December 31,
2017 September 30,
2017 December 31,
2016
Non-utility LPG and natural gas $ 216.4
$ 188.4
$ 150.9
Gas Utility natural gas 34.6
39.5
25.8
Materials, supplies and other 56.3
50.7
51.5
Total inventories $ 307.3
$ 278.6
$ 228.2

At December 31, 2017, UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) which have terms of up to three years. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated 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.

As of December 31, 2017, UGI Utilities had SCAAs with Energy Services, LLC, the effects of which are eliminated in consolidation, and with a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at December 31, 2017, September 30, 2017 and December 31, 2016, comprising 1.8 billion cubic feet (“bcf”), 2.3 bcf and 1.9 bcf of natural gas, was $5.1, $6.7 and $4.8, respectively.

~~- 9 -~~

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

Revenue Disaggregation

~~Note 5 — Income Tax Reform~~

The following tables present our disaggregated revenues by reportable segment:

~~U.S. Tax Reform~~

On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was enacted into law. Among the significant changes resulting from the law, the TCJA reduces the U.S. federal income tax rate from 35% to 21% effective January 1, 2018, creates a territorial tax system with a one-time mandatory “toll tax” on previously unrepatriated foreign earnings, and allows for immediate capital expensing of certain qualified property. It also applies restrictions on the deductibility of interest expense, eliminates bonus depreciation for regulated utilities and applies a broader application of compensation limitations.

In accordance with GAAP as determined by ASC 740, “Income Taxes,” we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three months ended December 31, 2017, contain provisional estimates of the impact of the TCJA. These amounts are considered provisional because they use estimates for which tax returns have not yet been filed and because estimated amounts may be impacted by future regulatory and accounting guidance if and when issued. We will adjust these provisional amounts as further information becomes available and as we refine our calculations. As permitted by recent guidance issued by the SEC, these adjustments will occur during a reasonable “measurement period” not to exceed twelve months from the date of enactment.

As a result, during the three months ended December 31, 2017, we reduced our net deferred income tax liabilities by $383.8 due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of the enactment. Because part of the reduction to our net deferred income taxes relates to UGI Utilities’ regulated utility plant assets as further described below, most of UGI Utilities’ reduction in deferred income taxes is not being recognized immediately in income tax expense.

Discrete deferred income tax adjustments recorded during the three months ended December 31, 2017, which reduced income tax expense, totaled $166.0 (equal to $0.96 per basic share and $0.94 per diluted share) and consisted primarily of the following items:


~~(1)~~	~~a $180.3 reduction in net deferred tax liabilities in the U.S from the reduction of the U.S. tax rate;~~


~~(2)~~	~~the establishment of $12.6 of valuation allowances related to deferred tax assets impacted by U.S. tax law changes; and~~


~~(3)~~	~~a $1.7 “toll tax” on un-repatriated foreign earnings.~~

In order for UGI Utilities’ regulated utility plant assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred income taxes be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. At December 31, 2017, UGI Utilities has recorded a regulatory liability of $216.1 associated with excess deferred federal income taxes related to its regulated utility plant assets. This regulatory liability has been increased, and a federal deferred income tax asset has been recorded, in the amount of $87.8 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. For further information on this regulatory liability, see Note 7 to condensed consolidated financial statements.

For the three months ended December 31, 2017, we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rate. We are subject to a blended federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contains the effective date of the rate change from 35% to 21%. As a result, the U.S. federal income tax rate included in our estimated annual effective tax rate is based on this 24.5% blended rate for fiscal year 2018. For the three months ended December 31, 2017, the effects of the tax law changes on current-period results (excluding the one-time impacts described above) decreased income tax expense, and increased net income attributable to UGI, by approximately by $20.4. Regarding UGI Utilities, the PUC has not issued any orders with respect to the lower income tax rate. Our estimated annual effective tax rate for Fiscal 2018 does not reflect the impact of any regulatory action that may be taken by the PUC with respect to the TCJA.

