XML 46 R30.htm IDEA: XBRL DOCUMENT

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2024

Preparing the consolidated financial statements to conform with GAAP requires management to make estimates in measuring assets and liabilities and related revenues and expenses. These estimates involve judgments about various future economic factors that are difficult to predict and are beyond our control; therefore, actual results could differ from these estimates. As additional information becomes available, or actual amounts are determined, recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Property, Plant and Equipment

Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, allowance for funds used during construction ("AFUDC"), and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged to expense as incurred, and the costs of major renewals and improvements are capitalized. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. Upon retirement or disposition of property within the unregulated businesses, the gain or loss, net of salvage value, is charged to income. A summary of property, plant and equipment by classification as of December 31, 2024 and 2023 is provided in the following table:


	As of December 31,
(in millions)	2024		2023
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	1,679.3	$	1,486.8
Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida	819.5		788.2
Electric distribution	163.0		143.5
Unregulated Energy
Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida	201.6		194.9
Natural gas transmission and supply – Ohio	139.2		134.2
Electricity and steam generation	37.4		37.1
Mobile CNG and pipeline solutions	52.8		40.6
Sustainable energy investments, including renewable natural gas related investments	32.7		4.0
Other	29.9		30.3
Total property, plant and equipment	3,155.4		2,859.6
Less: Accumulated depreciation and amortization	(567.6)		(516.4)
Plus: Construction work in progress	148.1		113.2
Net property, plant and equipment	$	2,735.9	$	2,456.4

Contributions or Advances in Aid of Construction

Customer contributions or advances in aid of construction reduce property, plant and equipment, unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. Non-refundable contributions reduce property, plant and equipment at the time of such determination. As of December 31, 2024 and 2023, the non-refundable contributions totaled $5.9 million and $4.2 million, respectively.

AFUDC

Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in the applicable rate base for rate-making purposes when the completed projects are placed in service. During the year ended December 31, 2024, AFUDC was $1.4 million and was reflected as a reduction of interest expense. For the years ended December 31, 2023 and 2022, AFUDC was not material.

Leases

We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These leases enable us to conduct our business operations in the regions in which we operate. Our operating leases are included in operating lease right-of-use assets, other accrued liabilities, and operating lease - liabilities in our consolidated balance sheets.

Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Operating lease right-of-use assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on our balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term. Our leases do not provide an implicit lease rate, therefore, we utilize our incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. Our incremental borrowing rate represents the rate that we would have to pay to borrow funds on a collateralized basis over a similar term and in a similar economic environment.

We have lease agreements with lease and non-lease components. At the adoption of ASC 842, we elected not to separate non-lease components from all classes of our existing leases. The non-lease components have been accounted for as part of the single lease component to which they are related. See Note 14, Leases, for additional information.

Jointly-owned Pipelines

Property, plant and equipment for our Florida natural gas transmission operation included $28.4 million of jointly owned assets at December 31, 2024, primarily comprised of the 26-mile Callahan intrastate transmission pipeline in Nassau County, Florida jointly-owned with Seacoast Gas Transmission. Peninsula Pipeline's ownership is 50 percent. Direct expenses for the jointly-owned pipeline are included in operating expenses within our consolidated statements of income. Accumulated depreciation for this pipeline totaled $2.8 million and $2.2 million at December 31, 2024 and 2023, respectively.

Impairment of Long-lived Assets

We periodically evaluate whether events or circumstances have occurred, which indicate that long-lived assets may not be fully recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the asset, compared to the carrying value of the asset. When such events or circumstances are present, we record an impairment loss equal to the excess of the asset's carrying value over its fair value, if any.

Depreciation and Accretion Included in Operations Expenses

We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the respective regulatory bodies. Certain components of depreciation and accretion are reported in operations expenses, rather than as depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expenses consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2024, 2023 and 2022, we reported $15.8 million, $11.9 million and $11.0 million, respectively, of depreciation and accretion in operations expenses.

The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2024, 2023 and 2022:


	2024	2023	2022
Natural gas distribution – Delmarva Peninsula (1)	2.1%	2.5%	2.5%
Natural gas distribution – Florida (2) (3)	2.7%	2.2%	2.5%
Natural gas transmission – Delmarva Peninsula	2.7%	2.7%	2.7%
Natural gas transmission – Florida	2.4%	2.4%	2.4%
Natural gas transmission – Ohio (4)	2.3%	5.0%	5.0%
Electric distribution	2.4%	2.4%	2.8%

(1) Average for 2024 includes the impact of the depreciation study that was approved by the Maryland PSC for Maryland and Sandpiper.

