ratings.
The Company raised $25 million through the issuance of approximately 0.9 million shares of common stock under the DRIP, the HEIRSP, ASB 401(k) Plan and other plans during the first six months of 2013.
In March 2013, HEI entered into equity forward transactions in which a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and such borrowed shares were sold pursuant to an HEI registered public offering. At June 30, 2013, the equity forward transactions could have been settled with physical delivery by HEI of 7 million newly-issued shares to the forward counterparty in exchange for cash of $178 million. HEI will not receive any proceeds from the sale of common stock until the equity forward transactions are settled. HEI anticipates physical settlement of the equity forward transactions before March 25, 2015, but the transactions may also be cash settled or net share settled.
On March 6, 2013, HEI issued $50 million of 3.99% Senior Notes due March 6, 2023 via a private placement. HEI used the net proceeds from the issuance of the Senior Notes to refinance $50 million of its 5.25% medium-term notes that matured on March 7, 2013. The Senior Notes contain customary representation and warranties, affirmative
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and negative covenants, and events of default (the occurrence of which may result in some or all of the notes then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit agreement. For example, see discussion of “Capitalization Ratio” and “Consolidated Net Worth” above.
For the first six months of 2013, net cash provided by operating activities of consolidated HEI was $131 million. Net cash used by investing activities for the same period was $240 million, due to HECO’s consolidated capital expenditures, a net increase in ASB’s loans held for investment and purchases of investment and mortgage-related securities, partly offset by repayments of investment and mortgage-related securities, proceeds from sale of investment securities and HECO’s contributions in aid of construction. Net cash provided by financing activities during this period was $44 million as a result of several factors, including net increases in deposit liabilities and short-term borrowings and proceeds from the issuance of common stock under HEI plans, partly offset by the payment of common stock dividends. Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), HECO’s periodic short-term borrowings from HEI (and related interest) and the payment of dividends to HEI, the electric utility and bank segments are largely autonomous in their operating, investing and financing activities. (See the electric utility and bank segments’ discussions of their cash flows in their respective “Financial condition—Liquidity and capital resources” sections below.) During the first six months of 2013, HECO and ASB (via ASHI) paid cash dividends to HEI of $41 million and $20 million, respectively.
CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION
The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 48 to 49, 64 to 67, and 78 to 80 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2012 Form 10-K.
Additional factors that may affect future results and financial condition are described on pages iv and v under “Forward-Looking Statements.”
MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES
In preparing financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.
In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that these policies are both the most important to the portrayal of the Company’s results of operations and financial condition, and currently require management’s most difficult, subjective or complex judgments.
For information about these material estimates and critical accounting policies, see pages 49 to 50, 67 to 68, and 80 to 81 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2012 Form 10-K.
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Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.
Utility strategic progress. In 2012 and the first six months of 2013, the utilities continued to make significant progress in implementing their renewable energy strategies to support Hawaii’s efforts to reduce its dependence on oil. The PUC issued several important regulatory decisions during the period, including a number of interim and final rate case decisions (see table in “Most recent rate proceedings” below).
The utilities are committed to achieving or exceeding the State’s Renewable Portfolio Standard goal of 40% renewable energy by 2030 (see “Renewable energy strategy” below). In addition, while it will not take precedence over the utilities’ work to increase their use of renewable energy, the utilities are also working with the State of Hawaii and other entities to examine the possibility of using liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used for the remaining generation.
Regulatory. In January 2013, the utilities and Consumer Advocate signed a settlement agreement (2013 Agreement), which the PUC approved with clarifications in March 2013 (2013 D&O). See “Utility projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” and the discussion under “Most recent rate proceedings” below.
With PUC approval, decoupling was implemented by HECO on March 1, 2011, by HELCO on April 9, 2012 and by MECO 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 revenue 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 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. The implementation of decoupling has resulted in an improvement in the utilities’ under-earning situation that has existed over the last several years. Prior to and during the transition to decoupling, however, the utilities’ returns have been well below PUC-allowed returns.
Under decoupling, the most significant drivers for improving earnings are:
1. completing major capital projects within PUC approved amounts and on schedule;
2. managing O&M expenses relative to authorized O&M adjustments; and
3. regulatory outcomes that cover O&M requirements and rate base items not included in the RAMs.
On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling and citing three years of implementation experience for HECO, the PUC opened an investigative docket to review whether the decoupling mechanism is functioning as intended. 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. HECO, HELCO, MECO and the Consumer Advocate are named as parties to this proceeding and filed a joint statement of position that any material changes to the current decoupling mechanism should be made prospectively after 2016 unless the utilities and the Consumer Advocate mutually agree to the change in this proceeding. Several parties have filed motions to intervene.
The utilities’ five-year 2013-2017 forecast reflects net capital expenditures of $2.9 billion and a compounded near-term annual rate base growth rate in the range of 5% to 10%. Many of the major initiatives within this forecast are expected to be completed beyond the 5-year period. Major initiatives which comprise approximately 35% of the 5-year plan include projects relating to: (1) environmental compliance; (2) fuel infrastructure investments; (3) new generation; and (4) infrastructure investments to integrate more energy from renewables into the system. Estimates for these initiatives could change over time, based on external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and the outcome of competitive bidding for new generation.
Actual and PUC-allowed (as of June 30, 2013) returns were as follows:
Return on rate base (RORB)*
ROACE**
Rate-making ROACE***
Twelve months ended June 30, 2013
Utility returns
7.73
6.54
7.01
6.80
5.18
7.39
10.05
7.02
8.60
PUC-allowed returns
8.11
8.31
7.34
10.00
9.00
Difference
(0.38
(1.77
(0.33
(3.20
(4.82
(1.61
0.05
(2.98
(0.40
* Based on recorded operating income and average rate base, both adjusted for items not included in determining electric rates.
** Recorded net income divided by average common equity.
*** ROACE adjusted to remove items not included by the PUC in establishing rates, such as the write-off of $40 million of CIS project costs, executive bonuses and advertising.
The approval of decoupling by the PUC has helped the utilities to gradually improve their ROACEs, which in turn will facilitate the utilities’ ability to effectively raise capital for needed infrastructure investments. However, the utilities continue to expect an ongoing structural gap between their PUC-allowed ROACEs and the ROACEs they actually achieve due to the following:
1) the timing of general rate case decisions,
2) the effective date of the RAMs,
3) the 5-year historical average for baseline plant additions, and
4) the PUC’s consistent exclusion of certain expenses from rates.
The structural gap in 2014 to 2016 is expected to be 80 to 110 basis points, an improvement of 40 basis points from management’s prior expectations. The improvement is due to the change in the timing of the recognition of the RAM revenues in 2014 to 2016 as defined in the 2013 Agreement. For 2013, the expected structural gap remains unchanged at 120 to 150 basis points. Between rate cases, items not covered by the annual RAMs could also have a negative impact on the actual ROACEs achieved by the utilities (primarily investments in software projects, changes in fuel inventory and O&M in excess of indexed escalations). The specific magnitude of the impact will depend on various factors, including the size of software projects, changes in fuel prices and management’s ability to manage costs within the current mechanisms.
