XML 58 R28.htm IDEA: XBRL DOCUMENT

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Sep. 30, 2019

Principles of consolidation — The accompanying consolidated financial statements include the accounts of Atmos Energy Corporation and its wholly-owned subsidiaries. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process.

Use of estimates

Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include the allowance for doubtful accounts, unbilled revenues, contingency accruals, pension and postretirement obligations, deferred income taxes, impairment of long-lived assets, risk management and trading activities, fair value measurements and the valuation of goodwill and other long-lived assets. Actual results could differ from those estimates.

Regulation

Regulation — Our distribution and pipeline and storage operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our accounting policies recognize the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions. Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations. Further, regulation may impact the period in which revenues or expenses are recognized.

Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and our regulatory liabilities are recorded as a component of other current liabilities and deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the long-term portion of regulatory excess deferred taxes and regulatory cost of removal obligation are reported separately.

Revenue recognition

Revenue recognition — Effective October 1, 2018, we adopted the new guidance under Accounting Standards Codification (ASC) Topic 606. See “Accounting pronouncements adopted in fiscal 2019” herein and Note 5 for information regarding our adoption of ASC 606 and the related disclosures.

Distribution Revenues

Distribution revenues represent the delivery of natural gas to residential, commercial, industrial and public authority customers at prices based on tariff rates established by regulatory authorities in the states in which we operate. Revenue is recognized and our performance obligation is satisfied over time when natural gas is delivered and simultaneously consumed by our customer. We have elected to use the invoice practical expedient and recognize revenue for volumes delivered that we have the right to invoice our customers. We read meters and bill our customers on a monthly cycle basis. Accordingly, we estimate volumes from the last meter read to the balance sheet date and accrue revenue for gas delivered but not yet billed.

In our Texas and Mississippi jurisdictions, we pay franchise fees and gross receipt taxes to operate in these service areas. These franchise fees and gross receipts taxes are required to be paid regardless of our ability to collect from our customers. Accordingly, we account for these amounts on a gross basis in revenue and we record the associated tax expense as a component of taxes, other than income.

Pipeline and Storage Revenues

Pipeline and storage revenues primarily represent the transportation and storage of natural gas on our APT system and the transmission of natural gas through our 21-mile pipeline in Louisiana. APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies and certain industrial customers under tariff rates approved by the RRC. APT also provides certain transportation and storage services to industrial and electric generation customers, as well as marketers and producers, under negotiated rates. Our pipeline in Louisiana is primarily used to aggregate gas supply for our Louisiana Division under a long-term contract and on a more limited basis to third parties. The demand fee charged to our Louisiana Division is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans with distribution affiliates of the Company at terms that have been approved by the applicable state regulatory commissions. The performance obligations for these transportation customers are satisfied by means of transporting customer-supplied gas to the designated location. Revenue is recognized and our performance obligation is satisfied over time when natural gas is delivered to the customer. Management determined that these arrangements qualify for the invoice practical expedient for recognizing revenue. For demand fee arrangements, revenue is recognized and our performance obligation is satisfied by standing ready to transport natural gas over the period of each individual month.

Revenue Recognition for Alternative Revenue Programs

Alternative Revenue Program Revenues

In our distribution segment, we have weather-normalization adjustment mechanisms that serve to minimize the effects of weather on our Contribution Margin. Additionally, APT has a regulatory mechanism that requires that we share with its tariffed customers 75% of the difference between the total non-tariffed revenues earned during a test period and a revenue benchmark of $69.4 million that was established in its most recent rate case. Differences between actual revenues and revenues calculated under these mechanisms adjust the amount billed to customers. These mechanisms are considered to be alternative revenue programs under accounting standards generally accepted in the United States as they are deemed to be contracts between us and our regulator. Accordingly, revenue under these mechanisms are excluded from revenue from contracts with customers.

Purchased gas costs

Purchased gas costs — Rates established by regulatory authorities are adjusted for increases and decreases in our purchased gas costs through purchased gas cost adjustment mechanisms. Purchased gas cost adjustment mechanisms provide gas distribution companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case to address all of their non-gas costs. There is no margin generated through purchased gas cost adjustments, but they provide a dollar-for-dollar offset to increases or decreases in our distribution segment’s gas costs. The effects of these purchased gas cost adjustment mechanisms are recorded as deferred gas costs on our consolidated balance sheets.

