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Note 1 — Nature of Operations

UGI is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we own and operate (1) a retail propane marketing and distribution business; (2) natural gas and electric distribution utilities; and (3) an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production, electricity generation and energy services business. In Europe, we market and distribute propane and other LPG and market energy products and services.

We conduct a domestic propane marketing and distribution business through AmeriGas Partners. AmeriGas Partners conducts a national propane distribution business through its principal operating subsidiary, AmeriGas OLP. AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc., serves as the General Partner of AmeriGas Partners. On August 21, 2019, we completed the AmeriGas Merger pursuant to which we issued 34,612,847 shares of UGI Common Stock and paid $528.9 in cash to acquire all of the outstanding Common Units in AmeriGas Partners not already held by UGI or its subsidiaries, with the Partnership surviving as a wholly owned subsidiary of UGI. Prior to the AmeriGas Merger, UGI controlled the Partnership through its ownership of the General Partner, which held a 1% general partner interest (which included IDRs) and approximately 25.5% of the outstanding Common Units in AmeriGas Partners, and held an effective 27.0% ownership interest in AmeriGas OLP. The IDRs held by the General Partner prior to the AmeriGas Merger entitled it to receive distributions from AmeriGas Partners in excess of its general partner interest under certain circumstances. Incentive distributions received by the General Partner during the six months ended March 31, 2019 were $22.9.

UGI International, through subsidiaries and affiliates, conducts (1) an LPG distribution business throughout much of Europe and (2) an energy marketing business in France, Belgium, the Netherlands and the United Kingdom. These businesses are conducted principally through our subsidiaries, UGI France, Flaga, AvantiGas, DVEP and UniverGas.

Energy Services conducts, directly and through subsidiaries, energy marketing, midstream transmission, LNG storage, natural gas gathering and processing, natural gas production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S., eastern Ohio and the panhandle of West Virginia. UGID owns all or a portion of electricity generation facilities principally located in Pennsylvania. Energy Services and its subsidiaries’ storage and portions of its LNG and midstream transmission operations are subject to regulation by the FERC.

UGI Utilities directly owns and operates Gas Utility, a natural gas distribution utility business in eastern and central Pennsylvania and in a portion of one Maryland county. Gas Utility is subject to regulation by the PAPUC and the FERC and, with respect to a small service territory in one Maryland county, the MDPSC. UGI Utilities also owns and operates Electric Utility, an electric distribution utility located in northeastern Pennsylvania. Electric Utility is subject to regulation by the PAPUC and the FERC.

Note 2 — Summary of Significant Accounting Policies

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the SEC. They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2019, Condensed Consolidated Balance Sheet was derived from audited financial statements but does not include all footnote disclosures from the annual financial statements.

These financial statements should be read in conjunction with the financial statements and related notes included in the Company’s 2019 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Leases. Effective October 1, 2019, the Company adopted ASU No. 2016-02, "Leases," which, as amended, is included in ASC 842. This new accounting guidance supersedes previous lease accounting guidance in ASC 840 and requires entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on its balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases.

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We adopted this new guidance using the modified retrospective transition method. Amounts and disclosures related to periods prior to October 1, 2019 have not been restated and continue to be reported in accordance with ASC 840. We elected to apply the following practical expedients in accordance with the guidance upon adoption:

•	Short-term leases: We did not recognize short-term leases (term of 12 months or less) on the balance sheet;

•	Easements: We did not re-evaluate existing land easements that were not previously accounted for as leases; and

•	Other: We did not reassess the classification of expired or existing contracts or determine whether they are or contain a lease. We also did not reassess whether initial direct costs qualify for capitalization under ASC 842.

Upon adoption, we recorded ROU assets and lease liabilities of $451.9 related to our operating leases. Our accounting for finance leases remained substantially unchanged. There were no cumulative effect adjustments made to opening retained earnings as of October 1, 2019. The adoption did not, and is not expected to, have a significant impact on our condensed consolidated statements of income or cash flows. See Note 9 for additional disclosures regarding our leases.

Equity Method Investments. We account for privately held equity securities of entities without readily determinable fair values in which we do not have control, but have significant influence over operating and financial policies, under the equity method. Our equity method investments are primarily comprised of PennEast and Pennant.

UGI PennEast, LLC and four other members comprising wholly owned subsidiaries of Southern Company, New Jersey Resources, South Jersey Industries, and Enbridge, Inc., each hold a 20% membership interest in PennEast. In September 2019, a panel of the U.S. Court of Appeals for the Third Circuit ruled that New Jersey’s Eleventh Amendment immunity barred PennEast from bringing an eminent domain lawsuit in federal court, under the Natural Gas Act, against New Jersey or its agencies. The Third Circuit subsequently denied PennEast’s petition for rehearing en banc. Following the Third Circuit denial of petition for rehearing, PennEast filed a petition for declaratory order with the FERC regarding interpretation of the Natural Gas Act; the FERC issued an order favorable to PennEast’s position on January 30, 2020. PennEast filed a petition for a writ of certiorari to seek U.S. Supreme Court review of the Third Circuit decision on February 18, 2020.  The ultimate outcome of these matters cannot be determined at this time, and could result in delays, additional costs, or the inability to move forward with the project, resulting in an impairment of all or a portion of our investment in PennEast.

Restricted Cash. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Condensed Consolidated Balance Sheets to the corresponding amounts reported on the Condensed Consolidated Statements of Cash Flows.

		Cash, Cash Equivalents and Restricted Cash
		March 31, 2020				March 31, 2019				September 30, 2019				September 30, 2018
Cash and cash equivalents		$	297.3			$	492.1			$	447.1			$	452.6
Restricted cash		104.4				26.3				63.7				9.6
Cash, cash equivalents and restricted cash		$	401.7			$	518.4			$	510.8			$	462.2

Earnings Per Common Share. Basic earnings per share attributable to UGI stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI stockholders include the effects of dilutive stock options and common stock awards.

 

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Shares used in computing basic and diluted earnings per share are as follows: 

		Three Months Ended March 31,						Six Months Ended March 31,
		2020			2019			2020			2019
Denominator (thousands of shares):
Weighted-average common shares outstanding — basic (a)		208,941			174,501			209,151			174,461
Incremental shares issuable for stock options and awards (b)		867			2,817			1,343			2,985
Weighted-average common shares outstanding — diluted		209,808			177,318			210,494			177,446

(a)	The three and six months ended March 31, 2020, reflects the August 2019 issuance of 34,613 shares of UGI Common Stock in connection with the AmeriGas Merger.

(b)	For the three and six months ended March 31, 2020 and 2019, there were 8,020 and 208 shares, respectively, associated with outstanding stock option awards that were excluded from the computation of diluted earnings per share above because their effect was antidilutive.

Derivative Instruments. Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the NPNS exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument, whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes.

Certain of our derivative instruments qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in AOCI, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. We do not designate our commodity and certain foreign currency derivative instruments as hedges under GAAP. Changes in the fair values of these derivative instruments are reflected in net income. Gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. From time to time, we also enter into net investment hedges. Gains and losses on net investment hedges that relate to our foreign operations are included in the cumulative translation adjustment component in AOCI until such foreign net investment is sold or liquidated.

Cash flows from derivative instruments, other than certain cross-currency swaps and net investment hedges, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges, if any, are included in cash flows from operating activities while cash flows from the currency portion of such hedges, if any, are included in cash flows from financing activities. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows.

For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 14.

Business Combination Purchase Price Allocations. From time to time, the Company enters into business combinations. In accordance with ASC 805, the purchase price is allocated to the various assets acquired and liabilities assumed at their estimated fair value as of the acquisition date. Fair values of assets acquired and liabilities assumed are based upon available information. Estimating fair values is generally subject to significant judgment and assumptions and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, under certain circumstances, up to one year from the acquisition date to finalize the purchase price allocation.

Other Non-Operating Income, Net. Included in “Other non-operating income, net,” on the Condensed Consolidated Statements of Income are net gains and losses on forward foreign currency contracts used to reduce volatility in net income associated with our foreign operations, and non-service income (expense) associated with our pension and other postretirement plans.

Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on

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management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

Reclassifications. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

Note 3 — Accounting Changes

New Accounting Standards Adopted in Fiscal 2020

Derivatives and Hedging. Effective October 1, 2019, the Company adopted ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. For cash flow and net investment hedges as of the adoption date, the guidance required a modified retrospective approach. The amended presentation and disclosure guidance was required prospectively. The adoption did not have a material impact on our consolidated financial statements.

Leases. Effective October 1, 2019, the Company adopted new accounting guidance for leases in accordance with ASC 842. See Notes 2 and 9 for a detailed description of the impact of the new guidance and related disclosures.

Accounting Standards Not Yet Adopted

Credit Losses. In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments.” This ASU, as subsequently amended, requires entities to estimate lifetime expected credit losses for financial instruments not measured at fair value through net income, including trade and other receivables, net investments in leases, financial receivables, debt securities, and other financial instruments, which may result in earlier recognition of credit losses. Further, the new current expected credit loss model may affect how entities estimate their allowance for losses related to receivables that are current with respect to their payment terms. ASU 2016-13 is effective for the Company for interim and annual periods beginning October 1, 2020 (Fiscal 2021). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.