Management expects the earned ROACE to gradually improve from 2014 to 2016.
As part of decoupling, HECO also tracks its rate-making ROACE as calculated under the earnings sharing mechanism and which includes only items considered in establishing rates. Earnings over and above the ROACE allowed by the PUC are shared between HECO and its ratepayers on a tiered basis. For 2012, HECO’s rate-making ROACE was 10.70%, which was above the PUC allowed 10% ROACE and triggered its earnings sharing mechanism. As a result, HECO will credit its customers $2.6 million for their portion of the earnings sharing. HECO’s 2012 rate-making ROACE of 10.70% included various adjustments to HECO’s actual ROACE of 7.57% such as the exclusion of the $40 million of CIS project costs pursuant to the 2013 Agreement, and of other expenses not considered in establishing electric rates (e.g., executive bonuses and advertising). HELCO’s rate-making ROACE was 7.79% and MECO’s rate-making ROACE was 6.69%, which did not trigger the earnings sharing mechanism.
Annual decoupling filings. On May 31, 2013, the PUC approved the revised annual decoupling filings for tariffed rates for HECO, HELCO and MECO that will be effective from June 1, 2013 through May 31, 2014. The amounts approved as noted below reflect the electric utilities’ agreements with the position of the Consumer Advocate. The revised tariffed rates include:
Annual incremental RAM adjusted revenues
Operations and maintenance
3.9
1.0
Invested capital
27.5
2.4
Total annual incremental RAM adjusted revenues
31.4
2.1
3.4
Accrued earnings sharing credits to be refunded
(2.6
Accrued RBA balance as of December 31, 2012 (and associated revenue taxes) to be collected
55.4
4.9
5.8
Results.
Increase
(decrease)
731
790
(59
Revenues. Decrease largely due to:
(56
Lower fuel prices and lower KWH sales adjusted for decoupling mechanisms and revenue taxes
Interim rate increase granted to MECO in its 2012 test year rate case
(8
MECO test year 2012 final (refund)
Interim and final rate increases granted to HECO in its 2011 test year rate case
289
331
(42
Fuel oil expense. Decrease largely due to lower fuel costs and less KWHs generated
(10
Purchased power expense. Decrease largely due to lower purchased power energy costs, partially offset by higher KWH purchased
94
Other operation and maintenance expenses. Decrease largely due to:
Higher customer service expenses
Reversal of 2011 expenses for the 200 MW RFP and CIS deferral costs in 2012
MECO final decision adjustments for deferral of pension/OPEB and IRP expenses
Decrease due to timing of overhauls
109
Other expenses. Decrease largely due to lower taxes other than income taxes due to lower operating revenues, partially offset by higher depreciation due to an increase in plant additions
61
Operating income. Slight decrease due to MECO 2012 test year refund, partially offset by lower O&M, MECO interim and HECO rate increases
Net income for common stock. Slight decrease largely due to lower operating income
2,247
2,257
Kilowatthour sales (millions)
69.3
68.0
1.3
Wet-bulb temperature (Oahu average; degrees Fahrenheit)
1,150
Cooling degree days (Oahu)
129.94
145.27
(15.33
Average fuel oil cost per barrel
1,450
1,539
(89
(93
594
659
Purchased power expense. Decrease largely due to lower purchased power energy costs, less KWH purchased and lower purchase capacity/non-fuel charges
195
Other operation and maintenance expenses. Increase largely due to:
Higher employee benefit costs
2012 increase in general liability reserve for an environmental matter
Operating income. Decrease largely due to MECO 2012 test year refund, higher O&M, partly offset by MECO interim and HECO rate increases
Net income for common stock. Decrease largely due to lower operating income
4,370
4,508
(138
67.6
1,903
2,011
(108
131.49
139.63
(8.14
450,455
448,001
2,472
Customer accounts (end of period)
Note: The electric utilities had effective tax rates for the second quarters of 2013 and 2012 of 39% and 38%, respectively, and for the first six months of 2013 and 2012 of 38%.
HECO’s consolidated ROACE was 6.6% for the twelve months ended June 30, 2013 and 8.7% for the twelve months ended June 30, 2012.
Other operation and maintenance expenses (excluding expenses covered by surcharges or by third parties) for 2013 are projected to be flat to approximately 1% over prior year, as the electric utilities expect to manage expenses to near-2012 levels.
See “Economic conditions” in the “HEI Consolidated” section above.
Most recent rate proceedings. Unless otherwise agreed or ordered, each electric utility shall initiate a rate proceeding every third year (on a staggered basis) to allow the PUC and the Consumer Advocate to regularly evaluate decoupling and the utility to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. The PUC may grant an interim increase within 10 to 11 months following the filing of an application, but there is no guarantee of such an interim increase and interim amounts collected are refundable, with interest, to the extent they exceed the amount approved in the PUC’s final D&O. The timing and amount of any final increase is determined at the discretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and RORB) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.
The following table summarizes certain details of each utility’s most recent rate cases, including the details of the increases requested, whether the utility and the Consumer Advocate reached a settlement that they proposed to the PUC, the details of any granted interim and final PUC D&O increases, and whether an interim or final PUC D&O remains pending.
Test year (dollars in millions)
Date (applied/ implemented)
% over rates in effect
ROACE (%)
RORB (%)
Rate base
Common equity %
Stipulated agreement reached with Consumer Advocate
2011 (1)
Request
7/30/10
113.5
6.6
10.75
8.54
1,569
56.29
Yes
Interim increase
7/26/11
53.2
3.1
1,354
Interim increase (adjusted)
4/2/12
58.2
1,385
5/21/12
58.8
1,386
Final increase
9/1/12
58.1
2010 (2)
12/9/09
20.9
6.0
8.73
487
55.91
1/14/11
10.50
8.59
465
1/1/12
5.2
4/9/12
4.5
2013 (3)
8/16/12
19.8
4.2
10.25
8.30
455
57.05
Closed
3/27/13
2012 (4)
7/22/11
6.7
11.00
8.72
393
56.85
6/1/12
13.1
3.2
7.91
56.86
8/1/13
5.3
Note: The “Request Date” reflects the application filing date for the rate proceeding. All other line items reflect the effective dates of the revised schedules and tariffs as a result of PUC-approved increases.
(1) HECO filed a request with the PUC for a general rate increase of $113.5 million, based on depreciation rates and methodology as proposed by HECO in a separate depreciation proceeding. HECO’s request was primarily to pay for major capital projects and higher O&M costs to maintain and improve service reliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and fuel security.
The $53.2 million, $58.2 million, and $58.8 million interim increases, and the $58.1 million final increase, include the $15 million in annual revenues that were being recovered through the decoupling RAM prior to the first interim increase.