Cash and cash equivalents

Cash and cash equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Accounts receivable and allowance for doubtful accounts

Accounts receivable and allowance for doubtful accounts — Accounts receivable arise from natural gas sales to residential, commercial, industrial, municipal and other customers. We establish an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect based on our collection experience or where we are aware of a specific customer’s inability or reluctance to pay. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Gas stored underground

Gas stored underground — Our gas stored underground is comprised of natural gas injected into storage to support the winter season withdrawals for our distribution operations. The average cost method is used for all of our distribution operations. Gas in storage that is retained as cushion gas to maintain reservoir pressure is classified as property, plant and equipment and is valued at cost.

Property, plant and equipment

Property, plant and equipment — Regulated property, plant and equipment is stated at original cost, net of contributions in aid of construction. The cost of additions includes direct construction costs, payroll related costs (taxes, pensions and other fringe benefits), administrative and general costs and an allowance for funds used during construction. The allowance for funds used during construction (AFUDC) represents the capitalizable total cost of funds used to finance the construction of major projects.

The following table details amounts capitalized for the fiscal year ended September 30.



		2019		2018		2017
Component of AFUDC	Statement of Comprehensive Income Location	(In thousands)
Debt	Interest charges	$	7,643	$	6,810	$	2,479
Equity	Other non-operating income (expense)	11,165		—		—
		$	18,808	$	6,810	$	2,479

Major renewals, including replacement pipe, and betterments that are recoverable through our regulatory rate base are capitalized while the costs of maintenance and repairs that are not capitalizable are charged to expense as incurred. The costs of large projects are accumulated in construction in progress until the project is completed. When the project is completed, tested and placed in service, the balance is transferred to the regulated plant in service account included in the rate base and depreciation begins.

Regulated property, plant and equipment is depreciated at various rates on a straight-line basis. These rates are approved by our regulatory commissions and are comprised of two components: one based on average service life and one based on cost of removal. Accordingly, we recognize our cost of removal expense as a component of depreciation expense. The related cost of removal accrual is reflected as a regulatory liability on the consolidated balance sheet. At the time property, plant and equipment is retired, removal expenses less salvage, are charged to the regulatory cost of removal accrual. The composite depreciation rate was 3.1 percent, 3.2 percent and 3.1 percent for the fiscal years ended September 30, 2019, 2018 and 2017.

Other property, plant and equipment is stated at cost. Depreciation is generally computed on the straight-line method for financial reporting purposes based upon estimated useful lives.

Asset retirement obligations

Asset retirement obligations — We record a liability at fair value for an asset retirement obligation when the legal obligation to retire the asset has been incurred with an offsetting increase to the carrying value of the related asset. Accretion of the asset retirement obligation due to the passage of time is recorded as an operating expense.

As of September 30, 2019 and 2018, we had asset retirement obligations of $17.1 million and $12.9 million. Additionally, we had $11.3 million and $7.5 million of asset retirement costs recorded as a component of property, plant and equipment that will be depreciated over the remaining life of the underlying associated assets.

We believe we have a legal obligation to retire our natural gas storage facilities. However, we have not recognized an asset retirement obligation associated with our storage facilities because we are not able to determine the settlement date of this obligation as we do not anticipate taking our storage facilities out of service permanently. Therefore, we cannot reasonably estimate the fair value of this obligation.

Impairment of long-lived assets

Impairment of long-lived assets — We evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded.

Goodwill

Goodwill — We annually evaluate our goodwill balances for impairment during our second fiscal quarter or more frequently as impairment indicators arise. During the second quarter of fiscal 2019, we completed our annual goodwill impairment assessment using a qualitative assessment, as permitted under U.S. GAAP. We test goodwill for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit. Based on the assessment performed, we determined that our goodwill was not impaired. Although not applicable for the fiscal 2019 analysis, if the qualitative assessment resulted in impairment indicators, we would then use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. These calculations are dependent on several subjective factors including the timing of future cash flows, future growth rates and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value.

Marketable securities

Marketable securities — As of September 30, 2019, we hold marketable securities classified as either equity or debt securities. Beginning on October 1, 2018, changes in fair value of our equity securities were recorded in net income as discussed further below in the Recent accounting pronouncements section. Debt securities, which are considered available for sale securities, are reported at market value with unrealized gains and losses shown as a component of accumulated other

comprehensive income (loss). During fiscal 2018 and under the previous accounting guidance, all our debt and equity securities were considered available for sale securities.