Income Taxes. In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” This ASU simplifies the accounting for income taxes by eliminating certain exceptions within the existing guidance for recognizing deferred taxes for equity method investments, performing intraperiod allocations and calculating income taxes in interim periods. Further, this ASU clarifies existing guidance related to, among other things, recognizing deferred taxes for goodwill and allocated taxes to members of a consolidated group. ASU 2019-12 is effective for the Company for interim and annual periods beginning October 1, 2021 (Fiscal 2022). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Reference Rate Reform. In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides entities temporary optional guidance to ease potential accounting burdens to transition away from LIBOR or other reference rates that are expected to be discontinued and replaced with alternative reference rates. This ASU applies to all entities that have contracts, hedging relationships and other transactions affected by reference rate reform. The provisions in this ASU, among other things, simplify contract modification accounting and allow hedging relationships affected by reference rate reform to continue. ASU 2020-04 is effective upon issuance and entities may elect to apply the amendments prospectively through December 31, 2022. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the optional expedients will be elected.

Note 4 — Revenue from Contracts with Customers

The Company recognizes revenue when control of promised goods or services is transferred to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. See Note 4 in the Company’s 2019 Annual Report for information on our revenues from contracts with customers.

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Revenue Disaggregation

The following tables present our disaggregated revenues by reportable segment for the three and six months ended March 31, 2020 and 2019:

Three Months Ended March 31, 2020		Total				Eliminations (a)				AmeriGas Propane				UGI International				Midstream & Marketing				UGI Utilities				Corporate & Other
Revenues from contracts with customers:
Utility:
Core Market:
Residential		$	211.5			$	—			$	—			$	—			$	—			$	211.5			$	—
Commercial & Industrial		95.1				—				—				—				—				95.1				—
Large delivery service		41.4				—				—				—				—				41.4				—
Off-system sales and capacity releases		22.8				(15.9		)		—				—				—				38.7				—
Other		4.5				(0.6		)		—				—				—				5.1				—
Total Utility		375.3				(16.5		)		—				—				—				391.8				—
Non-Utility:
LPG:
Retail		1,194.3				—				712.2				482.1				—				—				—
Wholesale		74.0				—				18.8				55.2				—				—				—
Energy Marketing		419.1				(22.3		)		—				144.5				296.9				—				—
Midstream:
Pipeline		45.1				—				—				—				45.1				—				—
Peaking		2.8				(54.3		)		—				—				57.1				—				—
Other		1.7				—				—				—				1.7				—				—
Electricity Generation		7.8				—				—				—				7.8				—				—
Other		81.8				(0.7		)		55.9				17.4				9.2				—				—
Total Non-Utility		1,826.6				(77.3		)		786.9				699.2				417.8				—				—
Total revenues from contracts with customers		2,201.9				(93.8		)		786.9				699.2				417.8				391.8				—
Other revenues (b)		27.0				(0.7		)		15.1				4.2				4.4				0.8				3.2
Total revenues		$	2,228.9			$	(94.5	)		$	802.0			$	703.4			$	422.2			$	392.6			$	3.2

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Three Months Ended March 31, 2019		Total				Eliminations (a)				AmeriGas Propane				UGI International				Midstream & Marketing				UGI Utilities				Corporate & Other
Revenues from contracts with customers:
Utility:
Core Market:
Residential		$	240.3			$	—			$	—			$	—			$	—			$	240.3			$	—
Commercial & Industrial		100.7				—				—				—				—				100.7				—
Large delivery service		44.1				—				—				—				—				44.1				—
Off-system sales and capacity releases		21.9				(24.5		)		—				—				—				46.4				—
Other (c)		(3.3		)		(0.8		)		—				—				—				(2.5		)		—
Total Utility		403.7				(25.3		)		—				—				—				429.0				—
Non-Utility:
LPG:
Retail		1,405.6				—				874.6				531.0				—				—				—
Wholesale		93.8				—				25.2				68.6				—				—				—
Energy Marketing		552.1				(46.4		)		—				162.7				435.8				—				—
Midstream:
Pipeline		22.4				—				—				—				22.4				—				—
Peaking		8.1				(51.7		)		—				—				59.8				—				—
Other		0.7				—				—				—				0.7				—				—
Electricity Generation		11.6				—				—				—				11.6				—				—
Other		79.5				(0.7		)		57.1				12.7				10.4				—				—
Total Non-Utility		2,173.8				(98.8		)		956.9				775.0				540.7				—				—
Total revenues from contracts with customers		2,577.5				(124.1		)		956.9				775.0				540.7				429.0				—
Other revenues (b)		28.6				(0.7		)		14.7				8.2				1.7				0.6				4.1
Total revenues		$	2,606.1			$	(124.8	)		$	971.6			$	783.2			$	542.4			$	429.6			$	4.1

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Six Months Ended March 31, 2020		Total				Eliminations (a)				AmeriGas Propane				UGI International				Midstream & Marketing				UGI Utilities				Corporate & Other
Revenues from contracts with customers:
Utility:
Core Market:
Residential		$	395.6			$	—			$	—			$	—			$	—			$	395.6			$	—
Commercial & Industrial		163.0				—				—				—				—				163.0				—
Large delivery service		82.7				—				—				—				—				82.7				—
Off-system sales and capacity releases		39.2				(30.0		)		—				—				—				69.2				—
Other		8.9				(1.2		)		—				—				—				10.1				—
Total Utility		689.4				(31.2		)		—				—				—				720.6				—
Non-Utility:
LPG:
Retail		2,288.7				—				1,343.4				945.3				—				—				—
Wholesale		139.8				—				40.8				99.0				—				—				—
Energy Marketing		782.0				(47.9		)		—				268.4				561.5				—				—
Midstream:
Pipeline		88.3				—				—				—				88.3				—				—
Peaking		6.7				(92.0		)		—				—				98.7				—				—
Other		3.5				—				—				—				3.5				—				—
Electricity Generation		16.6				—				—				—				16.6				—				—
Other		162.7				(1.6		)		115.1				29.7				19.5				—				—
Total Non-Utility		3,488.3				(141.5		)		1,499.3				1,342.4				788.1				—				—
Total revenues from contracts with customers		4,177.7				(172.7		)		1,499.3				1,342.4				788.1				720.6				—
Other revenues (b)		57.8				(1.5		)		33.1				12.4				6.6				1.3				5.9
Total revenues		$	4,235.5			$	(174.2	)		$	1,532.4			$	1,354.8			$	794.7			$	721.9			$	5.9

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Six Months Ended March 31, 2019		Total				Eliminations (a)				AmeriGas Propane				UGI International				Midstream & Marketing				UGI Utilities				Corporate & Other
Revenues from contracts with customers:
Utility:
Core Market:
Residential		$	416.0			$	—			$	—			$	—			$	—			$	416.0			$	—
Commercial & Industrial		168.3				—				—				—				—				168.3				—
Large delivery service		83.6				—				—				—				—				83.6				—
Off-system sales and capacity releases		37.1				(47.4		)		—				—				—				84.5				—
Other (c)		(2.8		)		(1.5		)		—				—				—				(1.3		)		—
Total Utility		702.2				(48.9		)		—				—				—				751.1				—
Non-Utility:
LPG:
Retail		2,635.3				—				1,596.5				1,038.8				—				—				—
Wholesale		153.8				—				46.2				107.6				—				—				—
Energy Marketing		1,021.0				(93.9		)		—				305.8				809.1				—				—
Midstream:
Pipeline		41.8				—				—				—				41.8				—				—
Peaking		10.1				(90.4		)		—				—				100.5				—				—
Other		1.7				—				—				—				1.7				—				—
Electricity Generation		23.3				—				—				—				23.3				—				—
Other		163.5				(1.4		)		117.7				25.1				22.1				—				—
Total Non-Utility		4,050.5				(185.7		)		1,760.4				1,477.3				998.5				—				—
Total revenues from contracts with customers		4,752.7				(234.6		)		1,760.4				1,477.3				998.5				751.1				—
Other revenues (b)		53.6				(1.8		)		31.4				16.6				3.3				1.2				2.9
Total revenues		$	4,806.3			$	(236.4	)		$	1,791.8			$	1,493.9			$	1,001.8			$	752.3			$	2.9

(a)	Includes intersegment revenues principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.

(b)	Primarily represents revenues from tank rentals at AmeriGas Propane and UGI International, revenues from certain gathering assets at Midstream & Marketing, and gains and losses on commodity derivative instruments not associated with current-period transactions reflected in Corporate & Other, none of which are within the scope of ASC 606 and are accounted for in accordance with other GAAP.

(c)	UGI Utilities includes an unallocated negative surcharge revenue reduction of $(10.5) and $(14.6) for the three and six months ended March 31, 2019 as a result of a PAPUC Order issued May 17, 2018, related to the TCJA.

Contract Balances

The timing of revenue recognition may differ from the timing of invoicing to customers or cash receipts. Contract assets represent our right to consideration after the performance obligations have been satisfied when such right is conditioned on something other than the passage of time. Contract assets were not material for all periods presented. Substantially all of our receivables are unconditional rights to consideration and are included in “Accounts receivable” and, in the case of UGI Utilities, “Accrued utility revenues” on the Condensed Consolidated Balance Sheets. Amounts billed are generally due within the following month.

Contract liabilities arise when payment from a customer is received before the performance obligations have been satisfied and represent the Company’s obligations to transfer goods or services to a customer for which we have received consideration. The balances of contract liabilities were $62.2, $114.1 and $60.4 at March 31, 2020, September 30, 2019 and March 31, 2019, respectively, and are included in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets. Revenues recognized for the six months ended March 31, 2020 and 2019, from the amounts included in contract liabilities at September 30, 2019 and October 1, 2018, were $82.2 and $82.8, respectively.