~~Changes in French Corporate Income Tax Rates~~

In December 2017, the French Parliament approved the Finance Bill for 2018 and the second amended Finance Bill for 2017 (collectively, the “December 2017 French Finance Bills”). One impact of the December 2017 French Finance Bills is an increase in the Fiscal 2018 corporate income tax rate in France to 39.4% from 34.4% previously. The December 2017 French Finance Bills also include measures to reduce the corporate income tax rate to 25.8% effective for fiscal years starting after January 1, 2022 (Fiscal 2023). As a result of the future corporate income tax rate reduction effective in Fiscal 2023, during the three months ended December 31, 2017, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax


Three Months Ended June 30, 2023	Total		Eliminations (a)		AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other
Revenues from contracts with customers:
Utility:
Core Market:
Residential	$	151	$	—	$	—	$	—	$	—	$	151	$	—
Commercial & Industrial	60		—		—		—		—		60		—
Large delivery service	39		—		—		—		—		39		—
Off-system sales and capacity releases	7		(7)		—		—		—		14		—
Other	8		—		—		—		—		8		—
Total Utility	265		(7)		—		—		—		272		—
Non-Utility:
LPG:
Retail	799		—		423		376		—		—		—
Wholesale	76		—		24		52		—		—		—
Energy Marketing	336		(14)		—		156		194		—		—
Midstream:
Pipeline	58		—		—		—		58		—		—
Peaking	1		(5)		—		—		6		—		—
Other	3		—		—		—		3		—		—
Electricity Generation	17		—		—		—		17		—		—
Other	65		—		47		18		—		—		—
Total Non-Utility	1,355		(19)		494		602		278		—		—
Total revenues from contracts with customers	1,620		(26)		494		602		278		272		—
Other revenues (b)(c)	39		1		20		9		1		6		2
Total revenues	$	1,659	$	(25)	$	514	$	611	$	279	$	278	$	2

~~- 10 -~~

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

benefit of $17.3 (equal to $0.10 per basic and diluted share). The estimated annual effective income tax rate used in determining income taxes for the three months ended December 31, 2017, reflects the impact of the single year Fiscal 2018 income tax rate as a result of the December 2017 French Finance Bills. The impact of the single year rate change increased income tax expense for the three months ended December 31, 2017, by $3.9.

In December 2016, the French Parliament approved the Finance Bill for 2017 and amended the Finance Bill for 2016 (collectively, the “December 2016 French Finance Bills”). The December 2016 French Finance Bills, among other things, will reduce UGI France’s corporate income tax rate from the then-current 34.4% to 28.9%, effective for fiscal years starting after January 1, 2020 (Fiscal 2021). As a result of this future income tax rate reduction, during the three months ended December 31, 2016, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $27.4 (equal to $0.15 per basic and diluted share).

~~Note 6 — Goodwill and Intangible Assets~~

~~Goodwill and intangible assets comprise the following:~~


Three Months Ended June 30, 2022	Total		Eliminations (a)		AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other
Revenues from contracts with customers:
Utility:
Core Market:
Residential	$	140	$	—	$	—	$	—	$	—	$	140	$	—
Commercial & Industrial	57		—		—		—		—		57		—
Large delivery service	38		—		—		—		—		38		—
Off-system sales and capacity releases	9		(24)		—		—		—		33		—
Other	5		—		—		—		—		5		—
Total Utility	249		(24)		—		—		—		273		—
Non-Utility:
LPG:
Retail	880		—		478		402		—		—		—
Wholesale	107		—		48		59		—		—		—
Energy Marketing	631		(70)		—		246		455		—		—
Midstream:
Pipeline	53		—		—		—		53		—		—
Peaking	9		(5)		—		—		14		—		—
Other	2		—		—		—		2		—		—
Electricity Generation	1		—		—		—		1		—		—
Other	72		—		51		21		—		—		—
Total Non-Utility	1,755		(75)		577		728		525		—		—
Total revenues from contracts with customers	2,004		(99)		577		728		525		273		—
Other revenues (b)	29		—		20		10		—		1		(2)
Total revenues	$	2,033	$	(99)	$	597	$	738	$	525	$	274	$	(2)

December 31,
2017 September 30,
2017 December 31,
2016
Goodwill (not subject to amortization) $ 3,185.5
$ 3,107.2
$ 2,935.8
Intangible assets:
Customer relationships, noncompete agreements and other $ 862.0
$ 817.8
$ 759.4
Accumulated amortization (355.0 ) (340.2 ) (329.0 )
Intangible assets, net (definite-lived) 507.0
477.6
430.4
Trademarks and tradenames (indefinite-lived) 134.9
134.1
128.5
Total intangible assets, net $ 641.9
$ 611.7
$ 558.9