We regularly evaluate the performance of our available for sale debt securities on an investment by investment basis for impairment, taking into consideration the securities’ purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related investment is written down to its estimated fair value.

Financial instruments and hedging activities

Financial instruments and hedging activities — We currently use financial instruments to mitigate commodity price risk in our distribution and pipeline and storage segments and in the past have also used financial instruments to mitigate interest rate risk. The objectives and strategies for using financial instruments have been tailored to our business and are discussed in Note 14.

We record all of our financial instruments on the balance sheet at fair value, with changes in fair value ultimately recorded in the statement of comprehensive income. These financial instruments are reported as risk management assets and liabilities and are classified as current or noncurrent other assets or liabilities based upon the anticipated settlement date of the underlying financial instrument. We record the cash flow impact of our financial instruments in operating cash flows based upon their balance sheet classification.

The timing of when changes in fair value of our financial instruments are recorded in the statement of comprehensive income depends on whether the financial instrument has been designated and qualifies as a part of a hedging relationship or if regulatory rulings require a different accounting treatment. Changes in fair value for financial instruments that do not meet one of these criteria are recognized in the statement of comprehensive income as they occur.

Financial Instruments Associated with Commodity Price Risk

In our distribution segment, the costs associated with and the realized gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statements of comprehensive income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with accounting principles generally accepted in the United States. Accordingly, there is no earnings impact on our distribution segment as a result of the use of these financial instruments.

Financial Instruments Associated with Interest Rate Risk

In connection with the planned issuance of long-term debt, we may use financial instruments to manage interest rate risk. We historically managed this risk through the use of forward starting interest rate swaps to fix the Treasury yield component of the interest cost associated with anticipated financings. We designate these financial instruments as cash flow hedges at the time the agreements are executed. Unrealized gains and losses associated with the instruments are recorded as a component of accumulated other comprehensive income (loss). When the instruments settle, the realized gain or loss is recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest charges over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred is reported as a component of interest charges. As of September 30, 2019 and September 30, 2018, no cash was required to be held in margin accounts.

Fair Value Measurements

Fair Value Measurements — We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily use quoted market prices and other observable market pricing information in valuing our financial assets and liabilities and minimize the use of unobservable pricing inputs in our measurements.

Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties involved. Our counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and the use of collateral requirements under certain circumstances.

Amounts reported at fair value are subject to potentially significant volatility based upon changes in market prices, including, but not limited to, the valuation of the portfolio of our contracts, maturity and settlement of these contracts and newly originated transactions and interest rates, each of which directly affect the estimated fair value of our financial instruments. We believe the market prices and models used to value these financial instruments represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under then current market conditions.

Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). The levels of the hierarchy are described below:

Level 1 — Represents unadjusted quoted prices in active markets for identical assets or liabilities. An active market for the asset or liability is defined as a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Prices actively quoted on national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our balance sheet at fair value.

Our Level 1 measurements consist primarily of our debt and equity securities. The Level 1 measurements for investments in the Atmos Energy Corporation Master Retirement Trust (the Master Trust), Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of exchange-traded financial instruments.

Level 2 — Represents pricing inputs other than quoted prices included in Level 1 that are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data. Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps and municipal and corporate bonds where market data for pricing is observable. The Level 2 measurements for investments in our Master Trust, Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of non-exchange traded financial instruments such as corporate bonds and government securities.

Level 3 — Represents generally unobservable pricing inputs which are developed based on the best information available, including our own internal data, in situations where there is little if any market activity for the asset or liability at the measurement date. The pricing inputs utilized reflect what a market participant would use to determine fair value. We currently do not have any Level 3 investments.

Pension and other postretirement plans

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 market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and current demographic and actuarial mortality data. Our measurement date is September 30. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. For the valuation performed as of September 30, 2019, decreases in the discount rate resulted in actuarial losses that increased our plan obligations.

The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligation and net pension and postretirement cost. When establishing our discount rate, we consider high quality corporate bond rates based on bonds available in the marketplace that are suitable for settling the obligations, changes in those rates from the prior year and the implied discount rate that is derived from matching our projected benefit disbursements with currently available high quality corporate bonds.

The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of the annual pension and postretirement plan cost. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, 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 when making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan cost is not affected. Rather, this gain or loss is amortized over the expected future working lifetime of the plan participants.