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Remaining Performance Obligations

The Company has elected to use practical expedients as allowed in ASC 606 to exclude disclosures related to the aggregate amount of the transaction price allocated to certain performance obligations that are unsatisfied as of the end of the reporting period because these contracts have an initial expected term of one year or less, or we have a right to bill the customer in an amount that corresponds directly with the value of services provided to the customer to date. Certain contracts with customers at Midstream & Marketing and UGI Utilities contain minimum future performance obligations through 2047 and 2053, respectively. At March 31, 2020, Midstream & Marketing and UGI Utilities expect to record approximately $2.0 billion and $0.2 billion of revenues, respectively, related to the minimum future performance obligations over the remaining terms of the related contracts.

Note 5 — CMG Acquisition

On August 1, 2019, UGI through its wholly owned indirect subsidiary, Energy Services, completed the CMG Acquisition in which Energy Services acquired all of the equity interests in CMG and CMG’s approximately 47% interest in Pennant, for total cash consideration of $1,284.4. The CMG Acquisition was consummated pursuant to the CMG Acquisition Agreements. CMG and Pennant provide natural gas gathering and processing services through five discrete systems located in western Pennsylvania, eastern Ohio and the panhandle of West Virginia. The CMG Acquisition is consistent with our growth strategies, including expanding our midstream natural gas gathering and processing assets within the Marcellus and Utica Shale production regions. The CMG Acquisition was funded with cash from borrowings under the Energy Services Term Loan and the UGI Corporation Senior Credit Facility and cash on hand. We refer to CMG and its equity interest in Pennant as "UGI Appalachia".

The Company has accounted for the CMG Acquisition using the acquisition method. The components of the final CMG purchase price allocations are as follows:

Assets acquired:
Cash	$	0.3
Accounts receivable	10.2
Prepaid expenses and other current assets	1.1
Property, plant and equipment	613.6
Investment in Pennant	88.0
Intangible assets (a)	250.0
Total assets acquired	$	963.2
Liabilities assumed:
Accounts payable	$	3.3
Other noncurrent liabilities	0.1
Total liabilities assumed	$	3.4
Goodwill	324.6
Net consideration transferred (including working capital adjustments)	$	1,284.4

(a)	Represents customer relationships having an average amortization period of 35 years.

We allocated the purchase price of the acquisition to identifiable intangible assets and property, plant and equipment based on estimated fair values as follows:

•	Customer relationships were valued using a multi-period, excess earnings method. Key assumptions used in this method include discount rates, growth rates and cash flow projections. These assumptions are most sensitive and susceptible to change as they require significant management judgment; and

•	Property, plant and equipment were valued based on estimated fair values primarily using depreciated replacement cost and market value methods.

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The excess of the purchase price for the CMG Acquisition over the fair values of the assets acquired and liabilities assumed has been reflected as goodwill, assigned to the Midstream & Marketing reportable segment, and results principally from anticipated future capital investment opportunities and value creation resulting from new natural gas processing assets in the Marcellus and Utica Shale production regions. The goodwill recognized from the CMG Acquisition is deductible for income tax purposes.

The impact of the CMG Acquisition on a pro forma basis as if the CMG Acquisition had occurred on October 1, 2018 was not material to the Company’s consolidated results for the three and six months ended March 31, 2019.

Note 6 — Inventories

Inventories comprise the following: 

		March 31, 2020				September 30, 2019				March 31, 2019
Non-utility LPG and natural gas		$	110.1			$	150.2			$	159.7
Gas Utility natural gas		3.3				26.6				3.4
Materials, supplies and other		66.3				53.1				58.9
Total inventories		$	179.7			$	229.9			$	222.0

At March 31, 2020, UGI Utilities was party to three principal SCAAs with terms of up to three years. Pursuant to the SCAAs, UGI Utilities has, among other things, released certain natural gas storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated natural gas storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above. For all periods presented, UGI Utilities had SCAAs with Energy Services, the effects of which are eliminated in consolidation. At March 31, 2019, UGI Utilities had SCAAs with a non-affiliate, for which no gas storage inventories were released.

Note 7 — Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following: 

		March 31, 2020				September 30, 2019				March 31, 2019
Goodwill		$	3,465.5			$	3,456.4			$	3,147.8
Intangible assets:
Customer relationships		$	1,040.4			$	1,038.4			$	782.1
Trademarks and tradenames		11.8				16.2				16.5
Noncompete agreements and other		68.1				46.4				55.2
Accumulated amortization		(478.7		)		(441.8		)		(416.3		)
Intangible assets, net (definite-lived)		641.6				659.2				437.5
Trademarks and tradenames (indefinite-lived)		46.2				49.4				50.8
Total intangible assets, net		$	687.8			$	708.6			$	488.3

Amortization expense of intangible assets was $22.6 and $14.5 for the three months ended March 31, 2020 and 2019, respectively, and $39.4 and $29.1 for the six months ended March 31, 2020 and 2019, respectively. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2020 and for the next four fiscal years is as follows: remainder of Fiscal 2020 — $40.8; Fiscal 2021 — $67.2; Fiscal 2022 — $59.3; Fiscal 2023 — $56.9; Fiscal 2024 — $55.5.

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Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 9 in the Company’s 2019 Annual Report. Other than removal costs, UGI Utilities currently does not recover a rate of return on its regulatory assets listed below. The following regulatory assets and liabilities associated with UGI Utilities are included on the Condensed Consolidated Balance Sheets:

		March 31, 2020				September 30, 2019				March 31, 2019
Regulatory assets:
Income taxes recoverable		$	127.3			$	115.2			$	120.3
Underfunded pension and postretirement plans		171.8				178.6				83.6
Environmental costs		56.8				59.5				58.8
Removal costs, net		24.5				28.3				30.1
Other		10.5				14.0				6.5
Total regulatory assets		$	390.9			$	395.6			$	299.3
Regulatory liabilities (a):
Postretirement benefit overcollections		$	13.7			$	14.5			$	16.9
Deferred fuel and power refunds		11.3				6.1				17.7
State tax benefits — distribution system repairs		27.7				25.0				24.3
PAPUC Temporary Rates Order		15.4				31.3				25.1
Excess federal deferred income taxes		276.7				279.5				276.7
Other		1.1				2.4				18.8
Total regulatory liabilities		$	345.9			$	358.8			$	379.5

(a)	Regulatory liabilities are included in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.

Deferred Fuel and Power Refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of PGC rates in the case of Gas Utility and DS tariffs in the case of Electric Utility. These clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for retail core-market customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel and power costs or refunds. Net unrealized (losses) gains on such contracts at March 31, 2020, September 30, 2019 and March 31, 2019 were $(0.5), $(2.2) and $1.0, respectively.

Other Regulatory Matters

Base Rate Filings. On January 28, 2020, Gas Utility filed a request with the PAPUC to increase its base operating revenues for residential, commercial and industrial customers by $74.6 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and to continue funding programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Gas Utility requested that the new gas rates become effective March 28, 2020. The PAPUC entered an Order dated February 27, 2020, suspending the effective date for the rate increase to allow for investigation and public hearings for up to nine months from the date of filing. Thereafter, in response to a COVID-19 related motion to extend the suspension period indefinitely filed by the BIE, the Company voluntarily extended the end of the suspension period an additional twenty-one days, to November 19, 2020. Unless a settlement is reached sooner, this review process is expected to last until that date. The Company cannot predict the timing or the ultimate outcome of the rate case review process.

On January 28, 2019, Gas Utility filed a rate request with the PAPUC to increase the base operating revenues for residential, commercial, and industrial customers throughout its Pennsylvania service territory by an aggregate $71.1. On October 4, 2019,

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the PAPUC issued a final Order approving a settlement that permits Gas Utility, effective October 11, 2019, to increase its base distribution revenues by $30.0 under a single consolidated tariff, approved a plan for uniform class rates, and permits Gas Utility to extend its Energy Efficiency and Conservation and Growth Extension Tariff programs by an additional term of five years. The PAPUC’s final Order approved a negative surcharge, to return to customers $24.0 of tax benefits experienced by Gas Utility over the period January 1, 2018 to June 30, 2018, plus applicable interest, in accordance with the May 17, 2018 PAPUC Order, which became effective for a twelve-month period beginning on October 11, 2019, the effective date of Gas Utility’s new base rates.

On October 25, 2018, the PAPUC approved a final order providing for a $3.2 annual base distribution rate increase for Electric Utility, effective October 27, 2018. As part of the final PAPUC Order, Electric Utility provided customers with a one-time $0.2 billing credit associated with 2018 TCJA tax benefits. On November 26, 2018, the Pennsylvania Office of Consumer Advocate filed an appeal to the Pennsylvania Commonwealth Court challenging the PAPUC’s acceptance of UGI Utilities’ use of a fully projected future test year and handling of consolidated federal income tax benefits. On January 15, 2020, the Pennsylvania Commonwealth Court issued a decision affirming the PAPUC Order adopting UGI Utilities’ position on both issues. No party exercised their right to seek an appeal of the Commonwealth Court decision.

Note 9 — Leases

Lessee

We lease various buildings and other facilities, real estate, vehicles, rail cars and other equipment, the majority of which are operating leases. We determine if a contract is or contains a lease by evaluating whether the contract explicitly or implicitly identifies an asset, whether we have the right to obtain substantially all of the economic benefits of the identified leased asset and to direct its use.

ROU 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. We recognize ROU assets at the lease commencement date at the value of the lease liability adjusted for any prepayments, lease incentives received, and initial direct costs incurred. Lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. These payments are discounted using the discount rate implicit in the lease, when available. We apply an incremental borrowing rate, which is developed utilizing a credit notching approach based on information available at the lease commencement date, to substantially all of our leases as the implicit rate is often not available.