The changes in goodwill and intangible assets are primarily due to acquisitions and the effects of currency translation. Amortization expense of intangible assets was $14.8 and $12.5 for the three months ended December 31, 2017 and 2016, respectively. Amortization expense included in “Cost of sales” on the Condensed Consolidated Statements of Income was not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2018 and for the next four fiscal years is as follows: remainder of Fiscal 2018 — $42.8; Fiscal 2019 — $55.1; Fiscal 2020 — $53.7; Fiscal 2021 — $51.9; Fiscal 2022 — $50.2.

~~- 11 -~~

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)



Nine Months Ended June 30, 2023	Total		Eliminations (a)		AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other
Revenues from contracts with customers:
Utility:
Core Market:
Residential	$	911	$	—	$	—	$	—	$	—	$	911	$	—
Commercial & Industrial	369		—		—		—		—		369		—

Large delivery service	139		—		—		—		—		139		—
Off-system sales and capacity releases	84		(68)		—		—		—		152		—
Other	34		(1)		—		—		—		35		—
Total Utility	1,537		(69)		—		—		—		1,606		—
Non-Utility:
LPG:
Retail	3,243		—		1,812		1,431		—		—		—
Wholesale	287		—		120		167		—		—		—
Energy Marketing	1,854		(130)		—		755		1,229		—		—
Midstream:
Pipeline	189		—		—		—		189		—		—
Peaking	28		(102)		—		—		130		—		—
Other	10		—		—		—		10		—		—
Electricity Generation	27		—		—		—		27		—		—
Other	207		—		151		56		—		—		—
Total Non-Utility	5,845		(232)		2,083		2,409		1,585		—		—
Total revenues from contracts with customers	7,382		(301)		2,083		2,409		1,585		1,606		—
Other revenues (b)(c)	142		(1)		64		27		1		38		13
Total revenues	$	7,524	$	(302)	$	2,147	$	2,436	$	1,586	$	1,644	$	13

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)


Nine Months Ended June 30, 2022	Total		Eliminations (a)		AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other
Revenues from contracts with customers:
Utility:
Core Market:
Residential	$	774	$	—	$	—	$	—	$	—	$	774	$	—
Commercial & Industrial	318		—		—		—		—		318		—
Large delivery service	135		—		—		—		—		135		—
Off-system sales and capacity releases	65		(86)		—		—		—		151		—
Other	17		(1)		—		—		—		18		—
Total Utility	1,309		(87)		—		—		—		1,396		—
Non-Utility:
LPG:
Retail	3,684		—		2,032		1,652		—		—		—
Wholesale	401		—		172		229		—		—		—
Energy Marketing	2,254		(206)		—		1,045		1,415		—		—
Midstream:
Pipeline	149		—		—		—		149		—		—
Peaking	38		(101)		—		—		139		—		—
Other	6		—		—		—		6		—		—
Electricity Generation	20		—		—		—		20		—		—
Other	221		—		163		58		—		—		—
Total Non-Utility	6,773		(307)		2,367		2,984		1,729		—		—
Total revenues from contracts with customers	8,082		(394)		2,367		2,984		1,729		1,396		—
Other revenues (b)	90		(2)		56		27		2		4		3
Total revenues	$	8,172	$	(396)	$	2,423	$	3,011	$	1,731	$	1,400	$	3

(a)Includes intersegment revenues principally among Midstream & Marketing, 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, revenues from alternative revenue programs at Utilities 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)Includes the impact of the weather normalization adjustment rider, a five-year pilot program beginning on November 1, 2022 for PA Gas Utility. See Note 7 for additional information.

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 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 $133, $164 and $128 at June 30, 2023, September 30, 2022 and June 30, 2022, respectively, and are included in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

Revenues recognized for the nine months ended June 30, 2023 and 2022, from the amounts included in contract liabilities at September 30, 2022 and 2021, were $118 and $117, respectively.