The expected return on plan assets is then calculated by applying the expected long-term rate of return on plan assets to the market-related value of the plan assets. The market-related value of our plan assets represents the fair market value of the plan assets, adjusted to smooth out short-term market fluctuations over a five-year period. The use of this calculation will delay the impact of current market fluctuations on the pension expense for the period.

We use a corridor approach to amortize actuarial gains and losses. Under this approach, net gains or losses in excess of ten percent of the larger of the pension benefit obligation or the market-related value of the assets are amortized on a straight-line basis. The period of amortization is the average remaining service of active participants who are expected to receive benefits under the plan.

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

Income taxes

Income taxes — Income taxes are determined based on the liability method, which results in income tax assets and liabilities arising from temporary differences. Temporary differences are differences between the tax bases of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The liability method requires the effect of tax rate changes on accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.

The Company may recognize the tax benefit from uncertain tax positions only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon settlement with the taxing authorities. We recognize accrued interest related to unrecognized tax benefits as a component of interest charges. We recognize penalties related to unrecognized tax benefits as a component of miscellaneous income (expense) in accordance with regulatory requirements.

Tax collections

Tax collections — We are allowed to recover from customers revenue-related taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues. However, we do collect and remit various other taxes on behalf of various governmental authorities, and we record these amounts in our consolidated balance sheets on a net basis. We do not collect income taxes from our customers on behalf of governmental authorities.

Contingencies

Contingencies — In the normal course of business, we are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties or the action of various regulatory agencies. For such matters, we record liabilities when they are considered probable and estimable, based on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the future. Actual results may differ from estimates, depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure.

Recent accounting pronouncements

Accounting pronouncements adopted in fiscal 2019

During fiscal 2019, we adopted the following accounting guidance updates. The adoption of this new guidance, individually and collectively, did not have a material impact on our financial position, results of operations or cash flows.

•

Revenue recognition - We adopted the new guidance October 1, 2018 using the modified retrospective method. Under the new guidance, we are required to recognize revenue when we transfer promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The implementation of the new guidance did not have a material impact on our financial position, results of operations, cash flow or business processes. However, the guidance introduced new disclosures which are presented in Note 5.

•

Classification and measurement of financial instruments - The new guidance requires that we recognize changes in the fair value of our equity securities formerly designated as available-for-sale in other non-operating income (expense) in our consolidated statement of comprehensive income on a prospective basis from the date of adoption. However, we continue to classify cash flows from purchases and sales of equity securities within investing activities given the nature of these securities. Additionally, in accordance with the guidance, we reclassified a net $8.2 million unrealized gain related to these equity securities from accumulated other comprehensive income (AOCI) to retained earnings at October 1, 2018. The accounting for debt securities designated as available-for-sale did not change as a result of this new guidance. Accordingly, changes in the fair value of these securities will continue to be recorded as a component of AOCI.

•

Presentation of the Components of Net Periodic Benefit Cost - On October 1, 2018, we adopted the new guidance, which requires us to present only the current service cost component of the net benefit cost within operations and maintenance expense in the consolidated statements of comprehensive income. The remaining components of net benefit cost are now recorded in other non-operating income (expense) in our consolidated statements of comprehensive income. The change in presentation of these costs was implemented on a retrospective basis as required by the guidance. In lieu of determining how each component of the net periodic benefit cost was actually reflected in the prior periods’ statement of comprehensive income, we elected to utilize a practical expedient that permits the use of the amounts disclosed for these costs in our pension and post-retirement benefit plans footnote as the basis to retroactively apply this standard.

In addition, under the new guidance, only the service cost component of net benefit cost is eligible for capitalization (e.g., as part of inventory or property, plant, and equipment). We continue to capitalize these costs into property, plant and equipment.

However, the FERC, which establishes the regulatory accounting practices for rate-regulated entities, issued guidance that permits such entities the option to continue to capitalize non-service benefit costs for regulatory purposes. Since the accounting guidelines by the FERC are typically followed by our state regulatory authorities, for U.S. GAAP reporting purposes, we are prospectively deferring into a regulatory asset the portion of non-service components of net periodic benefit cost that are capitalizable for regulatory purposes.

•

Accounting for Implementation Costs Incurred in A Hosting Arrangement That Is A Service Contract - The new guidance aligns the requirements for capitalizing implementation costs incurred for these contracts with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). We elected to early adopt the new guidance on a prospective basis effective October 1, 2018. Accordingly, we will capitalize the up-front costs incurred for cloud computing arrangements had they been capitalizable in a similar on-premise software solution.