(2) Includes the impact of FCG beginning in 2024.

(3) Average for 2023 includes the impact of the depreciation study that was approved by the Florida PSC in connection with the natural gas base rate proceeding.

(4) 2024 rate excludes the impact of cumulative adjustments related to a change in useful lives of certain assets. Such adjustments were not material to the Company's results of operations for the year ended December 31, 2024.

For our unregulated operations, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets:


Asset Description			Useful Life
Propane distribution mains			10-37 years
Propane bulk plants and tanks			10-40 years
Propane equipment, meters and meter installations			5-33 years
Measuring and regulating station equipment			5-37 years
Natural gas pipelines			45 years
Natural gas right of ways			Perpetual
CHP plant			30 years
Natural gas processing equipment			20-25 years
Office furniture and equipment			3-10 years
Transportation equipment			4-20 years
Structures and improvements			5-45 years
Other			Various

Regulated Operations

We account for our regulated operations in accordance with ASC Topic 980, Regulated Operations, which includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, a regulated company defers the associated costs as regulatory assets on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company, for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future, as regulatory liabilities. If we were required to terminate the application of these regulatory provisions to our regulated operations, all such deferred amounts would be recognized in our consolidated statement of income at that time, which could have a material impact on our financial position, results of operations and cash flows.

We monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we determined that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that the provisions of ASC Topic 980 continue to apply to our regulated operations and that the recovery of our regulatory assets is probable.

Operating Revenues

Revenue Recognition

Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC in each state in which they operate. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. Eastern Shore’s revenues are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to FERC-approved maximum rates.

For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class.

All of our regulated natural gas and electric distribution operations have fuel cost recovery mechanisms. These mechanisms allow us to adjust billing rates, without further regulatory approvals, to reflect changes in the cost of purchased fuel. Differences between the cost of fuel purchased and delivered are deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.

We charge flexible rates to our natural gas distribution industrial interruptible customers who can use alternative fuels. Interruptible service imposes no contractual obligation to deliver or receive natural gas on a firm service basis.

Our unregulated propane distribution businesses record revenue in the period the products are delivered and/or services are rendered for their bulk delivery customers. For propane customers with meters whose billing cycles do not coincide with our accounting periods, we accrue unbilled revenue for product delivered but not yet billed and bill customers at the end of an accounting period, as we do in our regulated energy businesses.

Our Ohio natural gas transmission/supply operation recognizes revenues based on actual volumes of natural gas shipped using contractual rates based upon index prices that are published monthly.

Eight Flags records revenues based on the amount of electricity and steam generated and sold to its customers.

Our mobile compressed natural gas operation recognizes revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for labor, equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees.

We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis.

For our businesses with agreements that contain variable consideration, we use the invoice practical expedient method. We determined that the amounts invoiced to customers correspond directly with the value to our customers and our performance to date.

Cost of Sales

Natural gas, electric and propane costs include the direct costs attributable to the products sold or services provided to our customers. These costs include primarily the variable commodity cost of natural gas, electricity and propane, costs of pipeline capacity needed to transport and store natural gas, transmission costs for electricity, costs to gather and process natural gas, costs to transport propane to/from our storage facilities or our mobile CNG equipment to customer locations, and steam and electricity generation costs. Depreciation expense is not included in natural gas, electric and propane costs.

Operations and Maintenance Expenses

Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of removal costs for future retirements of utility assets and other administrative expenses.

Cash and Cash Equivalents

Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates fair value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Credit Losses

Accounts receivable consist primarily of amounts due for sales of natural gas, electricity and propane and transportation and distribution services to customers. An allowance for doubtful accounts is recorded against amounts due based upon our collections experiences and an assessment of our customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, natural gas, electricity and propane prices and impacts from general economic conditions. Accounts receivable are written off when they are deemed to be uncollectible.