Remaining Performance Obligations

The Company excludes 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 Utilities contain minimum future performance obligations through 2047 and 2053, respectively. At June 30, 2023, Midstream & Marketing and Utilities expect to record approximately $2.2 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 — Dispositions and Acquisition

UGI International Energy Marketing Businesses

Sale of U.K. Energy Marketing Business. On October 21, 2022, UGI International, through a wholly-owned subsidiary, sold its natural gas marketing business located in the U.K. for a net cash payment of $19 which includes certain working capital adjustments. In conjunction with the sale, during the first quarter of Fiscal 2023, the Company recorded a pre-tax loss of $215 ($151 after-tax) substantially all of which loss was due to the non-cash transfer of commodity derivative instruments associated with the business. At the date of closing of the sale, these commodity derivative instruments had a net carrying value of $206 which is attributable to net unrealized gains on such instruments. At September 30, 2022, these derivative instruments were classified as held for sale assets and liabilities on the Condensed Consolidated Balance Sheet and had a net carrying value of $276. The change in the carrying value of these derivative instruments between September 30, 2022 and October 21, 2022 resulted from changes in their fair values during that period.

Other UGI International Energy Marketing Businesses. In November 2022, the Company announced that it expected to sign a definitive agreement during the first quarter of Fiscal 2023 to sell its energy marketing business in France. In December 2022, the Company announced that it no longer expected to sign such agreement as extended negotiations with the potential buyer had been discontinued.

During the first quarter of Fiscal 2023, the Company recorded a $19 pre-tax impairment charge to reduce the carrying values of certain assets associated with its energy marketing business in the Netherlands, comprising property, plant and equipment and intangible assets. The impairment charge is reflected in “Operating and administrative expenses” on the Condensed Consolidated Statement of Income and included in the UGI International reportable segment.

On July 8, 2023, UGI International, through a wholly-owned subsidiary, entered into a definitive agreement to sell a substantial portion of its energy marketing business located in Belgium, principally comprising customer contracts and prepaid broker fees. The assets associated with the pending sale were not material at June 30, 2023 and have been classified as “Held for sale assets” on the Condensed Consolidated Balance Sheet as of June 30, 2023. The initially estimated cash proceeds, less a payment to the buyer, on or subsequent to the closing date, pursuant to the definitive agreement is not expected to be material. The cash payment to buyer is equal to an agreed upon portion of the fair value, as of the closing date, of associated derivative commodity hedge contracts currently held by UGI International. The closing of the pending sale is subject to regulatory and other third-party approvals and is expected to occur during the fourth quarter of Fiscal 2023.

On August 1, 2023, UGI International, through a wholly-owned subsidiary, entered into a definitive agreement to sell a substantial portion of its energy marketing business located in France, principally comprising customer contracts, energy certificates and substantially all of its derivative commodity hedge contracts, for an initially estimated net cash payment to the buyer of €23. This initially estimated closing date payment is subject to adjustments relating to, among other things, the actual date of closing, the fair value of derivative commodity hedge contracts currently held by the Company but not subject to transfer to the buyer, and conditions associated with certain customer contracts. The effects of these adjustments will be settled on, or subsequent to, the closing date. The closing of the pending sale is subject to regulatory and other third-party approvals and is expected to occur during the first quarter of Fiscal 2024.

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

The assets and liabilities associated with the energy marketing business in France, principally comprising the fair values of substantially all of its derivative commodity hedge contracts, have been classified as “Held for sale assets” and “Held for sale liabilities” on the Condensed Consolidated Balance Sheet as of June 30, 2023. The net fair value of these derivative commodity hedge contracts at June 30, 2023 was an asset of $10.

The amount of the gain or loss to be recognized upon the closing of these transactions will depend, in large part, on the fair values of the associated derivative commodity hedge contracts as of the respective dates of closing. The Company’s policy for the recognition of impairment charges is limited to the disposal group’s long-lived assets related to held for sale. The Company did not recognize any such impairment for the period ended June 30, 2023.

The Company continues to pursue the wind-down of its energy marketing business located in the Netherlands and its remaining natural gas marketing business in France. On July 21, 2023, DVEP signed a definitive agreement to sell a substantial portion of its power purchase agreement portfolio for a net cash payment to the buyer. Such payment is not expected to be material. The closing of the pending sale is subject to regulatory and other third-party approvals and is expected to occur during the first half of Fiscal 2024.

