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Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2023
Summary of Significant Accounting Policies [Abstract]  
Basis of Presentation
Basis of Presentation
These consolidated financial statements are prepared and presented in accordance with United States
Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, include all
adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera.
 
 
All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated.
Principles of Consolidation
Principles of Consolidation
These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned
subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses
the equity method of accounting to record investments in which the Company has the ability to exercise
significant influence, and for VIEs in which Emera is not the primary beneficiary.
The Company performs ongoing analysis to assess whether it holds any VIEs or whether any
reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management
reviews contractual and ownership arrangements such as leases, long-term purchase power agreements,
tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company
is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the
power to direct the activities of the VIE that most significantly impacts its economic performance and the
obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to
the VIE. In circumstances where Emera has an investment in a VIE but is not deemed the primary
beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32.
Intercompany balances and transactions have been eliminated on consolidation, except for the net profit
on certain transactions between certain non-regulated and regulated entities in accordance with
accounting standards for rate-regulated entities. The net profit on these transactions, which would be
eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-
regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for
generation and purchased power, or OM&G, depending on the nature of the transaction.
Use of Management Estimates
Use of Management Estimates
The preparation of consolidated financial statements in accordance with USGAAP requires management
to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the
date of the financial statements and reported amounts of revenues and expenses during the reporting
periods. Significant areas requiring use of management estimates relate to rate-regulated assets and
liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled
revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments,
income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management
evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and
expected conditions and assumptions believed to be reasonable at the time the assumption is made, with
any adjustments recognized in income in the year they arise.
Regulatory Matters
Regulatory Matters
Regulatory accounting applies where rates are established by, or subject to approval by, an
 
independent
third-party regulator. Rates are designed to recover prudently incurred costs of providing regulated
products or services and provide an opportunity for a reasonable rate of return on invested capital, as
applicable. For further detail, refer to note 6.
Foreign Currency Translation
Foreign Currency Translation
 
Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of
exchange prevailing at the balance sheet date. The resulting differences between the translation at the
original transaction date and the balance sheet date are included in income.
Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are
translated using exchange rates in effect at the balance sheet date and the results of operations at the
average exchange rate in effect for the period. The resulting exchange gains and losses on the assets
and liabilities are deferred on the balance sheet in AOCI.
The Company designates certain USD denominated debt held in CAD functional currency companies as
hedges of net investments in USD denominated foreign operations. The change in the carrying amount of
these investments, measured at exchange rates in effect at the balance sheet date is recorded in Other
Comprehensive Income (“OCI”).
Revenue Recognition
Revenue Recognition
Regulated Electric and Gas Revenue:
Electric and gas revenues, including energy charges, demand charges, basic facilities charges and
clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is
when electricity and gas are delivered to customers over time as the customer simultaneously receives
and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include
billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates
approved by the respective regulators and recorded based on metered usage, which occurs on a
periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity
and gas delivered to customers, but not billed, is estimated and corresponding unbilled revenue is
recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated
by estimating the megawatt hours (“MWh”) or therms delivered to customers at the established rates
expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of
energy demand, weather, line losses and inter-period changes to customer classes.
Non-regulated Revenue:
Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of
natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues
are recorded when obligations under terms of the contract are satisfied and are presented on a net basis
reflecting the nature of contractual relationships with customers and suppliers.
Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is
when electricity is delivered to customers over time.
 
Other non-regulated revenues are recorded when obligations under the terms of the contract are
satisfied.
Other:
Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the
Company concurrent with revenue-producing activities are excluded from revenue.
Franchise Fees and Gross Receipts
Franchise Fees and Gross Receipts
TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices
approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills
for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas”
revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by
TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state
and municipal taxes”.
NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not
required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross
receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.
PP&E
PP&E
 
PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in
aid of construction.
The cost of additions, including betterments and replacements of units, are included in “PP&E” on the
Consolidated Balance Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost,
plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no
gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are
included in income as the dispositions occur.
The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for
regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital
project. Overhead includes corporate costs such as finance, information technology and labour costs,
along with other costs related to support functions, employee benefits, insurance, procurement, and fleet
operating and maintenance. Expenditures for project development are capitalized if they are expected to
have a future economic benefit.
Normal maintenance projects and major maintenance projects that do not increase overall life of the
related assets are expensed as incurred. When a major maintenance project increases the life or value of
the underlying asset, the cost is capitalized.
 