(2) HELCO’s request was primarily to cover investments for system upgrade projects, two major transmission line upgrades and increasing O&M expenses. On February 8, 2012, the PUC issued a final D&O, which reflected the approval of decoupling and cost-recovery mechanisms, and on February 21, 2012, HELCO filed its revised tariffs to reflect the increase in rates. On April 4, 2012, the PUC issued an order approving the revised tariffs, which became effective April 9, 2012. HELCO implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. HELCO also reset the heat rates and implemented heat rate deadbands and the PPAC, which provides a surcharge mechanism that more closely aligns cost recovery with costs incurred. The revised tariffs reflect a lower increase in annual revenue requirement compared to the interim increase due to factors that became effective concurrently with the revised tariffs (lower depreciation rates and lower ROACE) and therefore, no refund to customers was required.
(3) HELCO’s request was required to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. As a result of the 2013 Agreement and 2013 D&O (described below), the rate case was withdrawn and the docket has been closed.
(4) MECO’s request was required to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. See discussion on final D&O, including the refund to customers in September and October 2013 required as a result of the final D&O, in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”
HECO 2011 test year rate case. In the HECO 2011 test year rate case, the PUC had granted HECO’s request to defer CIS project operation and maintenance (O&M) expenses (limited to $2,258,000 per year in 2011 and 2012) that were to be subject to a regulatory audit of project costs, and allowed HECO to accrue AFUDC on these deferred costs until the completion of the regulatory audit.
On January 28, 2013, HECO, HELCO, MECO and the Consumer Advocate entered into the 2013 Agreement to, among other things, write-off $40 million of CIS Project costs in lieu of conducting the regulatory audits of the
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CIP CT-1 and the CIS projects, with the remaining recoverable costs for the projects of $52 million to be included in rate base as of December 31, 2012. The parties agreed that HELCO would withdraw its 2013 test year rate case and not file a rate case until its next turn in the rate case cycle, for a 2016 test year, and HECO would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. The parties also agreed that, starting in 2014, HECO will be allowed to record RAM revenues starting on January 1 of 2014, 2015 and 2016. On March 19, 2013, the PUC issued its 2013 D&O approving the 2013 Agreement, with clarifications. See “Utility projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” for additional information on the 2013 Agreement and the 2013 D&O and their effects.
MECO 2012 test year rate case. See “MECO 2012 test year rate case” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” for information on the PUC’s final D&O.
Integrated Resource Planning. In June 2013, HECO, HELCO and MECO filed their 2013 integrated resource planning (IRP) report and five-year action plans detailing plans to meet future electricity needs for the islands of Oahu, Maui, Molokai, Lanai and Hawaii. IRP aims to develop long-range 20-year resource plans for meeting energy needs under various scenarios and then to develop near-term actions for implementation over the next five years. The 2013 IRP process was the first IRP to employ scenario planning, as well as an independent entity that facilitated and provided oversight of the process, since the PUC revised the IRP Framework in March 2012. The IRP process included input from a community advisory group established by the PUC of almost 70 business, community, and government, environmental and other leaders. The utilities also held two rounds of public meetings on the islands of Oahu, Maui, Molokai, Lanai and Hawaii to seek comments from the general public, in addition to 17 meetings with the advisory group.
The overarching goals of the action plans filed are lowering costs to customers, replacing expensive oil with cleaner sources of energy, modernizing the electric grid, and looking out for the interests of all customers. Significant action plan items include:
· Lowering costs to customers by accelerating the development of low-cost, fast-track, utility-scale renewable energy projects, including solar and wind facilities.
· Deactivating (i.e., removing from service with the possibility of reactivating in the future in a major emergency for example) older, less efficient oil-fired power plant units, to help lower costs and increase the use of renewable energy generation. This includes Honolulu Power Plant and two of four generating units at Maui’s Kahului Power Plant by 2014, as well as two generators at Oahu’s Waiau Power Plant by 2016. In addition, all units at Kahului Power Plant would be fully retired by 2019. Hawaii Island’s Shipman Plant is already deactivated and will be retired in 2014.
· Converting or replacing power plants that are not deactivated to use cost-effective, cleaner fuels, including renewable biomass or biofuel and liquefied natural gas.
· Supporting the state’s efforts to procure cheaper, cleaner, liquefied natural gas to replace the use of oil in making electricity.
· Increasing the capability of utility grids to accept additional customer-sited renewable generation, especially roof-top photovoltaic systems, while protecting safety, reliability and fairness of electric service for all customers.
· Developing “smart” grids for all three companies to improve customer service, integrate more renewable energy, and enable customers to better control their electric bills. Major components of the smart grid include installing smart meters for all customers (with opt-out provisions) in the 2017-2018 timeframe, automating the grid, and developing utility energy storage systems.
In July 2013, the Independent Entity, the person selected by the PUC to provide unbiased oversight of the IRP, filed a report to the PUC documenting his evaluation of the IRP process. The evaluation recognizes that the IRP report and action plans are compliant with many IRP Framework requirements and provides substantial analysis addressing the Principal Issues, which were issues and questions identified by the PUC to be addressed in the IRP process. However, the Independent Entity did not certify that the IRP process was conducted consistent with all provisions of the IRP Framework or that it fully addressed the Principal Issues. Under the IRP Framework, the PUC should issue a decision (with approval, partial approval, rejection, modifications and/or other directives) on the action plans within six months after the utilities’ IRP filing, unless the PUC determines that an evidentiary hearing is warranted.
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Renewable energy strategy. The utilities’ policy is to support efforts to increase renewable energy in Hawaii. The utilities believe their actions will help stabilize customer bills as they become less dependent on costly and price-volatile fossil fuel. The utilities’ renewable energy strategy will also allow them to meet Hawaii’s RPS law, which requires electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. HECO met the 10% RPS for 2010 with a consolidated RPS of 20.7%, including savings from energy efficiency programs and solar water heating (or 9.5% without DSM energy savings). Energy savings resulting from DSM energy efficiency programs and solar water heating will not count toward the RPS after 2014. For 2012, HECO achieved an RPS without DSM energy savings of 13.9%, primarily through a comprehensive portfolio of renewable energy power purchase agreements, net energy metering programs and biofuels. The utilities believe they are on track to meet the 2015 RPS.
Recent developments in the utilities’ renewable energy strategy include the following (also see the projects discussed under “Renewable Energy Projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements”):
· In February 2011, the PUC opened dockets related to HECO’s and MECO’s plans to proceed with competitive bidding processes to acquire up to approximately 300 MW and 50 MW, respectively, of new, renewable firm dispatchable capacity generation resources. In July 2013, the PUC closed the HECO and MECO RFPs, stating that the RFPs and related proceedings appear to be premature. The PUC will consider future requests by HECO or MECO to open another proceeding to conduct an RFP for generation upon demonstration of need and a plan focused on customer needs.
· In July 2011, the PUC directed HECO to submit a draft RFP for the PUC’s consideration for a competitive bidding process for 200 MW or more of renewable energy to be delivered to, or to be sited on, the island of Oahu. In October 2011, HECO filed a draft RFP with the PUC. In July 2013, the PUC issued orders related to the 200 MW RFP (see Note 5 of HECO’s “Notes to Consolidated Financial Statements” for additional information).