Acquisition of Assets

Stonehenge. On January 27, 2022, UGI, through Energy Services, completed the Stonehenge Acquisition in which Energy Services acquired all of the equity interests in Stonehenge for total cash consideration of approximately $190. The Stonehenge business includes a natural gas gathering system, located in western Pennsylvania, with more than 47 miles of pipeline and associated compression assets. The Stonehenge Acquisition is consistent with our growth strategies, including expanding our midstream natural gas gathering assets within the Appalachian basin production region. The Stonehenge Acquisition was funded using available cash. This transaction has been accounted for as an acquisition of assets, and the purchase price has been primarily allocated to property, plant and equipment. We refer to Stonehenge and its assets as “UGI Moraine East.”

Note 6 — Inventories

Inventories comprise the following:


	June 30, 2023		September 30, 2022		June 30, 2022
Non-utility LPG and natural gas	$	189	$	335	$	261
Gas Utility natural gas	37		166		84
Energy certificates	68		70		70
Materials, supplies and other	116		94		81
Total inventories	$	410	$	665	$	496

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

Note 7 — 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 89 in the Company’s ~~2017~~2022 Annual Report. Other than removal costs, ~~UGI~~ Utilities currently does not recover a rate of return on its regulatory ~~assets.~~assets listed below. The following regulatory assets and liabilities associated with ~~UGI~~ Utilities are included on the Condensed Consolidated Balance Sheets:


	June 30, 2023		September 30, 2022		June 30, 2022
Regulatory assets (a):
Income taxes recoverable	$	95	$	83	$	151
Underfunded pension plans	118		114		103
Environmental costs	28		37		34
Deferred fuel and power costs	30		32		14
Removal costs, net	22		22		22
Other	57		52		47
Total regulatory assets	$	350	$	340	$	371
Regulatory liabilities (a):
Postretirement benefit overcollections	$	10	$	11	$	12

Deferred fuel and power refunds	63		3		1
State tax benefits — distribution system repairs	40		38		34

Excess federal deferred income taxes	260		279		281
Other	3		4		8
Total regulatory liabilities	$	376	$	335	$	336

(a)Current regulatory assets are included in ~~our accompanying condensed consolidated balance sheets:~~“Prepaid expenses and other current assets” and regulatory liabilities are included in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.

December 31,
2017 September 30,
2017 December 31,
2016
Regulatory assets:
Income taxes recoverable $ 126.5
$ 121.4
$ 117.8
Underfunded pension and postretirement plans 138.3
141.3
179.4
Environmental costs 60.8
61.6
61.4
Deferred fuel and power costs 0.1
7.7
—
Removal costs, net 31.4
31.0
27.1
Other 5.7
5.9
7.2
Total regulatory assets $ 362.8
$ 368.9
$ 392.9
Regulatory liabilities (a):
Postretirement benefits $ 17.3
$ 17.5
$ 17.3
Deferred fuel and power refunds 12.7
10.6
23.8
State tax benefits — distribution system repairs 19.1
18.4
15.6
Excess federal deferred income taxes (b) 303.9
—
—
Other 4.5
2.7
2.0
Total regulatory liabilities $ 357.5
$ 49.2
$ 58.7


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


~~(b)~~	~~Balance at December 31, 2017, comprises excess deferred federal income taxes resulting from the enactment of the TCJA (see below and Note 5).~~

Deferred fuel and power ~~refunds.~~ ~~Gas Utility’s~~- costs and ~~Electric Utility’s~~refunds. Utilities’ tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of ~~purchased gas cost (“PGC”)~~PGC rates, ~~in the case of Gas Utility~~PGA rates and ~~default service (“DS”) tariffs in the case of Electric Utility. The~~DS tariffs. These clauses provide for periodic adjustments to PGC, PGA 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.

The WVPSC, in an effort to mitigate the impact of WV Gas Utility’s 2022 PGA rate increase to customers, delayed the effective date in 2022 from November 1 to December 1 and deferred $12 of unrecovered gas costs in determining the rates to be charged to the various customer classes effective December 1, 2022. Additionally, in order to lower winter bills for residential customers, the WVPSC removed transportation and storage costs from the volumetric rate and created a fixed monthly pipeline demand charge applicable only to residential customers. On April 12, 2023, the WVPSC issued a final Order that increased the PGA rate, which included the unrecovered gas cost balance initially deferred in the interim order, and continued the fixed monthly demand charge for residential customers.