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of
the depreciable assets in each functional class of depreciable property. For some of Emera’s rate-
regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied
to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of
depreciable property. The service lives of regulated assets require regulatory approval.
Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of
computer software and land rights. Amortization is determined by the straight-line method, based on the
estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated
subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book
value to date over the remaining life of those assets. The service lives of regulated intangible assets
require regulatory approval.
Goodwill
Goodwill
Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of
identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial
cost less any write-down for impairment and is adjusted for the impact of foreign exchange (“FX”).
Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or
change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When
assessing goodwill for impairment, the Company has the option of first performing a qualitative
assessment to determine whether a quantitative assessment is necessary. In performing a qualitative
assessment management considers, among other factors, macroeconomic conditions, industry and
market considerations and overall financial performance.
If the Company performs a qualitative assessment and determines it is more likely than not that its FV is
less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a
quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying
amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss
is recorded. Management estimates the FV of the reporting unit by using the income approach, or a
combination of the income and market approach. The income approach uses a discounted cash flow
analysis which relies on management’s best estimate of the reporting unit’s projected cash flows. The
analysis includes an estimate of terminal values based on these expected cash flows using a
methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s
residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly
traded comparable companies and represents the weighted average cost of capital of comparable
companies. For the market approach, management estimates FV based on comparable companies and
transactions within the utility industry. Significant assumptions used in estimating the FV of a reporting
unit using an income approach include discount and growth rates, rate case assumptions including future
cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating and
capital cash flows. Adverse changes in these assumptions could result in a future material impairment of
the goodwill assigned to Emera’s reporting units.
 
As of December 31, 2023, $
5,868
 
million of Emera’s goodwill represents the excess of the acquisition
purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over the FV assigned to
identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative assessments were performed
for NMGC and PGS given the significant excess of FV over carrying amounts calculated during the last
quantitative tests in Q4 2022 and Q4 2019, respectively. Management concluded it was more likely than
not that the FV of these reporting units exceeded their respective carrying amounts, including goodwill. As
such, no quantitative testing was required. Given the length of time passed since the last quantitative
impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and
performed a quantitative impairment assessment in Q4 2023 using a combination of the income and
market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying
amount, including goodwill, and as a result, no impairment charges were recognized.
In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment
charge of $
73
 
million, reducing the GBPC goodwill balance to
nil
 
as at December 31, 2022. For further
details, refer to note 22.
Income Taxes and Investment Tax Credits
Income Taxes and Investment Tax
 
Credits
Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events
that have been included in financial statements or income tax returns. Deferred income tax assets and
liabilities are determined based on the difference between the carrying value of assets and liabilities on
the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the
year in which the differences are expected to reverse. The effect of a change in income tax rates on
deferred income tax assets and liabilities is recognized in earnings in the period when the change is
enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator.
Emera recognizes the effect of income tax positions only when it is more likely than not that they will be
realized. Management reviews all readily available current and historical information, including forward-
looking information, and the likelihood that deferred income tax assets will be recovered from future
taxable income is assessed and assumptions are made about the expected timing of reversal of deferred
income tax assets and liabilities. If management subsequently determines it is likely that some or all of a
deferred income tax asset will not be realized, a valuation allowance is recorded to reflect the amount of
deferred income tax asset expected to be realized.
 