Lease expense is recognized on a straight-line basis over the expected lease term. Renewal and termination options are not included in the lease term unless we are reasonably certain that such options will be exercised. Leases with an original lease term of one year or less, including consideration of any renewal options assumed to be exercised, are not included in the Condensed Consolidated Balance Sheets.

Certain lease arrangements, primarily fleet vehicle leases with lease terms of one to ten years, contain purchase options. The Company generally excludes purchase options in evaluating its leases unless it is reasonably certain that such options will be exercised. Additionally, leases of fleet vehicles often contain residual value guarantees that are due at the end of the lease. Such amounts are included in the determination of lease liabilities when we are reasonably certain that they will be owed.

Certain leasing arrangements require variable payments that are dependent on asset usage or are based on changes in index rates, such as the Consumer Price Index. The variable payments component of such leases cannot be determined at lease commencement and is not recognized in the measurement of ROU assets or lease liabilities, but is recognized in earnings in the period in which the obligation occurs.

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ROU assets and lease liabilities recorded in the Condensed Consolidated Balance Sheet are as follows:

	March 31, 2020				Location on the Balance Sheet
ROU assets:
Operating lease ROU assets	$	431.8			Other assets
Finance lease ROU assets	54.0				Property, plant and equipment
Total ROU assets	$	485.8
Lease liabilities:
Operating lease liabilities - current	$	86.5			Other current liabilities
Operating lease liabilities - noncurrent	351.8				Other noncurrent liabilities
Finance lease liabilities - current	6.2				Current maturities of long-term debt
Finance lease liabilities - noncurrent	41.4				Long-term debt
Total lease liabilities	$	485.9

The components of lease cost are as follows:

	Three Months Ended March 31, 2020				Six Months Ended March 31, 2020
Operating lease cost	$	28.1			$	53.7
Finance lease cost:
Amortization of ROU assets	1.6				3.2
Interest on lease liabilities	0.7				1.2
Variable lease cost	1.4				2.8
Short-term lease cost	0.6				1.6
Total lease cost	$	32.4			$	62.5

The following table presents the cash and non-cash activity related to lease liabilities included in the Condensed Consolidated Statement of Cash Flows occurring during the period:

	Six Months Ended March 31, 2020
Cash paid related to lease liabilities:
Operating cash flows from operating leases	$	53.3
Operating cash flows from finance leases	$	1.2
Financing cash flows from finance leases	$	1.9
Non-cash lease liability activities:
ROU assets obtained in exchange for operating lease liabilities (including the impact upon adoption)	$	475.6
ROU assets obtained in exchange for finance lease liabilities	$	21.5

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The following table presents the weighted-average remaining lease term and weighted-average discount rate as of March 31, 2020:

Weighted-average remaining lease term		In years
Operating leases		6.3
Finance leases		2.4
Weighted-average discount rate		%
Operating leases		3.9%
Finance leases		2.0%

Expected annual lease payments based on maturities of operating and finance leases, as well as a reconciliation to the lease liabilities on the Condensed Consolidated Balance Sheet, as of March 31, 2020, were as follows:

	Remainder of Fiscal 2020				Fiscal 2021				Fiscal 2022				Fiscal 2023				Fiscal 2024				After Fiscal 2024				Total Lease Payments				Imputed Interest				Lease Liabilities
Operating leases:	$	50.8			$	93.3			$	77.8			$	68.6			$	59.1			$	146.8			$	496.4			$	(58.1	)		$	438.3
Finance leases:	$	3.1			$	5.1			$	4.0			$	3.4			$	3.1			$	85.9			$	104.6			$	(57.0	)		$	47.6

Approximately 85% of the operating lease liabilities presented above relates to AmeriGas Propane.

At March 31, 2020, operating and finance leases that had not yet commenced were not material.

Disclosures related to periods prior to adoption of ASC 842

As discussed above, the Company adopted ASC 842 effective October 1, 2019, using a modified retrospective approach. As required, the following disclosure is provided for periods prior to adoption. The Company’s future minimum payments under non-cancelable operating leases at September 30, 2019, which were accounted for under ASC 840, were as follows:

		Fiscal 2020				Fiscal 2021				Fiscal 2022				Fiscal 2023				Fiscal 2024				After Fiscal 2024
Total		$	100.4			$	85.9			$	71.0			$	61.7			$	53.6			$	139.2

Lessor

Note 10 — Debt

Energy Services. On March 6, 2020, Energy Services entered into the Energy Services 2020 Credit Agreement, as borrower, with a group of lenders. The Energy Services 2020 Credit Agreement amends and restates the Energy Services Credit Agreement. The Energy Services 2020 Credit Agreement provides for borrowings up to $260, including a $50 sublimit for letters of credit. Energy Services may request an increase in the amount of loan commitments under the Energy Services 2020 Credit Agreement to a maximum aggregate amount of $325, subject to certain terms and conditions. Borrowings under the Energy Services 2020 Credit Agreement can be used to fund acquisitions and investments and for general corporate purposes. The Energy Services 2020 Credit Agreement is scheduled to expire in March 2025.

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Borrowings under the Energy Services 2020 Credit Agreement bear interest at either (i) the Alternate Base Rate plus a margin or (ii) the Adjusted LIBOR plus a margin. The Alternate Base Rate, as defined, is the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, and (c) the Adjusted LIBOR for a one-month interest period plus 1% but in no event shall the Alternative Base Rate be less than 1%. The margins on borrowings ranges from 0.75% to 2.75% and are dependent upon Energy Services’ ratio of Consolidated Total Indebtedness to Consolidated EBITDA, as defined. The initial margin on the Alternate Base Rate and Adjusted LIBOR on borrowings under the Energy Services 2020 Credit Agreement were 1.50% and 2.50%, respectively. The Energy Services 2020 Credit Agreement includes customary provisions with respect to the replacement of LIBOR.

The Energy Services 2020 Credit Agreement requires that Energy Services not exceed ratios of Consolidated Total Indebtedness to Consolidated EBITDA, as defined, of 4.00 to 1.00, and maintain a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense, as defined, of 3.50 to 1.00. The Energy Services 2020 Credit Agreement is guaranteed by certain subsidiaries of Energy Services and is collateralized by substantially all of the assets of Energy Services, subject to certain exceptions and carveouts including, but not limited to, accounts receivables and certain real property. The Energy Services 2020 Credit Agreement is subject to customary covenants and default provisions including restrictions on the incurrence of additional indebtedness and also restricts liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions.

Subsequent Event

UGI Utilities. On April 16, 2020, UGI Utilities issued in a private placement $150 of UGI Utilities 3.12% Senior Notes due April 16, 2050 pursuant to a Note Purchase Agreement dated March 19, 2020, between UGI Utilities and certain note purchasers. The UGI Utilities 3.12% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the issuance of the UGI Utilities 3.12% Senior Notes were used to reduce short-term borrowings and for general corporate purposes. The UGI Utilities 3.12% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The UGI Utilities 3.12% Senior Notes require UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

Note 11 — Commitments and Contingencies

Environmental Matters

UGI Utilities

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain gas and electric operations. Beginning in 2006 and 2008, UGI Utilities also owned and operated two acquired subsidiaries (CPG and PNG), with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. CPG and PNG merged into UGI Utilities effective October 1, 2018.

Prior to the Utility Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, were subject to COAs with the PADEP to address the remediation of specified former MGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the Utility Merger, UGI Utilities, as the successor to CPG and PNG, is required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap (i.e. minimum expenditure threshold). The cost cap of the three COAs, in the aggregate, is $5.4. The three COAs are currently scheduled to terminate at the end of 2031, 2020 and 2020. UGI Utilities has initiated discussions with the PADEP to consolidate the three COAs into one agreement that, when finalized, would supersede the existing agreements as of the effective date and have a termination date of 2031. At March 31, 2020, September 30, 2019 and March 31, 2019, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $49.3, $50.4 and $50.8, respectively.

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We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to UGI Utilities’ results of operations because UGI Utilities receives ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. As such, UGI Utilities has recorded an associated regulatory asset for these costs because recovery of these costs from customers is probable (see Note 8).

From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by a former subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. Neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material for all periods presented.

AmeriGas Propane

AmeriGas OLP Saranac Lake. In 2008, the NYDEC notified AmeriGas OLP that the NYDEC had placed property purportedly owned by AmeriGas OLP in Saranac Lake, New York on the New York State Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by the NYDEC disclosed contamination related to a former MGP. AmeriGas OLP responded to the NYDEC in 2009 to dispute the contention it was a PRP as it did not operate the MGP and appeared to only own a portion of the site. In 2017, the NYDEC communicated to AmeriGas OLP that the NYDEC had previously issued three RODs related to remediation of the site totaling approximately $27.7 and requested additional information regarding AmeriGas OLP’s purported ownership. AmeriGas OLP renewed its challenge to designation as a PRP and identified potential defenses. The NYDEC subsequently identified a third party PRP with respect to the site.

The NYDEC commenced implementation of the remediation plan in the spring of 2018. Based on our evaluation of the available information as of March 31, 2020, the Partnership has an undiscounted environmental remediation liability of $7.5 related to the site. Our share of the actual remediation costs could be significantly more or less than the accrued amount.

Other Matters

Purported Class Action Lawsuits. Between May and October of 2014, purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI and a competitor by certain of their direct and indirect customers.  The class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade their common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws.  The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes. 