PA Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for ~~firm- residential, commercial and industrial (“~~retail ~~core-market”)~~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 ~~December 31, 2017,~~June 30, 2023, September 30, ~~2017~~2022 and ~~December 31, 2016~~June 30, 2022 were ~~$(1.7)~~$(7), ~~$0.1~~$5 and ~~$6.9,~~$7, respectively.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at December 31, 2017, September 30, 2017, and December 31, 2016, were not material.

~~Excess federal deferred income taxes.~~ This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 5). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that these excess federal deferred income taxes be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess federal deferred income taxes,

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~~Table of Contents~~

~~UGI CORPORATION AND SUBSIDIARIES~~

~~Notes to Condensed Consolidated Financial Statements~~

~~(unaudited)~~

~~(Currency in millions, except per share amounts and where indicated otherwise)~~

ranging from 1 year to approximately 65 years. This regulatory liability has been increased to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. This regulatory liability will be amortized and credited to tax expense.

Other Regulatory Matters

On ~~August 31, 2017, the PUC approved~~July 14, 2023, a ~~previously filed~~ Joint Petition for Approval of Settlement of all issues ~~providing for an $11.3 annual base distribution rate increase for PNG. The increase became effective on October 20, 2017.~~

~~On October 14, 2016, the PUC approved a previously~~supported by all active parties was filed ~~Joint Petition for Approval of Settlement of all issues providing for a $27.0 annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016.~~

~~Distribution System Improvement Charge.~~State legislation permits gas and electric utilities in Pennsylvania to recover a distribution system improvement charge (“DSIC”) on eligible capital investments as an alternative ratemaking mechanism providing for a more-timely cost recovery of qualifying capital expenditures between base rate cases.

PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In May 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018. PNG’s DSIC has been reset to zero as a result of its most recent rate case. The DSIC rate for PNG will resume upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its recent base rate case.

In November 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.

~~Note 8 — Energy Services Accounts Receivable Securitization Facility~~

Energy Services, LLC has an accounts receivable securitization facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2018. The Receivables Facility, as amended, provides Energy Services, LLC with the ability to borrow up to $150 of eligible receivables during the period November to April and up to $75 of eligible receivables during the period May to October. Energy Services, LLC uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.

Under the Receivables Facility, Energy Services, LLC transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time, sell an undivided interest in some or all of the receivables to a major bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services, LLC and its affiliates, including UGI. Trade receivables sold to the bank remain on Energy Services LLC’s balance sheet and Energy Services, LLC reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services, LLC continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses on sales of receivables to the bank during the three months ended December 31, 2017 and 2016, which are included in “Interest expense” on the Condensed Consolidated Statements of Income, were not material.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

with the PAPUC providing for a $9 annual base distribution rate increase for Electric Utility. The Joint Petition is subject to receipt of a recommended decision and a final order of the PAPUC approving the settlement. In accordance with the terms of the Joint Petition, the proposed rate increase will become effective on or before October 1, 2023, or as directed by the PAPUC in the final order. The Company cannot predict the timing or the ultimate outcome of the rate case review process.

~~Information regarding~~On January 28, 2022, PA Gas Utility filed a request with the ~~trade receivables transferred~~PAPUC to ~~ESFC~~increase its base operating revenues for residential, commercial and industrial customers by $83 annually. On September 15, 2022, the PAPUC issued a final order approving a settlement providing for a $49 annual base distribution rate increase for PA Gas Utility, through a phased approach, with $38 beginning October 29, 2022 and an additional $11 beginning October 1, 2023. In accordance with the terms of the final order, PA Gas Utility will not be permitted to file a rate case prior to January 1, 2024. Also in accordance with the terms of the final order, PA Gas Utility was authorized to implement a weather normalization adjustment rider as a five-year pilot program beginning on November 1, 2022. Under this rider, when weather deviates from normal by more than 3%, residential and small commercial customer billings for distribution services are adjusted monthly for weather related impacts exceeding the 3% threshold. Additionally, under the terms of the final order, PA Gas Utility was authorized to implement a DSIC once its total property, plant and equipment less accumulated depreciation reached $3,368 (which threshold was achieved in September 2022).