Generally, investment tax credits are recorded as a reduction to income tax expense in the current or
future periods to the extent that realization of such benefit is more likely than not. Investment tax credits
earned on regulated assets by TEC, PGS and NMGC are deferred and amortized as required by
regulatory practices.
TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income
taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that
is currently payable, except for the deferred income taxes on certain regulatory balances specifically
prescribed by regulators. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick
Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be
recovered from or returned to customers in future years. These regulated assets or liabilities are grossed
up using the respective income tax rate to reflect the income tax associated with future revenues that are
required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced
revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income
taxes.
Emera classifies interest and penalties associated with unrecognized tax benefits as interest and
operating expense, respectively. For further detail, refer to note 10.
Derivatives and Hedging Activities
Derivatives and Hedging Activities
The Company manages its exposure to normal operating and market risks relating to commodity prices,
FX, interest rates and share prices through contractual protections with counterparties where practicable,
and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and
swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the
Company has contracts for the physical purchase and sale of natural gas. These physical and financial
contracts are classified as HFT. Collectively,
 
these contracts and financial instruments are considered
derivatives.
The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial
derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that
meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in
income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction
is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources
within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the
commodity, and the Company deems the counterparty creditworthy.
 
The Company continually assesses
contracts designated under the NPNS exception and will discontinue the treatment of these contracts
under this exemption if the criteria are no longer met.
 
Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be
proven to effectively hedge identified risk both at the inception and over the term of the instrument.
Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in
income in the same period the related hedged item is realized. Where documentation or effectiveness
requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net
income in the reporting period, unless deferred as a result of regulatory accounting.
Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for
which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The
change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized
in the hedged item when the hedged item is settled. Management believes any gains or losses resulting
from settlement of these derivatives related to fuel for generation and purchased power will be refunded
to or collected from customers in future rates. TEC has no derivatives related to hedging as a result of a
FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31,
2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement
agreement.
Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV
normally recorded in net income of the period. The Company has not elected to designate any derivatives
to be included in the HFT category where another accounting treatment would apply.
Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues,
fuel for generation and purchased power, other expenses, inventory, and OM&G, depending on the
nature of the item being economically hedged. Transportation capacity arising as a result of marketing
and trading derivative transactions is recognized as an asset in “Receivables and other current assets”
and amortized over the period of the transportation contract term. Cash flows from derivative activities are
presented in the same category as the item being hedged within operating or investing activities on the
Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on
the Consolidated Statements of Cash Flows.
Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash
collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables
and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”.
Lessee, Leases
Leases
The Company determines whether a contract contains a lease at inception by evaluating whether the
contract conveys the right to control the use of an identified asset for a period of time in exchange for
consideration.
 
Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to
purchase wind and hydro energy over varying contract lengths which are classified as finance leases.
These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments
associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease
expense associated with these leases is recorded as “Regulated fuel for generation and purchased
power” on the Consolidated Statements of Income.
Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets
based on the present value of the future minimum lease payments over the lease term at commencement
date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at
commencement of the lease is used in determining the present value of future lease payments. Lease
expense is recognized on a straight-line basis over the lease term and is recorded as “Operating,
maintenance and general” on the Consolidated Statements of Income.
Lessor, Leases
Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the
arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria
are met due to the presence of a third-party residual value guarantee, the lease is a direct financing
lease.
 
For direct finance leases, a net investment in the lease is recorded that consists of the sum of the
minimum lease payments and residual value, net of estimated executory costs and unearned income.
The difference between the gross investment and the cost of the leased item is recorded as unearned
income at the inception of the lease. Unearned income is recognized in income over the life of the lease
using a constant rate of interest equal to the internal rate of return on the lease.
 
For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the
difference between the FV and the carrying value of the leased item is recorded at lease commencement
rather than deferred over the term of the lease.
 
Emera has certain contractual agreements that include lease and non-lease components, which
management has elected to account for as a single lease component.
Cash, Cash Equivalents and Restricted Cash
Cash, Cash Equivalents and Restricted Cash
Cash equivalents consist of highly liquid short-term investments with original maturities of three months or
less at acquisition.
Receivables
Receivables and Allowance for Credit Losses
Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard
payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be
assessed on account balances after the due date. The Company recognizes allowances for credit losses
to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit
losses related to accounts receivable by considering historical loss experience, customer deposits,
current events, the characteristics of existing accounts and reasonable and supportable forecasts that
affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed
to maintain the allowance at a level considered adequate to cover expected losses. Receivables are
written off against the allowance when they are deemed uncollectible.
Allowance for Credit Losses
Receivables and Allowance for Credit Losses
Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard
payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be
assessed on account balances after the due date. The Company recognizes allowances for credit losses
to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit
losses related to accounts receivable by considering historical loss experience, customer deposits,
current events, the characteristics of existing accounts and reasonable and supportable forecasts that
affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed
to maintain the allowance at a level considered adequate to cover expected losses. Receivables are
written off against the allowance when they are deemed uncollectible.
Inventory
Inventory
Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value,
unless evidence indicates the weighted-average cost will be recovered in future customer rates.
Asset Impairment
Asset Impairment
Long-Lived Assets:
Emera assesses whether there has been an impairment of long-lived assets and intangibles when a
triggering event occurs, such as a significant market disruption or sale of a business.
 