· In August 2011, HECO signed a 20-year contract, subject to PUC approval, with Hawaii BioEnergy to supply 10 million gallons per year of biocrude at Kahe Power Plant to begin within five years of PUC approval. In 2011, HECO also signed other contracts, subject to PUC approval, for lesser amounts of biocrude and for biodiesel for testing or operations.
· In September 2011, the PUC denied the utilities’ requested approval of HELCO’s contract with Aina Koa Pono-Ka’u LLC (AKP) citing the higher cost of the biofuel over the cost of petroleum diesel. In August 2012, HELCO signed a new 20-year contract with AKP, subject to PUC approval, to supply 16 million gallons of biodiesel per year with initial consumption expected to begin in 2017 or later. HELCO filed an application for approval of this contract in August 2012.
· In May 2012, the PUC approved HECO’s 3-year biodiesel supply contract with Renewable Energy Group for continued biodiesel supply to CT-1 of 3 million to 7 million gallons per year.
· In May 2012, MECO began purchasing wind energy from the 21 MW Kaheawa Wind Power II, LLC facility, which went into commercial operation in July 2012.
· In May 2012, HECO signed a contract, which was approved by the PUC, with the City and County of Honolulu to purchase an additional 27 MW of capacity and energy from an expanded waste-to-energy HPower facility, which was placed in service in April 2013.
· In May 2012, HELCO signed a power purchase agreement, subject to PUC approval, with Hu Honua Bioenergy for 21.5 MW of renewable, dispatchable firm capacity fueled by locally grown biomass from a facility on the island of Hawaii.
· 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. In February 2013, HELCO issued the Final Geothermal RFP. Six bids were received in April 2013 and are being evaluated.
· In August 2012, the battery facility at a 30 MW Kahuku wind farm experienced a fire and HECO has not purchased wind energy from the wind farm since then.
· In August 2012, the PUC approved a waiver from the competitive bidding process to allow HECO to negotiate with the U.S. Army for construction of a 50 MW utility-owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks on the island of Oahu and expected to be placed in service in 2017.
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· In September 2012, HECO began purchasing test wind energy from the 69 MW Kawailoa Wind, LLC facility. The wind farm was placed into full commercial operation in November 2012.
· In December 2012, the PUC approved a 3-year biodiesel supply contract with Pacific Biodiesel to supply 250,000 to 1 million gallons of biodiesel at the Honolulu International Airport Emergency Power Facility beginning in 2013.
· In December 2012, the 21 MW Auwahi Wind Energy LLC facility was placed into commercial operation, selling power to MECO under a 20-year contract.
· In December 2012, the 5 MW Kalaeloa Solar Two, LLC photovoltaic facility was placed into commercial operation, selling power to HECO under a 20-year contract.
· HECO, HELCO and MECO began accepting energy from feed-in tariff projects in 2011. As of June 30, 2013, there were 9 MW, 1 MW and 2 MW of installed feed-in tariff capacity from renewable energy technologies at HECO, HELCO and MECO, respectively.
· As of June 30, 2013, there were approximately 127 MW, 26 MW and 30 MW of installed net energy metering capacity from renewable energy technologies (mainly photovoltaic) at HECO, HELCO and MECO, respectively. Net energy metering continues to proceed at a record pace. The amount of net energy metering capacity installed in the first half of 2013 was more than twice the amount installed during the first half of 2012.
· In February 2013, HECO issued an “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding.” The invitation for waiver projects seeks to lower the cost of electricity for customers in the near term with qualified renewable energy projects on Oahu that can be quickly placed into service at a low cost per KWH. Proposals were received and, in June 2013, HECO filed a waiver request from the PUC Competitive Bidding Framework for five projects that meet these goals.
Commitments and contingencies. See Note 5 of HECO’s “Notes to Consolidated Financial Statements.”
Recent accounting pronouncements. See Note 8, “Recent accounting pronouncements,” of HECO’s “Notes to Consolidated Financial Statements.”
Liquidity and capital resources. Management believes that HECO’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper and lines of credit, is adequate to maintain sufficient liquidity to fund their respective capital expenditures and investments and to cover debt, retirement benefits and other cash requirements in the foreseeable future.
HECO’s consolidated capital structure was as follows:
Short-term borrowings
1,148
Preferred stock
1,485
1,472
2,721
2,654
Information about HECO’s short-term borrowings (other than from HELCO and MECO) and line of credit facility were as follows:
Borrowings from HEI
Undrawn capacity under line of credit facility (expiring December 5, 2016)
175
(1) The maximum amount of HECO’s external short-term borrowings during the first six months of 2013 was $71.0 million. At June 30, 2013, HECO had $9.6 million of short-term borrowings from HELCO, and MECO had $18 million of short-term borrowings from HECO. At July 31, 2013, HECO had $37 million of outstanding commercial paper, no draws under its line of credit facility, no borrowings from HEI and $10 million of short-term borrowings from HELCO. Also, at July 31, 2013, MECO had $22 million of short-term borrowings from HECO. Intercompany borrowings are eliminated in consolidation.
HECO has a line of credit facility of $175 million (see Note 9 of HECO’s “Notes to Consolidated Financial Statements”). There are customary conditions that must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 42% for HELCO and 44% for MECO as of June 30, 2013, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its credit agreement, or meet other requirements may result in an event of default. For example, under the credit agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 55% as of June 30, 2013, as calculated under the credit agreement), or if HECO is no longer owned by HEI.
Revenue bonds have been issued by the Department of Budget and Finance of the State of Hawaii (DBF) to finance (and refinance) capital improvement projects of HECO and its subsidiaries, but the sources of their repayment are the unsecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the DBF, including HECO’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on Special Purpose Revenue Bonds currently outstanding and issued prior to 2009 are insured by one of the following bond insurers: Ambac Assurance Corporation; Financial Guaranty Insurance Company, which was placed in a rehabilitation proceeding in the State of New York in June 2012 (with a plan of rehabilitation approved on June 11, 2013); MBIA Insurance Corporation (which bonds have been reinsured by National Public Finance Guarantee Corp.); or Syncora Guarantee Inc. (which bonds have been reinsured by Syncora Capital Assurance Inc.). The Standard & Poor’s (S&P’s) and Moody’s Investor Service’s ratings of each of these insurers, which at the time the insured obligations were issued were higher than the ratings of the utilities, are currently either lower than the ratings of the utilities or have been withdrawn.
The PUC has approved the use of an expedited approval procedure for the approval of long-term debt financings or refinancings (including the issuance of taxable debt) by HECO, HELCO and MECO during the period 2013 through 2015, subject to certain conditions. New long-term debt authorizations of $150 million (HECO $100 million, HELCO $25 million and MECO $25 million) can be requested under the expedited approval procedure through 2015.
In January 2013, HECO, HELCO and MECO filed with the PUC a letter request for the expedited authorization to issue prior to January 1, 2014 up to $90 million, $56 million and $20 million, respectively, of unsecured obligations bearing taxable interest to refinance select series of outstanding revenue bonds. In February 2013, HECO and MECO filed with the PUC a letter request for the expedited authorization to issue prior to January 1, 2014 up to $50 million and $20 million, respectively, of unsecured obligations bearing taxable interest. The proceeds are expected to be used to fund capital expenditures, including repaying short-term indebtedness incurred to fund capital expenditures. By orders issued on June 28 and July 24, 2013, the PUC approved both requests.