On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Missouri District Court.  As the result of rulings on a series of procedural filings, including petitions filed with the Eighth Circuit and the U.S. Supreme Court, both the federal and state law claims of the direct customer plaintiffs and the state law claims of the indirect customer plaintiffs were remanded to the Western Missouri District Court. The decision of the Western Missouri District Court to dismiss the federal antitrust claims of the indirect customer plaintiffs was upheld by the Eighth Circuit. On April 15, 2019, the Western Missouri District Court ruled that it has jurisdiction over the indirect purchasers’ state law claims and that the indirect customer plaintiffs have standing to pursue those claims. On August 21, 2019, the District Court partially granted the Company’s motion for judgment on the pleadings and dismissed the claims of indirect customer plaintiffs from ten states and the District of Columbia.

On October 2, 2019, the Partnership reached an agreement to resolve the claims of the direct purchaser class of plaintiffs, subject to court approval.

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Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial statements.

In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial statements.

Note 12 — Defined Benefit Pension and Other Postretirement Plans

The U.S. Pension Plan is a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, and certain of UGI’s other domestic wholly owned subsidiaries. U.S. Pension Plan benefits are based on years of service, age and employee compensation. We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to certain U.S. active and retired employees. In addition, certain UGI International employees in France, Belgium and the Netherlands are covered by defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the UGI International plans, such amounts are not material.

The service cost component of our pension and other postretirement plans, net of amounts capitalized, is reflected in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income. The non-service cost component, net of amounts capitalized by UGI Utilities as a regulatory asset, are reflected in “Other non-operating income, net” on the Condensed Consolidated Statements of Income. Net periodic pension cost and other postretirement benefit cost include the following components:

		Pension Benefits								Other Postretirement Benefits
Three Months Ended March 31,		2020				2019				2020				2019
Service cost		$	2.8			$	2.6			$	—			$	0.1
Interest cost		5.8				6.8				0.1				0.2
Expected return on assets		(9.4		)		(9.1		)		(0.2		)		(0.2		)
Curtailment gain		(1.1		)		—				—				—
Amortization of:
Prior service benefit		—				—				(0.1		)		(0.2		)
Actuarial loss		3.8				2.0				0.1				—
Net cost (benefit)		1.9				2.3				(0.1		)		(0.1		)
Change in associated regulatory liabilities		—				—				(0.4		)		(0.4		)
Net cost (benefit) after change in regulatory liabilities		$	1.9			$	2.3			$	(0.5	)		$	(0.5	)
		Pension Benefits								Other Postretirement Benefits
Six Months Ended March 31,		2020				2019				2020				2019
Service cost		$	5.6			$	5.1			$	0.1			$	0.1
Interest cost		11.6				13.6				0.3				0.4
Expected return on assets		(18.8		)		(18.1		)		(0.4		)		(0.4		)
Curtailment gain		(1.1		)		—				—				—
Amortization of:
Prior service cost (benefit)		0.1				0.1				(0.2		)		(0.3		)
Actuarial loss		7.5				3.9				0.1				—
Net cost (benefit)		4.9				4.6				(0.1		)		(0.2		)
Change in associated regulatory liabilities		—				—				(0.7		)		(0.7		)
Net cost (benefit) after change in regulatory liabilities		$	4.9			$	4.6			$	(0.8	)		$	(0.9	)

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The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. During the six months ended March 31, 2020 and 2019, the Company made cash contributions to the U.S. Pension Plan of $6.3 and $5.0, respectively. The Company expects to make additional cash contributions of approximately $6.0 to the U.S. Pension Plan during the remainder of Fiscal 2020.

UGI Utilities has established a VEBA trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. There were no required contributions to the VEBA during the six months ended March 31, 2020 and 2019.

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net costs associated with these plans for the three and six months ended March 31, 2020 and 2019, were not material.

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Note 13 — Fair Value Measurements

Recurring Fair Value Measurements

The following table presents, on a gross basis, our financial assets and liabilities, including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy:

		Asset (Liability)
		Level 1				Level 2				Level 3				Total
March 31, 2020:
Derivative instruments:
Assets:
Commodity contracts		$	36.4			$	11.9			$	—			$	48.3
Foreign currency contracts		$	—			$	58.0			$	—			$	58.0
Liabilities:
Commodity contracts		$	(92.2	)		$	(221.6	)		$	—			$	(313.8	)
Foreign currency contracts		$	—			$	(6.8	)		$	—			$	(6.8	)
Interest rate contracts		$	—			$	(54.1	)		$	—			$	(54.1	)
Non-qualified supplemental postretirement grantor trust investments (a)		$	38.6			$	—			$	—			$	38.6
September 30, 2019:
Derivative instruments:
Assets:
Commodity contracts		$	32.0			$	10.1			$	—			$	42.1
Foreign currency contracts		$	—			$	59.0			$	—			$	59.0
Liabilities:
Commodity contracts		$	(62.3	)		$	(112.7	)		$	—			$	(175.0	)
Foreign currency contracts		$	—			$	(4.3	)		$	—			$	(4.3	)
Interest rate contracts		$	—			$	(12.3	)		$	—			$	(12.3	)
Non-qualified supplemental postretirement grantor trust investments (a)		$	39.7			$	—			$	—			$	39.7
March 31, 2019:
Derivative instruments:
Assets:
Commodity contracts		$	33.3			$	27.7			$	—			$	61.0
Foreign currency contracts		$	—			$	29.8			$	—			$	29.8
Liabilities:
Commodity contracts		$	(17.0	)		$	(55.7	)		$	—			$	(72.7	)
Foreign currency contracts		$	—			$	(4.9	)		$	—			$	(4.9	)
Interest rate contracts		$	—			$	(5.7	)		$	—			$	(5.7	)
Non-qualified supplemental postretirement grantor trust investments (a)		$	40.2			$	—			$	—			$	40.2

(a)	Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 12).

 

The fair values of our Level 1 exchange-traded commodity futures and option contracts and non-exchange-traded commodity futures and forward contracts are based upon actively quoted market prices for identical assets and liabilities. The remainder of our derivative instruments are designated as Level 2. The fair values of certain non-exchange-traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. The fair values of our Level 2 interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments

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held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2). The carrying amounts and estimated fair values of our long-term debt (including current maturities but excluding unamortized debt issuance costs) were as follows:

	March 31, 2020				September 30, 2019				March 31, 2019
Carrying amount	$	5,878.6			$	5,856.6			$	4,341.2
Estimated fair value	$	5,735.7			$	6,189.3			$	4,380.4

Note 14 — Derivative Instruments and Hedging Activities

We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk; (2) interest rate risk; and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies, which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Although our commodity derivative instruments extend over a number of years, a significant portion of our commodity derivative instruments economically hedge commodity price risk during the next twelve months. For additional information on the accounting for our derivative instruments, see Note 2.

Commodity Price Risk

Regulated Utility Operations

Natural Gas

Gas Utility’s tariffs contain clauses that permit recovery of all prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PAPUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses NYMEX natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. Gains and losses on Gas Utility’s natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 8).

Non-utility Operations

LPG

In order to manage market price risk associated with the Partnership’s fixed-price programs, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic businesses

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and our UGI International operations also use over-the-counter price swap contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. The Partnership, from time to time, enters into price swap agreements to reduce the effects of short-term commodity price volatility. Also, Midstream & Marketing, from time to time, uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of propane.

Natural Gas

In order to manage market price risk relating to fixed-price sales contracts for physical natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and over-the-counter and ICE natural gas basis swap contracts. In addition, Midstream & Marketing uses NYMEX and over-the-counter futures and options contracts to economically hedge price volatility associated with the gross margin derived from the purchase and anticipated later near-term sale of natural gas storage inventories. Outside of the financial market, Midstream & Marketing also uses ICE and over-the-counter forward physical contracts. UGI International also uses natural gas futures and forward contracts to economically hedge market price risk associated with fixed-price sales contracts with its customers.

Electricity

In order to manage market price risk relating to fixed-price sales contracts for electricity, Midstream & Marketing enters into electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. UGI International also uses electricity futures and forward contracts to economically hedge market price risk associated with fixed-price sales and purchase contracts for electricity.

Interest Rate Risk

Certain of our long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. In order to fix the underlying short-term market interest rates, we may enter into pay-fixed, receive-variable interest rate swap agreements and designate such swaps as cash flow hedges.

The remainder of our long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time, we enter into IRPAs. We account for IRPAs as cash flow hedges. There were no unsettled IRPAs during any of the periods presented. At March 31, 2020, the amount of pre-tax net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3.5.

Foreign Currency Exchange Rate Risk

Forward Foreign Currency Exchange Contracts

In order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate to the euro and British pound sterling, we enter into forward foreign currency exchange contracts. We layer in these foreign currency exchange contracts over a multi-year period to eventually equal approximately 90% of anticipated UGI International local currency earnings before income taxes. Because these contracts are not designated as hedging instruments, realized and unrealized gains and losses on these contracts are recorded in “Other non-operating income, net,” on the Condensed Consolidated Statements of Income.

In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, we previously entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March. The last such contracts expired in September 2019. We accounted for these foreign currency exchange contracts as cash flow hedges.

From time to time, we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our UGI International euro-denominated net investments. We account for these foreign currency exchange contracts

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as net investment hedges. We use the forward rate method for measuring ineffectiveness for these net investment hedges and all changes in the fair value of the forward foreign currency contracts are reported in the cumulative translation adjustment component in AOCI.

Certain euro-denominated long-term debt issued under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes in October 2018 have been designated as net investment hedges of a portion of our UGI International euro-denominated net investment. We recognized pre-tax gains (losses) associated with these net investment hedges in the cumulative translation adjustment component in AOCI of $11.9 and $16.4 during the three months ended March 31, 2020 and 2019, respectively, and $(8.5) and $10.3 during the six months ended March 31, 2020 and 2019, respectively.