The assessment involves comparing undiscounted expected future cash flows to the carrying value of the
asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the
amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-
lived asset over its estimated FV. The Company’s assumptions relating to future results of operations or
other recoverable amounts, are based on a combination of historical experience, fundamental economic
analysis, observable market activity and independent market studies. The Company’s expectations
regarding uses and holding periods of assets are based on internal long-term budgets and projections,
which consider external factors and market forces, as of the end of each reporting period. The
assumptions made are consistent with generally accepted industry approaches and assumptions used for
valuation and pricing activities.
As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets.
No
impairment charges related to long-lived assets were recognized in 2023 or 2022.
 
Equity Method Investments:
The carrying value of investments accounted for under the equity method are assessed for impairment by
comparing the FV of these investments to their carrying values, if a FV assessment was completed, or by
reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be
other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds
the investment’s FV.
No
 
impairment of equity method investments was required in either 2023 or 2022.
Financial Assets:
Equity investments, other than those accounted for under the equity method, are measured at FV, with
changes in FV recognized in the Consolidated Statements of Income. Equity investments that do not
have readily determinable FV are recorded at cost minus impairment, if any, plus or minus changes
resulting from observable price changes in orderly transactions for the identical or similar investments.
No
impairment of financial assets was required in either 2023 or 2022.
Asset Retirement Obligations and Cost of Removal
Asset Retirement Obligations
An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs
resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation
may exist under an existing or enacted law or statute, written or oral contract, or by legal construction
under the doctrine of promissory estoppel.
An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using
the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred.
Estimated future cash flows are based on completed depreciation studies, remediation reports, prior
experience, estimated useful lives, and governmental regulatory requirements. The present value of the
liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.
The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.
Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term
liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated
accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and
included in the next depreciation study.
Some of the Company’s transmission and distribution assets may have conditional AROs that are not
recognized in the consolidated financial statements, as the FV of these obligations could not be
reasonably estimated, given insufficient information to do so. A conditional ARO refers to a legal
obligation to perform an asset retirement activity in which the timing and/or method of settlement are
conditional on a future event that may or may not be within the control of the entity. Management
monitors these obligations and a liability is recognized at FV in the period in which an amount can be
determined.
Cost of Removal (“COR”)
TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR
represent funds received from customers through depreciation rates to cover estimated future non-legally
required COR of PP&E upon retirement. The companies accrue for COR over the life of the related
assets based on depreciation studies approved by their respective regulators. The costs are estimated
based on historical experience and future expectations, including expected timing and estimated future
cash outlays.
Stock-Based Compensation
Stock-Based Compensation
The Company has several stock-based compensation plans: a common share option plan for senior
management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a
performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for
its plans in accordance with the FV-based method of accounting for stock-based compensation. Stock-
based compensation cost is measured at the grant date, based on the calculated FV of the award, and is
recognized as an expense over the employee’s or director’s requisite service period using the graded
vesting method. Stock-based compensation plans recognized as liabilities are initially measured at FV
and re-measured at FV at each reporting date, with the change in liability recognized in income.
Employee Benefits
Employee Benefits
The costs of the Company’s pension and other post-retirement benefit programs for employees are
expensed over the periods during which employees render service. The Company recognizes the funded
status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes
changes in funded status in the year the change occurs. The Company recognizes unamortized gains
and losses and past service costs in “AOCI” or “Regulatory assets” on the Consolidated Balance Sheets.
The components of net periodic benefit cost other than the service cost component are included in “Other
income, net” on the Consolidated Statements of Income. For further detail, refer to note 21.