Our estimate for expected credit losses has been developed by analyzing our portfolio of financial assets that present potential credit exposure risk. These assets consist solely of our trade receivables from customers and contract assets. The estimate is based on five years of historical collections experience, a review of current economic and operating conditions in our service territories, and an examination of economic indicators which provide a reasonable and supportable basis of potential future activity. Those indicators include metrics which we believe provide insight into the future collectability of our trade receivables such as unemployment rates and economic growth statistics in our service territories.

When determining estimated credit losses, we analyze the balance of our trade receivables based on the underlying line of business. This includes an examination of trade receivables from our energy distribution, energy transmission, energy delivery services and propane operations businesses. Our energy distribution business consists of all our regulated distribution utility (natural gas and electric) operations on the Delmarva Peninsula and in Florida. These business units have the ability to recover their costs through the rate-making process, which can include consideration for amounts historically written off to be included in rate base. Therefore, they possess a mechanism to recover credit losses which we believe reduces their exposure to credit risk. Our energy transmission and energy delivery services business units consist of our natural gas pipelines and our mobile CNG delivery operations. The majority of customers served by these business units are regulated distribution utilities who also have the ability to recover their costs. We believe this cost recovery mechanism significantly reduces the amount of credit risk associated with these customers. Our propane operations are unregulated and do not have the same ability to recover their costs as our regulated operations. However, historically our propane operations have not had material write offs relative to the amount of revenues generated.

Our estimate of expected credit losses reflects our anticipated losses associated with our trade receivables as a result of non-payment from our customers beginning the day the trade receivable is established. We believe the risk of loss associated with trade receivables classified as current presents the least amount of credit exposure risk and therefore, we assign a lower estimate to our current trade receivables. As our trade receivables age outside of their expected due date, our estimate increases. Our allowance for credit losses relative to the balance of our trade receivables has historically been immaterial as a result of on time payment activity from our customers.

The table below illustrates the changes in the balance of our allowance for expected credit losses for the year ended December 31, 2024:


(in millions)
Balance at December 31, 2023	$	2.7
Additions:
Provision for credit losses	2.1
Recoveries	0.4
Deductions:
Write offs	(1.9)
Balance at December 31, 2024	$	3.3

Inventories

We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to their net realizable value. There were no lower-of-cost-or-net realizable value adjustment for the years ended December 31, 2024, 2023 or 2022.

Goodwill and Other Intangible Assets

Goodwill is not amortized but is tested for impairment at least annually, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We generally use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value. There were no goodwill impairments recognized during the years ended December 31, 2024, 2023 and 2022. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.

Other Deferred Charges

Other deferred charges include issuance costs associated with short-term borrowings. These charges are amortized over the life of the related short-term debt borrowings.

Asset Retirement Obligation [Policy Text Block]

Asset Removal Cost

As authorized by the appropriate regulatory body (state PSC or FERC), we accrue future asset removal costs associated with utility property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities or assets. When we retire depreciable utility plant and equipment, we charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities or assets. The difference between removal costs recognized in depreciation rates and the accretion and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes. Accordingly, these differences are deferred as regulatory liabilities or assets. In the rate setting process, the regulatory liability or asset is excluded from the rate base upon which those utilities have the opportunity to earn their allowed rates of return. The costs associated with our asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

See Note 18, Rates and Other Regulatory Activities, for information related to FCG's reserve surplus amortization mechanism ("RSAM") that was approved as part of its rate case effective as of May 1, 2023.

Pension and Other Postretirement Plans

Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates, including the fair value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. We review annually the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates, expected returns on plan assets and the mortality assumption are the factors that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.

The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When estimating our discount rates, we consider high-quality corporate

bond rates, such as the Empower curve index and the FTSE Index, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options.

The expected long-term rates of return on assets are utilized in calculating the expected returns on the plan assets component of our annual pension plan costs. We estimate the expected returns on plan assets by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on plan assets.

We estimate the health care cost trend rates used in determining our postretirement expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date.

The mortality assumption used for our pension and postretirement plans is reviewed periodically and is based on the actuarial table that best reflects the expected mortality of the plan participants.

Income Taxes and Investment Tax Credit Adjustments

Income Taxes, Investment Tax Credit Adjustments and Tax-Related Contingency

Deferred tax assets and liabilities are recorded for the income tax effect of temporary differences between the financial statement basis and tax basis of assets and liabilities and are measured using the enacted income tax rates in effect in the years in which the differences are expected to reverse. Deferred tax assets are recorded when it is more likely than not that such income tax benefits will be realized. Valuation allowances may be recorded if it is determined that some deferred tax assets will not be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.