Quantitative Disclosures Related to Derivative Instruments

The following table summarizes by derivative type the gross notional amounts related to open derivative contracts at March 31, 2020, September 30, 2019 and March 31, 2019, and the final settlement date of the Company's open derivative transactions as of March 31, 2020, excluding those derivatives that qualified for the NPNS exception:

						Notional Amounts (in millions)
Type		Units		Settlements Extending Through		March 31, 2020				September 30, 2019				March 31, 2019
Commodity Price Risk:
Regulated Utility Operations
Gas Utility NYMEX natural gas futures and option contracts		Dekatherms		March 2021		11.3				23.3				11.6
Non-utility Operations
LPG swaps		Gallons		September 2022		816.4				800.4				369.2
Natural gas futures, forward and pipeline contracts		Dekatherms		December 2024		185.5				196.1				213.7
Natural gas basis swap contracts		Dekatherms		December 2024		155.4				131.1				84.0
NYMEX natural gas storage futures contracts		Dekatherms		March 2021		2.2				0.3				0.3
NYMEX natural gas option contracts		Dekatherms		N/A		—				2.4				—
NYMEX propane storage futures contracts		Gallons		April 2020		0.1				0.5				0.1
Electricity long forward and futures contracts		Kilowatt hours		January 2024		4,165.5				3,098.1				3,685.0
Electricity short forward and futures contracts		Kilowatt hours		April 2024		502.5				366.7				265.0
Interest Rate Risk:
Interest rate swaps		Euro		October 2022		€	300.0			€	300.0			€	300.0
Interest rate swaps		USD		July 2024		$	1,350.7			$	1,357.3			$	114.1
Foreign Currency Exchange Rate Risk:
Forward foreign currency exchange contracts		USD		September 2023		$	460.1			$	516.0			$	299.1
Net investment hedge forward foreign exchange contracts		Euro		October 2024		€	172.8			€	172.8			€	172.8

Derivative Instrument Credit Risk

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We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange traded futures contracts generally require cash deposits in margin accounts. Restricted cash in brokerage accounts is reported in “Restricted cash” on the Condensed Consolidated Balance Sheets. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss we would incur if these counterparties failed to perform according to the terms of their contracts, based upon the gross fair values of the derivative instruments, was not material at March 31, 2020. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At March 31, 2020, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on the Condensed Consolidated Balance Sheets if the right of offset exists. We offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange or clearinghouse to enter, execute or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions.

In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on the Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.

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Fair Value of Derivative Instruments

 

The following table presents the Company’s derivative assets and liabilities by type, as well as the effects of offsetting:

		March 31, 2020				September 30, 2019				March 31, 2019
Derivative assets:
Derivatives designated as hedging instruments:
Foreign currency contracts		$	27.2			$	17.4			$	7.1
Derivatives subject to PGC and DS mechanisms:
Commodity contracts		1.4				1.4				1.3
Derivatives not designated as hedging instruments:
Commodity contracts		46.9				40.7				59.7
Foreign currency contracts		30.8				41.6				22.7
		77.7				82.3				82.4
Total derivative assets — gross		106.3				101.1				90.8
Gross amounts offset in the balance sheet		(25.7		)		(29.0		)		(35.8		)
Total derivative assets — net		$	80.6			$	72.1			$	55.0
Derivative liabilities:
Derivatives designated as hedging instruments:
Interest rate contracts		$	(54.1	)		$	(12.3	)		$	(5.7	)
Derivatives subject to PGC and DS mechanisms:
Commodity contracts		(1.9		)		(3.7		)		(0.2		)
Derivatives not designated as hedging instruments:
Commodity contracts		(311.9		)		(171.3		)		(72.5		)
Foreign currency contracts		(6.8		)		(4.3		)		(4.9		)
		(318.7		)		(175.6		)		(77.4		)
Total derivative liabilities — gross		(374.7		)		(191.6		)		(83.3		)
Gross amounts offset in the balance sheet		25.7				29.0				35.8
Cash collateral pledged		58.0				29.3				—
Total derivative liabilities — net		$	(291.0	)		$	(133.3	)		$	(47.5	)

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Effects of Derivative Instruments

The following tables provide information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for the three and six months ended March 31, 2020 and 2019:

Three Months Ended March 31,:
		Gain (Loss) Recognized in AOCI								Gain (Loss) Reclassified from AOCI into Income								Location of Gain (Loss) Reclassified from AOCI into Income
Cash Flow Hedges:		2020				2019				2020				2019
Foreign currency contracts		$	—			$	0.2			$	—			$	1.3			Cost of sales
Interest rate contracts		(49.7		)		(2.4		)		(0.8		)		(1.3		)		Interest expense
Total		$	(49.7	)		$	(2.2	)		$	(0.8	)		$	—
Net Investment Hedges:
Foreign currency contracts		$	13.3			$	5.9
		Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:		2020				2019				Location of Gain (Loss) Recognized in Income
Commodity contracts		$	(205.5	)		$	(26.2	)		Cost of sales
Commodity contracts		5.6				4.6				Revenues
Commodity contracts		(0.4		)		0.1				Operating and administrative expenses
Foreign currency contracts		11.7				7.8				Other non-operating income, net
Total		$	(188.6	)		$	(13.7	)
Six Months Ended March 31,:
		Gain (Loss) Recognized in AOCI								Gain (Loss) Reclassified from AOCI into Income								Location of Gain (Loss) Reclassified from AOCI into Income
Cash Flow Hedges:		2020				2019				2020				2019
Foreign currency contracts		$	—			$	1.2			$	—			$	2.1			Cost of sales
Cross-currency contracts		—				(0.1		)		—				(0.3		)		Interest expense/other operating income, net
Interest rate contracts		(41.9		)		(5.2		)		(1.8		)		(2.8		)		Interest expense
Total		$	(41.9	)		$	(4.1	)		$	(1.8	)		$	(1.0	)
Net Investment Hedges:
Foreign currency contracts		$	9.8			$	6.8
		Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:		2020				2019				Location of Gain (Loss) Recognized in Income
Commodity contracts		$	(238.6	)		$	(185.9	)		Cost of sales
Commodity contracts		8.1				1.8				Revenues
Commodity contracts		(0.3		)		(0.3		)		Operating and administrative expenses
Foreign currency contracts		0.4				16.7				Other non-operating income, net
Total		$	(230.4	)		$	(167.7	)

We are also a party to a number of other contracts that have elements of a derivative instrument. However, these contracts qualify for NPNS exception accounting because they provide for the delivery of products or services in quantities that are expected to be

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used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold. These contracts include, among others, binding purchase orders, contracts that provide for the purchase and delivery, or sale, of energy products, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments.

Note 15 — Accumulated Other Comprehensive Income (Loss)

The tables below present changes in AOCI, net of tax, during the three and six months ended March 31, 2020 and 2019:

Three Months Ended March 31, 2020		Postretirement Benefit Plans				Derivative Instruments				Foreign Currency				Total
AOCI — December 31, 2019		$	(25.5	)		$	(19.1	)		$	(118.5	)		$	(163.1	)
Other comprehensive loss before reclassification adjustments (after-tax)		—				(35.6		)		(32.7		)		(68.3		)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)		1.5				0.8				—				2.3
Reclassification adjustments tax benefit		(0.4		)		(0.2		)		—				(0.6		)
Reclassification adjustments (after-tax)		1.1				0.6				—				1.7
Other comprehensive income (loss) attributable to UGI		1.1				(35.0		)		(32.7		)		(66.6		)
AOCI — March 31, 2020		$	(24.4	)		$	(54.1	)		$	(151.2	)		$	(229.7	)
Three Months Ended March 31, 2019		Postretirement Benefit Plans				Derivative Instruments				Foreign Currency				Total
AOCI — December 31, 2018		$	(13.6	)		$	(20.6	)		$	(98.9	)		$	(133.1	)
Other comprehensive loss before reclassification adjustments (after-tax)		—				(1.2		)		(26.8		)		(28.0		)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)		0.4				—				—				0.4
Reclassification adjustments tax benefit		(0.1		)		—				—				(0.1		)
Reclassification adjustments (after-tax)		0.3				—				—				0.3
Other comprehensive income (loss) attributable to UGI		0.3				(1.2		)		(26.8		)		(27.7		)
AOCI — March 31, 2019		$	(13.3	)		$	(21.8	)		$	(125.7	)		$	(160.8	)

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Six Months Ended March 31, 2020		Postretirement Benefit Plans				Derivative Instruments				Foreign Currency				Total
AOCI — September 30, 2019		$	(25.7	)		$	(25.4	)		$	(165.5	)		$	(216.6	)
Other comprehensive (loss) income before reclassification adjustments (after-tax)		—				(30.0		)		14.3				(15.7		)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)		1.8				1.8				—				3.6
Reclassification adjustments tax benefit		(0.5		)		(0.5		)		—				(1.0		)
Reclassification adjustments (after-tax)		1.3				1.3				—				2.6
Other comprehensive income (loss) attributable to UGI		1.3				(28.7		)		14.3				(13.1		)
AOCI — March 31, 2020		$	(24.4	)		$	(54.1	)		$	(151.2	)		$	(229.7	)
Six Months Ended March 31, 2019		Postretirement Benefit Plans				Derivative Instruments				Foreign Currency				Total
AOCI — September 30, 2018		$	(11.0	)		$	(16.1	)		$	(83.3	)		$	(110.4	)
Other comprehensive loss before reclassification adjustments (after-tax)		—				(2.7		)		(42.4		)		(45.1		)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)		0.8				1.0				—				1.8
Reclassification adjustments tax benefit		(0.2		)		(0.3		)		—				(0.5		)
Reclassification adjustments (after-tax)		0.6				0.7				—				1.3
Other comprehensive income (loss) attributable to UGI		0.6				(2.0		)		(42.4		)		(43.8		)
Reclassification of stranded income tax effects related to TCJA		(2.9		)		(3.7		)		—				(6.6		)
AOCI — March 31, 2019		$	(13.3	)		$	(21.8	)		$	(125.7	)		$	(160.8	)

For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 14.