Operating activities provided $112 million in net cash during the first six months of 2013. Investing activities for the same period used net cash of $132 million for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $12 million, primarily due to the increase in short-term borrowings, partly offset by payment of $42 million of common and preferred dividends.
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Primary reason(s) for significant change
The impact of higher average earning asset balances was more than offset by lower yields on earning assets. ASB’s average loan portfolio balance for the second quarter of 2013 was $180 million higher than for the second quarter of 2012 as the average home equity lines of credit, residential, commercial real estate and consumer loan balances increased by $89 million, $81 million, $25 million and $24 million, respectively. The growth in these loan portfolios was consistent with ASB’s portfolio mix target and loan growth strategy. The loan portfolio yields were impacted by the low interest rate environment as new loan production yields were lower than the average portfolio yield.
Higher gain on sale of securities as ASB sold $70 million of agency obligations during the second quarter of 2013.
Lower funding costs as a result of the low interest rate environment. Average deposit balances for the second quarter of 2013 increased by $184 million compared to the second quarter of 2012 due to an increase in core deposits of $252 million, partly offset by a decrease in term certificates of $68 million. The other borrowings average balance decreased by $30 million due to lower retail repurchase agreements.
The credit for loan losses in the second quarter of 2013 was due to the $1 million release of reserves as a result of an agreement to sell ASB’s credit card portfolio. No additional provision expense was incurred as increases in the provision for loan losses to cover loan growth and charge-offs were offset by the release of commercial real estate loan portfolio reserves due to paydowns, recoveries of previously charged off consumer loans and the ongoing improvement in the quality of ASB’s loan portfolio.
Higher compensation and benefits expenses due to targeted staffing increases to support increased business volumes, information technology (IT) and risk management capabilities.
Higher noninterest income and lower provision for loan losses, partially offset by lower net interest income and higher noninterest expenses.
Higher operating income.
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The impact of higher average earning asset balances was more than offset by lower yields on earning assets. ASB’s average loan portfolio balance for the six months ended June 30, 2013 was $144 million higher than for the same period in 2012 as the average home equity lines of credit, commercial real estate, residential and consumer loan balances increased by $89 million, $30 million, $27 million and $26 million, respectively. The growth in these loan portfolios was consistent with ASB’s portfolio mix target and loan growth strategy. Loan portfolio yields were impacted by the low interest rate environment as new loan production yields were lower than the average portfolio yields. The average investment and mortgage-related securities portfolio balance increased by $23 million as ASB used its excess liquidity to purchase securities.
Higher gain on sale of securities due to the sale of $70 million of agency obligations and higher mortgage banking income due to higher gain on sale of loans.
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Lower funding costs as a result of the low interest rate environment. Average deposit balances for the six months ended June 30, 2013 increased by $161 million compared to the same period in 2012 due to an increase in core deposits of $230 million, partly offset by a decrease in term certificates of $70 million. The other borrowings average balance decreased by $35 million due to lower retail repurchase agreements.
The 2013 provision for loan losses declined due in part to the improved credit quality associated with the continuing improvement in Hawaii’s economy, lower net charge-offs in the higher risk land loan portfolios and purchased mortgage portfolio and $1.0 million release of the allowance on credit card loans due to the upcoming portfolio sale.
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Higher compensation and benefits expenses due to targeted staffing increases to support increased business volumes, IT and risk management capabilities.
Lower provision for loan losses and higher noninterest income, partially offset by lower net interest income and higher noninterest expenses.
Details of ASB’s other noninterest income and other noninterest expense were as follows:
993
1,952
1,972
746
456
1,371
1,449
2,809
FDIC insurance premium
854
1,707
Marketing
824
554
1,362
1,104
Office supplies, printing and postage
1,026
919
1,899
1,909
Communication
430
895
866
Reversal of interest expense—tax
(552
5,378
10,251
9,779
Total other expense
See Note 4 of HEI’s “Notes to Consolidated Financial Statements” and “Economic conditions” in the “HEI Consolidated” section above.
Despite the revenue pressures across the banking industry, management expects ASB’s low-cost funding base and lower-risk profile to continue to deliver strong performance compared to industry peers.
ASB’s return on average assets, net interest margin and efficiency ratio were as follows:
(percent)
Return on average assets
1.25
1.15
1.19
1.22
Net interest margin
3.79
3.97
4.01
Efficiency ratio
Average balance sheet and net interest margin. The following tables set forth average balances, together with interest earned and accrued, and resulting yields and costs:
Three months ended June 30 (dollars in thousands)
Interest
Yield/ rate (%)
Assets:
Other investments (1)
164,374
0.11
201,812
Securities purchased under resale agreements
26,154
0.38
617,942
3,386
2.19
624,581
3,435
2.20
Loans (2)
1,964,140
23,503
4.79
1,882,701
24,802
5.27
429,409
4,973
4.64
404,542
4,649
4.60
665,879
4,840
2.92
576,655
3,914
2.73
22,607
335
5.93
37,453
6.39
699,023
7,347
4.21
723,995
7,916
4.40
123,601
2,626
8.52
99,261
2,594
10.51
Total loans (2), (3)
3,904,659
4.47
3,724,607
Total interest-earning assets (4)
4,713,129
47,079
4.00
4,551,000
47,974
4.22
(43,372
(39,295
Non-interest-earning assets
429,924
429,258
5,099,681
4,940,963
Liabilities and shareholder’s equity:
Savings
1,811,157
0.06
1,725,034
304
0.07
Interest-bearing checking
659,790
0.02
613,370
Money market
176,812
187,455
0.16
Time certificates
462,762
952
0.83
530,896
0.97
Total interest-bearing deposits
3,110,521
0.17
3,056,755
0.22
Advances from Federal Home Loan Bank
51,264
542
4.18
541
4.28
Securities sold under agreements to repurchase
144,496
636
1.74
175,745
673
1.52
Total interest-bearing liabilities
3,306,281
0.30
3,282,500
0.35
Non-interest bearing liabilities:
Deposits
1,182,244
1,052,275
104,372
106,125
4,592,897
4,440,900
Shareholder’s equity
506,784
500,063
44,605
45,064
Net interest margin (%) (5)
71
Six months ended June 30 (dollars in thousands)
181,195
0.12
226,714
162
0.14
13,149
633,232
7,005
2.21
609,826
7,315
2.40
1,923,389
46,859
4.87
1,896,188
50,412
5.32
425,473
9,606
4.53
395,229
9,235
4.68
653,086
9,302
2.87
563,723
2.74
23,801
591
4.97
39,661
1,153
5.81
705,330
14,816
4.23
718,297
15,875
4.44
123,624
5,053
8.23
97,240
5,002
10.34
3,854,703
4.49
3,710,338
4.83
4,682,279
93,365
4,546,878
96,838
4.27
(42,992
(38,741
432,009
430,929
5,071,296
4,939,066
1,793,415
517
1,711,941
614
650,044
609,448
186,136
218,571
466,261
1,923
536,113
2,607
0.98
3,095,856
3,076,073
0.23
50,635
1,082
145,888
1,265
1.73
181,535
1,393
3,292,379
3,307,608
0.36
1,166,993
1,026,187
107,594
108,519
4,566,966
4,442,314
504,330
496,752
88,415
90,888
(1) Includes federal funds sold, interest bearing deposits and stock in the FHLB of Seattle.