•

Disclosures of Defined Benefit Pension and Other Postretirement Plans - As of September 30, 2019, we elected to early adopt the new guidance, issued by the FASB in August 2018, that modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance removes the disclosure requirements for the amounts of gain/loss and prior service cost/credit amortization expected in the following year and the disclosure of the effect of a one-percentage-point change in the health care cost trend rate, among other changes. The guidance adds certain disclosures including the weighted average interest crediting rate for cash balance plans and a narrative description for the significant change in gains and losses as well as any other significant change in the plan obligations or assets. The adoption of this new guidance impacted only our disclosures, see Note 8.

Accounting pronouncements that will be effective after fiscal 2019

In February 2016, the FASB issued a comprehensive new leasing standard that will require lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with an initial term greater than 12 months on its balance sheet. Subsequently, the FASB issued practical expedients to 1) allow entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current guidance and 2) allow entities the option to adopt the standard and recognize a cumulative–effect adjustment to the opening balance of retained earnings in the period of adoption rather than applying the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The new standard was effective for us beginning on October 1, 2019.

The impact of this change on our financial position is expected to be material and we will be required to make additional disclosures. We do not anticipate the adoption of this standard will have a material impact to our results of operations or cash flows. We adopted the following practical expedients and accounting policy elections:

•land easements practical expedient under the provisions of ASU 2018-01, as described above,

•package of three practical expedients described in ASC 842-10-65-1,

•transition method practical expedient provided in ASU 2018-11, as described above,

•lease and non-lease component accounting policy election accounted for as single component, and

•short-term lease exemption to not apply Topic 842, as permitted.

We are implementing a new lease accounting system, which we will utilize to capture, track and account for lease data. The new system will also aid in automating the compilation of disclosure information. Additionally, we are implementing internal controls to adhere to the new accounting guidance and to facilitate in the preparation of financial information.

In June 2016, the FASB issued new guidance which will require credit losses on most financial assets measured at amortized cost and certain other instruments to be measured using an expected credit loss model. Under this model, entities will estimate credit losses over the entire contractual term of the instrument from the date of initial recognition of that instrument. In contrast, current U.S. GAAP is based on an incurred loss model that delays recognition of credit losses until it is probable the loss has been incurred. The new guidance also introduces a new impairment recognition model for available-for-sale debt securities that will require credit losses for available-for-sale debt securities to be recorded through an allowance account. The new standard will be effective for us beginning on October 1, 2020; early adoption is permitted. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.

Segment information

As of September 30, 2019, we manage and review our consolidated operations through the following two reportable segments:


•	The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states.


•	The pipeline and storage segment is comprised primarily of the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana.

Prior to disposition, the natural gas marketing segment, which was comprised of our natural gas marketing business, was also a reportable segment.

Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers. Although our distribution segment operations are geographically dispersed, they are aggregated and reported as a single segment as each natural gas distribution division has similar economic characteristics. In addition, because the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana have similar economic characteristics, they have been aggregated and reported as a single segment.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies. We evaluate performance based on net income or loss of the respective operating units. We allocate interest and pension expense to the pipeline and storage segment; however, there is no debt or pension liability recorded on the pipeline and storage segment balance sheet. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Income taxes are allocated to each segment as if each segment’s income taxes were calculated on a separate return basis.

Earnings per share

We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator.

Significant Accounting Policies Related to Discontinued Operations

Except as noted below, AEM adhered to the same Significant Accounting Policies as described in Note 2.

Revenue recognition — We adopted ASC 606 using the modified retrospective approach so AEM's revenue recognition was not impacted by the adoption of the new standard. Operating revenues for our natural gas marketing segment were recognized in the period in which actual volumes were transported and storage services were provided. Operating revenues for our natural gas marketing segment and the associated carrying value of natural gas inventory (inclusive of storage costs) were recognized when we sold the gas and physically delivered it to our customers. Operating revenues include realized gains and losses arising from the settlement of financial instruments used in our natural gas marketing activities.

Gas stored underground — Gas stored underground was comprised of natural gas injected into storage to conduct the operations of the natural gas marketing segment. Our natural gas marketing segment utilized the average cost method; however, most of this inventory was hedged and was therefore reported at fair value at the end of each month.