We account for uncertainty in income taxes in our consolidated financial statements only if it is more likely than not that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the consolidated financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income.

We account for contingencies associated with taxes other than income when the likelihood of a loss is both probable and estimable. In assessing the likelihood of a loss, we do not consider the existence of current inquiries, or the likelihood of future inquiries, by tax authorities as a factor. Our assessment is based solely on our application of the appropriate statutes and the likelihood of a loss, assuming the proper inquiries are made by tax authorities.

Financial Instruments

We utilize financial instruments to mitigate commodity price risk associated with fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our propane operations enter into derivative transactions, such as swaps, put options and call options in order to mitigate the impact of wholesale price fluctuations on inventory valuation and future purchase commitments. These transactions may be designated as fair value hedges or cash flow hedges, if they meet all of the accounting requirements pursuant to ASC Topic 815, Derivatives and Hedging, and we elect to designate the instruments as hedges. If designated as a fair value hedge, the value of the hedging instrument, such as a swap, future, or put option, is recorded at fair value, with the effective portion of the gain or loss of the hedging instrument effectively reducing or increasing the value of the hedged item. If designated as a cash flow hedge, the value of the hedging instrument, such as a swap or call option, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument being initially recorded in accumulated other comprehensive income (loss) and reclassified to earnings when the associated hedged transaction settles. The ineffective portion of the gain or loss of a hedge is immediately recorded in earnings. If the instrument is not designated as a fair value or cash flow hedge, or it does not meet the accounting requirements of a hedge under ASC Topic 815, Derivatives and Hedging, it is recorded at fair value with all gains or losses being recorded directly in earnings.

Our natural gas, electric and propane operations enter into agreements with suppliers to purchase natural gas, electricity, and propane for resale to our respective customers. Purchases under these contracts, as well as distribution and sales agreements with counterparties or customers, either do not meet the definition of a derivative, or qualify for “normal purchases and normal sales” treatment under ASC Topic 815 and are accounted for on an accrual basis.

We manage interest rate risk by entering into derivative contracts to hedge the variability in cash flows attributable to changes in the short-term borrowing rates. We designate and account for the interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are recorded as a component of accumulated other comprehensive income (loss). When the interest rate swaps settle, the realized gain or loss will be recorded in the income statement and recognized as a component of interest charges.

Recently Adopted Accounting Standards

Schedule of Prospective Adoption of New Accounting Pronouncements [Table Text Block]

Segment Reporting (ASC 280) - In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures, which modifies required disclosures about a public entity’s reportable segments and addresses requests from investors for more detailed information about a reportable segment’s expenses and a more comprehensive reconciliation of each segment's reported profit or loss. We adopted ASU 2023-07 for our annual financial statements beginning January 1, 2024 and our interim financial statements beginning January 1, 2025. ASU 2023-07 only impacts disclosures, and as a result, did not have an impact on our financial position or results of operations.

Recent Accounting Standards Yet to be Adopted

FASB

Income Taxes (ASC 740) - In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which modifies required income tax disclosures primarily related to an entity's rate reconciliation and information pertaining to income taxes paid. These enhancements have been made to address requests from investors related to transparency and usefulness of income tax disclosures. ASU 2023-09 will be effective for our annual financial statements beginning January 1, 2025. ASU 2023-09 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations.

Income Statement Expense Disaggregation (ASC 220) - In November 2024, the FASB issued ASU 2024-04, Disaggregation of Income Statement Expenses, which require disclosure in the notes to financial statements of specified information about certain costs and expenses. ASU 2024-04 will be effective for our annual financial statements beginning January 1, 2027 and our interim financial statements beginning January 1, 2028. ASU 2024-04 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations.

SEC

Climate-Related Disclosures - In March 2024, the SEC issued a final rule that requires a public entity to provide disclosures surrounding material Scope 1 and Scope 2 emissions, climate-related risks and the material impact of those risks and material climate targets and goals. In April 2024, the SEC issued a stay on the final rule as a result of various petitions being filed and sought review of the final ruling in multiple courts of appeals. At this time, it is uncertain as to when the review will be completed, the final outcome of the review, and the timing of required disclosure.