(2) Includes loans held for sale.
(3) Includes loan fees of $1.4 million and $1.3 million for the three months ended June 30, 2013 and 2012, respectively, and $2.9 million and $2.5 million for the six months ended June 30, 2013 and 2012, together with interest accrued prior to suspension of interest accrual on nonaccrual loans, includes nonaccrual loans.
(4) Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.2 million for the three months ended June 30, 2013 and 2012, and $0.4 million for the six months ended June 30, 2013 and 2012.
(5) Defined as net interest income as a percentage of average earning assets.
Earning assets, costing liabilities and other factors. Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. The interest rate environment has been impacted by disruptions in the financial markets and these conditions have continued to have a negative impact on ASB’s net interest margin.
Loan originations and mortgage-related securities are ASB’s primary sources of earning assets.
Loan portfolio. ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. The composition of ASB’s loan portfolio was as follows:
% of total
50.5
49.2
9.7
9.9
17.0
16.6
0.5
0.7
0.2
Total real estate loans, net
3,139,111
79.2
2,948,276
77.8
18.2
19.0
2.6
100.0
Less: Deferred fees and discounts
(9,755
(11,638
Total loans, net
The increase in the total loan portfolio during the first six months of 2013 compared to the same period in 2012 was primarily due to an increase in originated ASB’s residential 1-4 family, home equity lines of credit and commercial real estate loan portfolios and is in line with ASB’s portfolio mix target and loan growth strategy.
In May 2013, ASB entered into an agreement with First Bankcard, a division of First National Bank of Omaha, to sell ASB’s credit card portfolio to First Bankcard. As part of the agreement, through First Bankcard, ASB will be able to offer ASB customers a greater variety of business and consumer credit card products, an enhanced rewards program, and regular marketing support. First Bankcard supports more than 500 partners with 5,700 retail branches, owning over 4 million credit card accounts. ASB transferred the $25 million credit card portfolio to held for sale and carried it at lower of cost or market. On August 1, 2013, ASB completed the sale of its credit card portfolio to First Bankcard.
Home equity — key credit statistics.
Outstanding balance (in thousands)
Percent of portfolio in first lien position
35.0
29.9
Net charge-off ratio
Delinquency ratio
End of draw period – interest only
Interest only
2013-2014
2015-2017
Thereafter
amortizing
524,775
132
12,153
512,490
148,952
The home equity line of credit (HELOC) portfolio makes up 17% of the total loan portfolio and is generally an interest-only revolving loan for a 10-year period, after which time the HELOC outstanding balance converts to a fully amortizing variable rate term loan with a 20-year amortization period. This product type comprises 89% of the total HELOC portfolio and is the current product offering. Within this product type, borrowers also have a “Fixed Rate Loan Option” to convert a part of their available line of credit into a 5, 7 or 10-year fully amortizing fixed rate loan with level
principal and interest payments. As of June 30, 2013, approximately 11% of the portfolio balances are amortizing loans under the Fixed Rate Loan Option. Nearly all originations prior to 2008 consisted of amortizing equity lines that have structured principal payments during the draw period. These older vintage equity lines represent 11% of the portfolio and are included in the amortizing balances identified in the table above.
Loan portfolio risk elements. See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”
Investment and mortgage-related securities. ASB’s investment portfolio was comprised as follows:
Mortgage-related securities — FNMA, FHLMC and GNMA
Principal and interest on mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) are guaranteed by the issuer and, in the case of GNMA, backed by the full faith and credit of the U.S. The decrease in federal agency obligations was due to the sale of $70 million of agency obligations in the second quarter of 2013. The decrease in mortgage-related securities was due to paydowns in the portfolio.
Deposits and other borrowings. Deposits continue to be the largest source of funds for ASB and are affected by market interest rates, competition and management’s responses to these factors. Deposit retention and growth will remain challenging in the current environment due to competition for deposits and the low level of short-term interest rates. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be additional sources of funds. Advances from the FHLB of Seattle have remained at $50 million from December 31, 2012 to June 30, 2013. As of June 30, 2013 and December 31, 2012, ASB’s costing liabilities consisted of 96% deposits and 4% other borrowings. The weighted average cost of deposits for the first six months of 2013 was 0.12%, compared to 0.17% for the first six months of 2012.
Other factors. Interest rate risk is a significant risk of ASB’s operations and also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing interest rates generally translate into decreases and increases in the fair value of those instruments, respectively. In addition, changes in credit spreads also impact the fair values of those instruments.
As of June 30, 2013 and December 31, 2012, ASB had unrealized gains, net of taxes, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI of $1 million and $11 million, respectively. The decrease in AOCI was due to the impact of rising interest rates on the fair value of ASB’s investment and mortgage-related securities. See “Item 3. Quantitative and qualitative disclosures about market risk.”
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During the first six months of 2013, ASB recorded a provision for loan losses of $0.9 million primarily due to net charge-offs during the year for consumer, commercial and HELOC loans, and growth in the loan portfolio, partly offset by the release of reserves for the credit card and commercial real estate loan portfolios. During the first six months of 2012, ASB recorded a provision for loan losses of $5.9 million primarily due to charge-offs during the year for 1-4 family, residential land, commercial and consumer loans. Continued financial stress on ASB’s customers may result in higher levels of delinquencies and losses.
Year ended December 31
Allowance for loan losses, January 1
Less: net charge-offs
1,880
4,367
8,804
Allowance for loan losses, end of period
39,463
Ratio of allowance for loan losses, end of period, to end of period loans outstanding
1.04
1.06
1.11
Ratio of net charge-offs during the period to average loans outstanding (annualized)
0.24
Legislation and regulation. ASB is subject to extensive regulation, principally by the Office of the Comptroller of the Currency (OCC) and the Federal Deposit Insurance Corporation (FDIC). Depending on ASB’s level of regulatory capital and other considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholder. See the discussion below under “Liquidity and capital resources.”
Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). Regulation of the financial services industry, including regulation of HEI, ASHI and ASB, has changed and will continue to change as a result of the enactment of the Dodd-Frank Act, which became law in July 2010. Importantly for HEI, ASHI and ASB, under the Dodd-Frank Act, on July 21, 2011, all of the functions of the Office of Thrift Supervision transferred to the OCC, the FDIC, the Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI and ASHI, as thrift holding companies, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not generally change, the applicable laws and regulations are being interpreted, and new and amended regulations may be adopted, by the FRB, OCC and the Bureau. In addition, HEI will continue to be required to serve as a source of strength to ASB in the event of its financial distress. The Dodd-Frank Act also imposes new restrictions on the ability of a savings bank to pay dividends should it fail to remain a qualified thrift lender.