Property, plant and equipment — Natural gas marketing property, plant and equipment was stated at cost. Depreciation was generally computed on the straight-line method for financial reporting purposes based upon estimated useful lives ranging from 3 to 30 years.

Financial instruments and hedging activities — In our natural gas marketing segment, we previously designated most of the natural gas inventory held by this operating segment as the hedged item in a fair-value hedge. This inventory was marked to market at the end of each month based on the Gas Daily index, with changes in fair value recognized as unrealized gains or losses in purchased gas cost, which is reflected in income from discontinued operations in the period of change. The financial instruments associated with this natural gas inventory were designated as fair-value hedges and were marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains or losses in purchased gas cost in the period of change. We elected to exclude this spot/forward differential for purposes of assessing the effectiveness of these fair-value hedges.

Additionally, we previously elected to treat fixed-price forward contracts used in our natural gas marketing segment to deliver natural gas as normal purchases and normal sales. As such, these deliveries were recorded on an accrual basis in accordance with our revenue recognition policy. Financial instruments used to mitigate the commodity price risk associated with these contracts were designated as cash flow hedges of anticipated purchases and sales at indexed prices. Accordingly, unrealized gains and losses on these open financial instruments were recorded as a component of accumulated other comprehensive income, and were recognized in earnings as a component of purchased gas cost which is reflected in income from discontinued operations when the hedged volumes were sold.

Gains and losses from hedge ineffectiveness were recognized in the statement of comprehensive income. Fair value and cash flow hedge ineffectiveness arising from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the financial instruments is referred to as basis ineffectiveness. Ineffectiveness arising from changes in the fair value of the fair value hedges due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity is referred to as timing ineffectiveness. Hedge ineffectiveness, to the extent incurred, is reported as a component of purchased gas cost reflected in income from discontinued operations for the year ended September 30, 2017.

Our natural gas marketing segment also utilized master netting agreements with significant counterparties that allow us to offset gains and losses arising from financial instruments that would be settled in cash with gains and losses arising from financial instruments that could be settled with the physical commodity. Assets and liabilities from risk management activities, as well as accounts receivable and payable, reflect the master netting agreements in place. Additionally, the accounting guidance for master netting arrangements requires us to include the fair value of cash collateral or the obligation to return cash in the amounts that have been netted under master netting agreements used to offset gains and losses arising from financial instruments.

Fair Value Measurements — Our discontinued operations used the same fair value measurement policies as described in Note 2 for our continuing operations. Level 1 measurements included primarily exchange-traded financial instruments and gas stored underground that was been designated as the hedged item in a fair value hedge. Within our natural gas marketing operations, we utilized a mid-market pricing convention (the mid-point between the bid and ask prices), as permitted under current accounting standards. Values derived from these sources reflected the market in which transactions involving these financial instruments are executed. Level 2 measurements primarily consisted of non-exchange-traded financial instruments, such as over-the-counter options and swaps.

Short-term Debt Related to Discontinued Operations

AEM had one uncommitted $25 million 364-day bilateral credit facility that was scheduled to expire on July 31, 2017 and one committed $15 million 364-day bilateral credit facility that was scheduled to expire on September 30, 2017. In connection with the sale of AEM, both facilities were terminated on January 3, 2017.

Commodity Risk Management Activities

Our discontinued natural gas marketing segment was exposed to risks associated with changes in the market price of natural gas through the purchase, sale and delivery of natural gas to its customers at competitive prices. Through December 31, 2016, we managed our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Effective January 1, 2017, as a result of the sale of AEM, these activities were discontinued.

Due to the sale of AEM, we determined that the cash flows associated with our natural gas marketing commodity cash flow hedges were no longer probable of occurring; therefore, we discontinued hedge accounting as of December 31, 2016. As a result, we reclassified the gain in accumulated other comprehensive income associated with the commodity contracts into earnings as a reduction of purchased gas cost and recognized a pre-tax gain of $10.6 million, which is included in income from discontinued operations on the consolidated statement of comprehensive income for the year ended September 30, 2017.

The Company's other risk management activities are discussed in Note 14.

Impact of Financial Instruments on the Statement of Comprehensive Income

Hedge ineffectiveness for our natural gas marketing segment was recorded as a component of purchased gas cost, which is included in discontinued operations on the consolidated statement of comprehensive income, and primarily results from differences in the location and timing of the derivative instrument and the hedged item.