On February 8, 2021, Electric Utility filed a request with the PAPUC to increase its annual base distribution revenues by $9. On October 28, 2021, the PAPUC issued a final Order approving a settlement that permitted Electric Utility, effective November 9, 2021, to increase its base distribution revenues by $6.

Mountaineer. On July 31, 2023, Mountaineer submitted its 2023 IREP filing to the WVPSC requesting recovery of $10 for costs associated with capital investments after December 31, 2022, that total $131, including $67 in calendar year 2024. With new base rates expected to be effective January 1, 2024, revenues from IREP rates would decrease by $12. The filing included capital investments totaling $383 over the 2024 - 2028 period.

On July 28, 2023, Mountaineer submitted its annual PGA filing with the WVPSC. This filing allows the WVPSC to review the prudence of Mountaineer’s incurred gas costs, to review the computation of any over or under collection of gas costs, and to establish a PGA billing rate for the upcoming year. The new PGA billing rate is intended to settle past over or under collections and allows Mountaineer to recover its projected gas costs for the upcoming year.

On March 6, 2023, Mountaineer submitted a base rate case filing with the WVPSC seeking a net revenue increase of $20, which consists of an increase in base rates of $38 and a decrease in the IREP rates of $18 annually to be effective on April 5, 2023. On March 31, 2023, the WVPSC suspended the effective date of the requested rate change increase until January 1, 2024 to allow for a full review of the filing.

On July 29, 2022, Mountaineer submitted its 2022 IREP filing to the WVPSC requesting recovery of costs associated with capital investments totaling $354 over the 2023 - 2027 period, including $64 in calendar year 2023. On November 16, 2022, Mountaineer and the ~~amounts sold~~intervening parties submitted a Joint Stipulation and Agreement for Settlement to the ~~bank~~WVPSC requesting approval of 2023 IREP revenue of $22 to be charged effective January 1, 2023, which includes the recovery of a $1 under-recovery of 2021 IREP revenue. On December 21, 2022, the WVPSC issued an order approving the Joint Stipulation and Agreement for Settlement as filed.

Note 8 — Debt

AmeriGas Partners Senior Notes. On May 31, 2023, AmeriGas Partners and AmeriGas Finance Corp. issued $500 principal amount of 9.375% Senior Notes due May 2028. The 9.375% Senior Notes rank equally with AmeriGas Partners’ existing and future outstanding senior notes. The net proceeds from the issuance of the 9.375% Senior Notes, together with cash on hand, a $150 cash contribution from the Company and other sources of liquidity, were used for the ~~three months ended December 31, 2017~~early repayment, pursuant to a tender offer and ~~2016, as well as the~~notice of redemption, of all AmeriGas Partners 5.625% Senior Notes having an aggregate principal balance of ~~ESFC trade receivables at December 31, 2017, September 30, 2017~~$675, plus tender premiums and ~~December 31, 2016, is as follows:~~

Three Months Ended December 31,
2017 2016
Trade receivables transferred to ESFC during the period $ 270.6
$ 246.4
ESFC trade receivables sold to the bank during the period $ 48.0
$ 66.0

December 31, 2017 September 30, 2017 December 31, 2016
ESFC trade receivables — end of period (a) $ 101.0
$ 44.8
$ 81.4


~~(a)~~	At December 31, 2017, September 30, 2017 and December 31, 2016, the amounts of ESFC trade receivables sold to the bank were $45.0, $39.0, and $35.0, respectively, and are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets.

~~Note 9 — Debt~~

~~AmeriGas Propane.~~accrued and unpaid interest. In ~~December 2017, AmeriGas Partners entered into~~conjunction with the Second Amended and Restated Credit Agreement (“AmeriGas Credit Agreement”) with a group of banks. The AmeriGas Credit Agreement amends and restates a previous credit agreement. The AmeriGas Credit Agreement provides for borrowings up to $600 (including a $150 sublimit for letters of credit) and expires in December 2022. The AmeriGas Credit Agreement permits AmeriGas to borrow at prevailing interest rates, including the base rate, defined as the higherearly repayment of the ~~Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined~~5.625% Senior Notes, in the AmeriGas Credit Agreement, plus a margin. Under the AmeriGas Credit Agreement, the applicable margin on base rate borrowings ranges from 0.50% to 1.75%; the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.75%; and the facility fee ranges from 0.30% to 0.50%. The aforementioned margins and facility fees are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (each as defined in the AmeriGas Credit Agreement).