More stringent affiliate transaction rules now apply to ASB in the securities lending, repurchase agreement and derivatives areas. Standards were raised with respect to the ability of ASB to merge with or acquire another institution. In reviewing a potential merger or acquisition, the approving federal agency will need to consider the extent to which the proposed transaction will result in “greater or more concentrated risks to the stability of the U.S. banking or financial system.”
The Dodd-Frank Act established the Bureau. It has authority to prohibit practices it finds to be unfair, deceptive or abusive, and it may also issue rules requiring specified disclosures and the use of new model forms. On January 10, 2013, the Bureau issued the Ability-to-Repay rule which closed for comment on February 25, 2013. For mortgages, under the proposed Ability-to-Repay rule, among other things, (i) potential borrowers will have to supply financial information, and lenders must verify it, (ii) to qualify for a particular loan, a consumer will have to have sufficient assets or income to pay back the loan, and (iii) lenders will have to determine the consumer’s ability to repay both the principal and the interest over the long term - not just during an introductory period when the rate may be lower.
On May 22, 2012, the Bureau issued the Final Remittance Rule (an amendment to Regulation E). For international wires, the rule now provides flexibility regarding the disclosure of foreign taxes, as well as fees imposed by a designated recipient’s institution for receiving a remittance transfer in an account. Second, the rule limits a remittance transfer provider’s obligation to disclose foreign taxes to those imposed by a country’s central government. And third, the rule revises the error resolution provisions that apply when a remittance transfer is not
delivered to a designated recipient because the sender provided incorrect or insufficient information, and, in particular, when a sender provides an incorrect account number and that incorrect account number results in the funds being deposited in the wrong account.
ASB may also be subject to new state regulation because of a provision in the Dodd-Frank Act that acknowledges that a federal savings bank may be subject to state regulation and allows federal law to preempt a state consumer financial law on a “case by case” basis only when (1) the state law would have a discriminatory effect on the bank compared to that on a bank chartered in that state; (2) the state law prevents or significantly interferes with a bank’s exercise of its power; or (3) the state law is preempted by another federal law.
The Dodd-Frank Act also adopts a number of provisions that will impact the mortgage industry, including the imposition of new specific duties on the part of mortgage originators (such as ASB) to act in the best interests of consumers and to take steps to ensure that consumers will have the capability to repay loans they may obtain, as well as provisions imposing new disclosure requirements and requiring appraisal reforms.
The “Durbin Amendment” to the Dodd-Frank Act required the FRB to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the processing costs incurred. In June 2011, the FRB issued a final rule establishing standards for debit card interchange fees and prohibiting network exclusivity arrangements and routing restrictions. Under the final rule, effective October 1, 2011, the maximum permissible interchange fee that an issuer may receive for an electronic debit transaction is 21-24 cents, depending on certain components. Financial institutions and their affiliates that have less than $10 billion in assets are exempt from this Amendment; however, as of July 1, 2013, ASB is not exempt. For the second quarter of 2013, ASB had earned an average of 49 cents per electronic debit transaction. ASB estimates debit card interchange fees to be lower by approximately $3 million after tax for the remainder of 2013 and approximately $6 million after tax if it continues to be non-exempt in 2014.
Many of the provisions of the Dodd-Frank Act, as amended, will not become effective until implementing regulations are issued and effective.
Final Capital Rule. On July 2, 2013, the FRB finalized its rule implementing the Basel III regulatory capital framework. The final rule would apply to banking organizations of all sizes and types regulated by the FRB and the OCC, except bank holding companies subject to the FRB’s Small Bank Holding Company Policy Statement and Savings & Loan Holding Companies (SLHCs) substantially engaged in insurance underwriting or commercial activities. HEI currently meets the requirements of the exemption as a top-tier grandfathered unitary SLHC that derived, as of June 30 of the previous calendar year, either 50% or more of its total consolidated assets or 50% or more of its total revenues on an enterprise-wide basis (calculated under GAAP) from activities that are not financial in nature pursuant to Section 4(k) of the Bank Holding Company Act. The FRB is temporarily excluding these SLHCs from the final rule while it considers a proposal relating to capital and other requirements for SLHC intermediate holding companies. The FRB anticipates that it will release a proposal on intermediate holding companies in the near term that would specify the criteria for establishing and transferring activities to intermediate holding companies and propose to apply the FRB’s capital requirements to such intermediate holding companies.
Pursuant to the final rule and consistent with the proposals, all banking organizations, including covered holding companies, would be subject to the following minimum regulatory capital requirements: a common equity tier 1 capital ratio of 4.5%, a tier 1 capital ratio of 6%, a total capital ratio of 8% of risk-weighted assets and a leverage ratio of 4%. In order to avoid restrictions on capital distributions and discretionary bonus payments to executive officers, the final rule requires a banking organization to hold a buffer of common equity tier 1 capital above its minimum risk-based capital requirements in an amount greater than 2.5% of total risk-weighted assets (capital conservation buffer). In addition, a countercyclical capital buffer would expand the capital conservation buffer by up to 2.5% of a banking organization’s total risk-weighted assets for advanced approaches banking organizations. The final rule would establish qualification criteria for common equity, additional tier 1 and tier 2 capital instruments that help to ensure their ability to absorb losses. All banking organizations would be required to calculate risk-weighted assets under the standardized approach, which harmonizes the banking agencies’ calculation of risk-weighted assets and address shortcomings in risk-based capital requirements identified by the agencies.
Minimum Capital Requirements
Effective dates
1/1/15
1/1/16
1/1/17
1/1/18
1/1/19
Capital conservation buffer
0.625
1.875
2.50
Common equity ratio + conservation buffer
4.50
5.125
5.75
6.375
7.00
Tier 1 capital ratio + conservation buffer
6.00
6.625
7.25
7.875
8.50
Total capital ratio + conservation buffer
8.00
8.625
9.25
9.875
Tier 1 leverage ratio
Countercyclical capital buffer — not applicable to ASB
The final rule is effective January 1, 2015 for ASB. Subject to the timing and final outcome of the FRB’s SLHC intermediate holding company proposal, HEI anticipates that the capital requirements in the final rule will be effective for HEI or ASHI on January 1, 2015 as well. HEI and ASB have reviewed the final rule and the impact to capital ratios. If the final rules were currently applicable to HEI and ASB, management believes HEI and ASB would satisfy the new capital requirements, including the fully phased-in capital conservation buffer.
Commitments and contingencies. See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”
Liquidity and capital resources.
% change
5,069
560
671
(17
3,913
3,737
4,276
4,230
196
As of June 30, 2013, ASB was one of Hawaii’s largest financial institutions based on assets of $5.1 billion and deposits of $4.3 billion.
As of June 30, 2013, ASB’s unused FHLB borrowing capacity was approximately $0.9 billion. As of June 30, 2013, ASB had commitments to borrowers for loan commitments and unused lines and letters of credit of $1.6 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.