Note 16 — Segment Information

Our operations comprise four reportable segments generally based upon products or services sold, geographic location and regulatory environment: (1) AmeriGas Propane; (2) UGI International; (3) Midstream & Marketing; and (4) UGI Utilities.

During the fourth quarter of Fiscal 2019, the measurement of segment profit used by our CODM was revised to exclude certain items that are now included in Corporate & Other (in addition to net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions, which had previously been excluded). The revision to our segment profit measures aligns with the financial information used by our CODM in evaluating our reportable segments’ performance and allocating resources. Prior period amounts have been recast to reflect the change in segment measure of profit. Also during the fourth quarter of Fiscal 2019, principally as a result of the AmeriGas Merger and the CMG Acquisition and related transactions, our CODM began evaluating the performance of all of our reportable segments based upon earnings before interest expense and income taxes, excluding the items noted above.

In addition to the items described above, Corporate & Other includes the net expenses of UGI’s captive general liability insurance company, UGI’s corporate headquarters facility and UGI’s unallocated corporate and general expenses as well as interest expense on UGI debt that is not allocated. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company, and UGI corporate headquarters’ assets. The accounting policies of our reportable segments are the same as those described in Note 2, “Summary of Significant Accounting Policies,” in the Company’s 2019 Annual Report.

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Three Months Ended March 31, 2020		Total				Eliminations				AmeriGas Propane				UGI International				Midstream & Marketing				UGI Utilities				Corporate & Other (a)
Revenues from external customers		$	2,228.9			$	—			$	802.0			$	703.4			$	344.8			$	376.1			$	2.6
Intersegment revenues		$	—			$	(94.5	)	(b)	$	—			$	—			$	77.4			$	16.5			$	0.6
Cost of sales		$	1,248.2			$	(93.4	)	(b)	$	325.6			$	401.6			$	298.3			$	184.0			$	132.1
Operating income (loss)		$	361.9			$	(0.3	)		$	206.0			$	116.8		(c)	$	71.3			$	116.0			$	(147.9	)
Income from equity investees		8.0				—				—				0.1				7.9			(d)	—				—
Other non-operating income, net		11.7				—				—				9.3				—				—				2.4
Earnings (loss) before interest expense and income taxes		381.6				(0.3		)		206.0				126.2				79.2				116.0				(145.5		)
Interest expense		(82.4		)		—				(41.2		)		(7.7		)		(11.4		)		(13.5		)		(8.6		)
Income (loss) before income taxes		$	299.2			$	(0.3	)		$	164.8			$	118.5			$	67.8			$	102.5			$	(154.1	)
Noncontrolling interests’ net income		$	0.1			$	—			$	—			$	0.1			$	—			$	—			$	—
Depreciation and amortization		$	120.2			$	(0.2	)		$	44.9			$	30.4			$	19.0			$	25.8			$	0.3
Capital expenditures (including the effects of accruals)		$	159.0			$	—			$	35.9			$	21.6			$	23.5			$	78.0			$	—

Three Months Ended March 31, 2019 (e)		Total				Eliminations				AmeriGas Propane				UGI International				Midstream & Marketing				UGI Utilities				Corporate & Other (a)
Revenues from external customers		$	2,606.1			$	—			$	971.6			$	783.2			$	443.6			$	404.3			$	3.4
Intersegment revenues		$	—			$	(124.8	)	(b)	$	—			$	—			$	98.8			$	25.3			$	0.7
Cost of sales		$	1,426.9			$	(123.6	)	(b)	$	435.2			$	444.7			$	449.3			$	218.0			$	3.3
Operating income (loss)		$	538.8			$	(0.4	)		$	247.3			$	126.9			$	51.3			$	119.9			$	(6.2	)
Income from equity investees		1.6				—				—				0.1				1.5			(d)	—				—
Other non-operating income, net		7.9				—				—				3.1				—				0.4				4.4
Earnings (loss) before interest expense and income taxes		548.3				(0.4		)		247.3				130.1				52.8				120.3				(1.8		)
Interest expense		(61.0		)		—				(42.2		)		(6.1		)		(0.5		)		(12.2		)		—
Income (loss) before income taxes		$	487.3			$	(0.4	)		$	205.1			$	124.0			$	52.3			$	108.1			$	(1.8	)
Noncontrolling interests’ net income		$	151.3			$	—			$	139.3			$	0.2			$	—			$	—			$	11.8
Depreciation and amortization		$	108.9			$	(0.1	)		$	44.3			$	30.6			$	11.5			$	22.3			$	0.3
Capital expenditures (including the effects of accruals)		$	151.2			$	—			$	25.8			$	22.1			$	32.3			$	70.8			$	0.2

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Six Months Ended March 31, 2020		Total				Eliminations				AmeriGas Propane				UGI International				Midstream & Marketing				UGI Utilities				Corporate & Other (a)
Revenues from external customers		$	4,235.5			$	—			$	1,532.4			$	1,354.8			$	653.1			$	690.7			$	4.5
Intersegment revenues		$	—			$	(174.2	)	(b)	$	—			$	—			$	141.6			$	31.2			$	1.4
Cost of sales		$	2,256.2			$	(172.5	)	(b)	$	614.8			$	770.0			$	562.5			$	335.6			$	145.8
Operating income (loss)		$	739.1			$	—			$	371.3			$	212.6		(c)	$	126.4			$	207.8			$	(179.0	)
Income from equity investees		14.5				—				—				0.1				14.4			(d)	—				—
Other non-operating income (expense), net		0.2				—				—				13.7				—				(0.2		)		(13.3		)
Earnings (loss) before interest expense and income taxes		753.8				—				371.3				226.4				140.8				207.6				(192.3		)
Interest expense		(166.5		)		—				(83.7		)		(15.3		)		(22.9		)		(27.1		)		(17.5		)
Income (loss) before income taxes		$	587.3			$	—			$	287.6			$	211.1			$	117.9			$	180.5			$	(209.8	)
Noncontrolling interests’ net income		$	0.1			$	—			$	—			$	0.1			$	—			$	—			$	—
Depreciation and amortization		$	239.6			$	(0.2	)		$	88.8			$	61.6			$	37.4			$	51.5			$	0.5
Capital expenditures (including the effects of accruals)		$	310.8			$	—			$	74.4			$	41.9			$	46.0			$	148.5			$	—
As of March 31, 2020
Total assets		$	14,135.5			$	(370.3	)		$	4,508.5			$	3,226.6			$	2,823.9			$	3,730.2			$	216.6
Short-term borrowings		$	653.5			$	—			$	201.0			$	185.5			$	43.0			$	224.0			$	—
Goodwill		$	3,465.5			$	—			$	2,003.0			$	938.2			$	342.2			$	182.1			$	—

Six Months Ended March 31, 2019 (e)		Total				Eliminations				AmeriGas Propane				UGI International				Midstream & Marketing				UGI Utilities				Corporate & Other (a)
Revenues from external customers		$	4,806.3			$	—			$	1,791.8			$	1,493.9			$	816.1			$	703.4			$	1.1
Intersegment revenues		$	—			$	(236.4	)	(b)	$	—			$	—			$	185.7			$	48.9			$	1.8
Cost of sales		$	2,851.9			$	(234.4	)	(b)	$	813.7			$	893.3			$	826.8			$	377.5			$	175.0
Operating income (loss)		$	706.5			$	—			$	413.9			$	185.2			$	92.4			$	196.9			$	(181.9	)
Income from equity investees		3.1				—				—				0.1				3.0			(d)	—				—
Loss on extinguishments of debt		(6.1		)		—				—				—				—				—				(6.1		)
Other non-operating income, net		16.9				—				—				3.8				—				0.8				12.3
Earnings (loss) before interest expense and income taxes		720.4				—				413.9				189.1				95.4				197.7				(175.7		)
Interest expense		(121.2		)		—				(84.6		)		(11.5		)		(1.0		)		(23.9		)		(0.2		)
Income (loss) before income taxes		$	599.2			$	—			$	329.3			$	177.6			$	94.4			$	173.8			$	(175.9	)
Noncontrolling interests’ net income (loss)		$	175.6			$	—			$	220.8			$	0.3			$	—			$	—			$	(45.5	)
Depreciation and amortization		$	220.1			$	(0.1	)		$	90.0			$	62.0			$	23.0			$	44.8			$	0.4
Capital expenditures (including the effects of accruals)		$	313.0			$	—			$	56.8			$	49.9			$	57.4			$	148.1			$	0.8
As of March 31, 2019
Total assets		$	12,350.9			$	(121.5	)		$	3,978.1			$	3,229.6			$	1,500.9			$	3,438.4			$	325.4
Short-term borrowings		$	341.0			$	—			$	236.0			$	—			$	—			$	105.0			$	—
Goodwill		$	3,147.8			$	—			$	2,003.1			$	944.8			$	17.8			$	182.1			$	—

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(a)

Corporate & Other includes specific items attributable to our reportable segments that are not included in the segment profit measures used by our CODM in assessing our reportable segments’ performance or allocating resources. The following table presents such pre-tax gains (losses) which have been included in Corporate & Other, and the reportable segments to which they relate, for the three and six months ended March 31, 2020 and 2019:

Three Months Ended March 31, 2020		Location on Income Statement		AmeriGas Propane				UGI International				Midstream & Marketing
Net (losses) gains on commodity derivative instruments not associated with current-period transactions		Revenues / Cost of sales		$	(21.1	)		$	(118.1	)		$	9.5
Unrealized gains on foreign currency derivative instruments		Other non-operating income, net		$	—			$	2.4			$	—
Acquisition and integration expenses associated with the CMG Acquisition		Operating and administrative expenses		$	—			$	—			$	(1.0	)
LPG business transformation expenses		Operating and administrative expenses		$	(12.8	)		$	(6.7	)		$	—

    

Three Months Ended March 31, 2019		Location on Income Statement		AmeriGas Propane				UGI International				Midstream & Marketing
Net gains (losses) on commodity derivative instruments not associated with current-period transactions		Revenues / Cost of sales		$	17.1			$	(28.6	)		$	11.6
Unrealized gains on foreign currency derivative instruments		Other non-operating income, net		$	—			$	4.6			$	—
AmeriGas Merger expenses		Operating and other administrative expenses		$	(0.9	)		$	—			$	—

Six Months Ended March 31, 2020		Location on Income Statement		AmeriGas Propane				UGI International				Midstream & Marketing
Net (losses) gains on commodity derivative instruments not associated with current-period transactions		Revenues / Cost of sales		$	(11.7	)		$	(131.6	)		$	2.0
Unrealized losses on foreign currency derivative instruments		Other non-operating income, net		$	—			$	(13.3	)		$	—
Acquisition and integration expenses associated with the CMG Acquisition		Operating and administrative expenses		$	—			$	—			$	(1.7	)
LPG business transformation expenses		Operating and administrative expenses		$	(24.0	)		$	(12.2	)		$	—

    

Six Months Ended March 31, 2019		Location on Income Statement		AmeriGas Propane				UGI International				Midstream & Marketing
Net (losses) gains on commodity derivative instruments not associated with current-period transactions		Revenues / Cost of sales		$	(61.4	)		$	(125.9	)		$	13.4
Unrealized gains on foreign currency derivative instruments		Other non-operating income, net		$	—			$	12.7			$	—
Loss on extinguishments of debt		Loss on extinguishments of debt		$	—			$	(6.1	)		$	—
AmeriGas Merger expenses		Operating and other administrative expenses		$	(0.9	)		$	—			$	—

(b)	Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.

(c)	Beginning October 1, 2019, UGI International is allocated a portion of indirect corporate expenses. Prior to October 1, 2019, these expenses were billed to its parent company, which is included in Corporate & Other.

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(d)	Includes AFUDC associated with PennEast. The three and six months ended March 31, 2020 also includes equity income from Pennant (see Note 5).

(e)	Segment information recast to reflect the changes adopted during the fourth quarter of Fiscal 2019 in the segment measure of profit used by our CODM to evaluate the performance of our reportable segments.

Note 17 — Global LPG Business Transformation Initiatives

During the fourth quarter of Fiscal 2019, we began executing on multi-year business transformation initiatives at our AmeriGas Propane and UGI International business segments. These initiatives are designed to improve long-term operational performance by, among other things, reducing costs and improving efficiency in the areas of sales and marketing, supply and logistics, operations, purchasing, and administration. In addition, these business transformation initiatives focus on enhancing the customer experience through, among other things, enhanced customer relationship management and an improved digital customer experience. In connection with these initiatives, during the three and six months ended March 31, 2020, we recognized $19.5 and $36.2, respectively, of expenses principally comprising consulting, advisory, marketing and employee-related costs. These expenses are reflected in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income.

Note 18 — Impact of Global Pandemic

In March 2020, the WHO declared a global pandemic attributable to the outbreak and continued spread of COVID-19 that has had a significant impact throughout the global economy. In connection with the mitigation and containment procedures recommended by the WHO and imposed by federal, state, and local governmental authorities, including shelter-in-place orders, quarantines and similar restrictions, the Company implemented a variety of procedures to protect its employees, third-party business partners, and customers worldwide. The Company continues to provide essential products and services to its global customers in a safe and reliable manner, and will continue to do so in compliance with mandated restrictions presented by each of the markets it serves. However, the Company continues to evaluate and react to the potential effects of a prolonged disruption and the related impacts on its results of operations. These items may include, but are not limited to: the financial condition of its customers; decreased availability and demand for its products and services; realization of accounts receivable; impairment considerations related to certain current assets, long-lived assets and goodwill; and delays related to current and future projects. While its operational and financial performance may be significantly impacted by COVID-19, the Company cannot predict the duration or magnitude of the outbreak and the effects on its business, financial position, results of operations, liquidity or cash flows at this time.

On March 27, 2020, the CARES Act was enacted in response to the COVID-19 pandemic. Among other things, the CARES Act includes provisions which modify the NOL limitation and carryback rules including a five-year carryback for NOLs arising in taxable years beginning in 2018, 2019, and 2020, and the temporary removal of the 80 percent limitation on NOL utilization for taxable years beginning before January 1, 2021. The Company’s annual effective income tax rate for Fiscal 2020 reflects anticipated tax benefits resulting from the carryback of an NOL for Fiscal 2020 pursuant to the provisions of the CARES Act.

The Company has not yet filed its income tax returns for Fiscal 2019 or 2020, and continues to evaluate other tax positions or strategies that could affect current-year or prior-year taxable income or loss.  Accordingly, the impacts from the CARES Act on the Company’s income tax provisions and taxes payable or refundable are subject to change.

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(a)

Corporate & Other includes certain adjustments made to our reporting segments in arriving at net income attributable to UGI Corporation, including the impact of the anticipated tax benefits resulting from the carryback of an NOL for Fiscal 2020 pursuant to the provisions of the CARES Act.  These adjustments have been excluded from the segment results to align with the measure used by our CODM in assessing segment performance and allocating resources.  See “Interest Expense and

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(b)	Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates.

(c)	Earnings per share for the 2020 three- and six-month periods reflect 34.6 million incremental shares of UGI Common Stock issued in conjunction with the AmeriGas Merger.

(d)	Includes the effects of rounding.

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(a)	Total margin represents total revenues less total cost of sales.

(b)	Deviation from average heating degree days for the 15-year period 2002-2016 based upon national weather statistics provided by NOAA for 344 Geo Regions in the United States, excluding Alaska and Hawaii.

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(a)

Total margin represents revenues less cost of sales and, in the 2019 three-month period, French energy certificate costs of $16.2 million. For financial statement purposes, French energy certificate costs in the 2019 three-month period are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from operating and administrative expenses presented above). In the 2020 three-month period, French energy certificate costs are included in cost of sales on the Condensed Consolidated Statements of Income.

(b)	Deviation from average heating degree days for the 15-year period 2002-2016 at locations in our UGI International service territories.

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(a)	Total margin represents revenues less cost of sales.

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(a)

Total margin represents revenues less cost of sales and revenue-related taxes (i.e., Electric Utility gross receipts taxes) of $1.3 million and $1.4 million during the three months ended March 31, 2020 and 2019, respectively. For financial statement purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from operating and administrative expenses presented above).

(b)	Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory.

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(a)	Total margin represents total revenues less total cost of sales.

(b)	Deviation from average heating degree days for the 15-year period 2002-2016 based upon national weather statistics provided by NOAA for 344 Geo Regions in the United States, excluding Alaska and Hawaii.

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(a)

Total margin represents revenues less cost of sales and, in the 2019 six-month period, French energy certificate costs of $26.2 million. For financial statement purposes, French energy certificate costs in the 2019 six-month period are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from operating and administrative expenses presented above). In the 2020 six-month period, French energy certificate costs are included in cost of sales on the Condensed Consolidated Statements of Income.

(b)	Deviation from average heating degree days for the 15-year period 2002-2016 at locations in our UGI International service territories.

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(a)	Total margin represents revenues less cost of sales.

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(a)

Total margin represents revenues less cost of sales and revenue-related taxes (i.e., Electric Utility gross receipts taxes) of $2.4 million and $2.7 million during the six months ended March 31, 2020 and 2019, respectively. For financial statement purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income (but are excluded from operating and administrative expenses presented above).

(b)	Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory.

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(a)	Amount includes finance lease liabilities recognized as a result of the adoption of ASU 2016-02. For additional information, see Notes 2 and 9 to Condensed Consolidated Financial Statements.

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(a)	The 2018 UGI International Credit Facilities Agreement permits UGI International, LLC to borrow in euros or dollars. At March 31, 2020, the amount borrowed comprised USD-denominated borrowings of $180 million, equal to €163.2 million.

(b)	Borrowings outstanding have been classified as “Long-term debt” on the Condensed Consolidated Balance Sheets.

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(a)	Evaluation of Disclosure Controls and Procedures

(b)	Change in Internal Control over Financial Reporting

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•	negatively impact the financial condition of our customers and their ability to pay for our products and services;

•	reduce energy consumption by certain of our customers, which would affect demand for our products;

•	disrupt or delay progress in the development and completion of our energy infrastructure projects;

•	prolong the time period necessary to perform maintenance of our infrastructure;

•	result in operational delays, including delay in the delivery of our products to customers;

•	result in impairment relating to certain current and long-lived assets; and

•	limit or curtail significantly or entirely the ability of public utility commissions to approve or authorize applications and other requests we may make with respect to our regulated businesses.

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(1)	Shares of UGI Corporation Common Stock are repurchased through an extension of a previous share repurchase program announced by the Company on January 25, 2018. The UGI Board of Directors authorized the repurchase of up to 8 million shares of UGI Corporation Common Stock over a four-year period expiring in January 2022.

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