For the first six months of 2013, net cash provided by ASB’s operating activities was $48 million. Net cash used during the same period by ASB’s investing activities was $108 million, primarily due to purchases of investment and mortgage-related securities of $40 million, a net increase in loans receivable of $201 million and additions to premises and equipment of $8 million, partly offset by proceeds from the sale of investment securities of $71 million, repayments of investment and mortgage-related securities of $63 million, proceeds from the sale of real estate acquired in settlement of loans of $6 million and redemption of stock from FHLB of Seattle of $2 million. Net cash provided in financing activities during this period was $19 million, primarily due to net increases in deposit liabilities of $46 million and a net increase in mortgage escrow deposits of $1 million, partly offset by a net decrease in retail repurchase agreements of $8 million and the payment of $20 million in common stock dividends to HEI (through ASHI).
FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of June 30, 2013, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 9.3% (5.0%), a Tier-1 risk-based capital ratio of 11.5% (6.0%) and a total risk-based capital ratio of 12.5% (10.0%). FRB approval is required before ASB can pay a dividend or otherwise make a capital distribution to HEI (through ASHI).
77
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s results of operations, financial condition and liquidity. For additional quantitative and qualitative information about the Company’s market risks, see pages 82 to 84, HEI’s Quantitative and Qualitative Disclosures About Market Risk, in Part II, Item 7A of HEI’s 2012 Form 10-K and HECO’s Quantitative and Qualitative Disclosures About Market Risk, which is incorporated into Part II, Item 7A of HECO’s 2012 Form 10-K by reference to Exhibit 99.2.
ASB’s interest-rate risk sensitivity measures as of June 30, 2013 and December 31, 2012 constitute “forward-looking statements” and were as follows:
Change in NII (gradual change in interest rates)
Change in EVE (instantaneous change in interest rates)
Change in interest rates (basis points)
+300
1.6
(9.8
)%
(9.4
+200
(6.0
(4.9
+100
0.1
(2.7
(1.9
-100
(0.2
(1.7
Management believes that ASB’s interest rate risk position as of June 30, 2013 represents a reasonable level of risk. Net interest income (NII) sensitivity as of June 30, 2013 was slightly more asset sensitive for larger increases in rates compared to December 31, 2012 due to changes in assumptions about the rate sensitivity of certain non-maturity or core deposits.
ASB’s base economic value of equity (EVE) increased to $868 million as of June 30, 2013 compared to $767 million as of December 31, 2012 due to the decrease in the discount of core deposits resulting from the rise in interest rates.
The change in EVE was more sensitive to rising rate scenarios as of June 30, 2013 compared to December 31, 2012 due to the increase and steepening of the yield curve and changes in the asset mix as the residential portfolio grew and short duration securities were sold.
The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity and the percentage change in EVE is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results. To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.
Item 4. Controls and Procedures
HEI:
Changes in Internal Control over Financial Reporting
During the second quarter of 2013, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of June 30, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Constance H. Lau, HEI Chief Executive Officer, and James A. Ajello, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of June 30, 2013. Based on their evaluations, as of June 30, 2013, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:
(1) is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and
(2) is accumulated and communicated to HEI management, including HEI’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
HECO:
During the second quarter of 2013, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of June 30, 2013 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.
Richard M. Rosenblum, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of June 30, 2013. Based on their evaluations, as of June 30, 2013, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HECO in reports HECO files or submits under the Securities Exchange Act of 1934:
(2) is accumulated and communicated to HECO management, including HECO’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in HEI’s Form 10-K (see “Part I. Item 3. Legal Proceedings” and proceedings referred to therein) and this 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Note 4 of HEI’s “Notes to Consolidated Financial Statements” and HECO’s “Notes to Consolidated Financial Statements”) are incorporated by reference in this Item 1. With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved. Certain HEI subsidiaries (including HECO and its subsidiaries and ASB) may also be involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.
Item 1A. Risk Factors
For information about Risk Factors, see pages 70 to 79 of HEI’s Form 10-Q for the quarter ended March 31, 2013, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements herein. Also, see “Forward-Looking Statements” on pages v and vi of HEI’s 2012 Form 10-K, as updated on pages iv and v herein.
Item 5. Other Information
A. Ratio of earnings to fixed charges.
Years ended December 31
2011
2010
2009
2008
HEI and Subsidiaries
Excluding interest on ASB deposits
3.50
3.59
3.28
3.22
2.89
2.29
2.06
Including interest on ASB deposits
3.36
3.41
3.14
3.03
2.64
1.95
1.71
HECO and Subsidiaries
3.57
3.37
3.52
2.88
2.99
3.48
See HEI Exhibit 12.1 and HECO Exhibit 12.2.
B. James A. Ajello, HEI Executive Vice President and Chief Financial Officer, has been appointed HEI principal accounting officer effective August 2, 2013, in addition to his existing responsibilities. With respect to the principal accounting officer role, Mr. Ajello succeeds Jennifer B. Loo, HEI Manager, Financial Reporting and Accounting and Assistant Controller, who served as Interim principal accounting officer from March 8 to August 1, 2013, in addition to her ongoing duties. Mr. Ajello will not receive any additional compensation in connection with his appointment as principal accounting officer.
Item 6. Exhibits
HEI Exhibit 12.1
Computation of ratio of earnings to fixed charges, six months ended June 30, 2013 and 2012 and years ended December 31, 2012, 2011, 2010, 2009 and 2008
HEI Exhibit 31.1
Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer)
HEI Exhibit 31.2
Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer)
HEI Exhibit 32.1
HEI Certification Pursuant to 18 U.S.C. Section 1350
HEI Exhibit 101.INS
XBRL Instance Document
HEI Exhibit 101.SCH
XBRL Taxonomy Extension Schema Document
HEI Exhibit 101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
HEI Exhibit 101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
HEI Exhibit 101.LAB
XBRL Taxonomy Extension Label Linkbase Document
HEI Exhibit 101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
HECO Exhibit 12.2
HECO Exhibit 31.3
Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Richard M. Rosenblum (HECO Chief Executive Officer)
HECO Exhibit 31.4
Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer)
HECO Exhibit 32.2
HECO Certification Pursuant to 18 U.S.C. Section 1350
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The signature of the undersigned companies shall be deemed to relate only to matters having reference to such companies and any subsidiaries thereof.
(Registrant)
By
/s/ Constance H. Lau
/s/ Richard M. Rosenblum
Constance H. Lau
Richard M. Rosenblum
President and Chief Executive Officer
(Principal Executive Officer of HEI)
(Principal Executive Officer of HECO)
/s/ James A. Ajello
/s/ Tayne S. Y. Sekimura
James A. Ajello
Tayne S. Y. Sekimura
Executive Vice President and
Senior Vice President
Chief Financial Officer
and Chief Financial Officer
(Principal Financial and Accounting
(Principal Financial Officer of HECO)
Officer of HEI)
/s/ Cathlynn L. Yoshida
Cathlynn L. Yoshida
Controller
(Principal Accounting Officer of HECO)
Date: August 8, 2013