~~In December 2016,~~June 2023 the Partnership recognized a pre-tax loss of ~~$33.2 in connection with~~$9 primarily comprising tender premiums and the ~~early repayment~~write-off of ~~a portion of AmeriGas Partners’ 7.00% Senior Notes. This loss~~unamortized debt issuance costs, which is reflected in “Loss on extinguishments of debt” on the Condensed Consolidated ~~Statements of Income for the three months ended December 31, 2016.~~

~~UGI International.~~ In December 2017, UGI International, LLC, a wholly owned subsidiary of UGI, entered into a secured multicurrency revolving facility agreement (the "UGI International Credit Agreement") with a group of banks providing for borrowings up to €300. The UGI International Credit Agreement is scheduled to expire in April 2020. Under the UGI International Credit Agreement, UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus a margin ranging from 1.45% to 2.35%. Loans made in U.S. dollars will bear interest at LIBOR plus a margin ranging from 1.70% to 2.60%. The aforementioned margins are dependent upon certain indebtedness at UGI International, LLC. The UGI International Credit Agreement requires UGI International, LLC not to exceed a ratio of total indebtedness to EBITDA, as defined, of 3.50 to 1.00.

Also in December 2017, Flaga repaid $9.2 of the outstanding principal amount of its then-existing $59.1 U.S. dollar denominated variable-rate term loan due September 2018. Concurrently, Flaga entered into an amendment to the aforementioned term loan, which amends and restates the previous agreement to provide for a principal balance of $49.9 and extends the maturity of the term loan to April 2020 (“Flaga Term Loan”). The outstanding principal bears interest at the one-month LIBOR rate plus a margin of 1.125%. Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the Flaga Term Loan, by entering into a cross-currency swap arrangement with a bank. Because a portion of the cash flows related to the Flaga Term Loan were with the same bank, such cash flows have been reflected “net” in the financing activities section of the Condensed Consolidated Statement of ~~Cash Flows.~~Income.

~~UGI Utilities.~~In October 2017, UGI Utilities entered into a $125 unsecured variable-rate term loan agreement (the “Utilities Term Loan”) with a group of banks which initially matures on October 30, 2018. Such maturity will be automatically extended to

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

The 9.375% Senior Notes are redeemable at the issuers’ option prior to June 2025 at a make whole premium or, on or after June 2025, at a call premium that declines from 4.688% to 0% depending on the year of redemption.

The 9.375% Senior Notes indenture contains customary covenants and default provisions that limit AmeriGas Partners’ ability to, among other things: incur additional indebtedness; create or incur liens; engage in transactions with affiliates; engage in mergers or consolidations or sell all or substantially all of the issuers’ assets; make restricted payments, loans and investments; enter into business combinations and sell assets; and engage in other lines of business.

2022 AmeriGas OLP Credit Agreement.Under the 2022 AmeriGas OLP Credit Agreement, AmeriGas OLP, as borrower, is required to comply with financial covenants related to leverage and interest coverage measured at the Partnership and at AmeriGas OLP. The 2022 AmeriGas OLP Credit Agreement contains an equity cure provision, which allows AmeriGas OLP’s direct or indirect parent, including UGI and its other subsidiaries, to fund capital contributions to eliminate any EBITDA (as defined in the 2022 AmeriGas OLP Credit Agreement) shortfalls that would otherwise result in non-compliance with these financial covenants. Each equity cure is eligible to eliminate such EBITDA shortfalls up to four quarters after contribution. We are permitted to use the equity cure provision five times over the course of the Credit Agreement, twice during any rolling four-quarter period, and not in consecutive quarters.

As of March 31, 2023, AmeriGas OLP was in breach of the leverage ratio debt covenant and interest coverage ratio, which it cured with the funds received from UGI. UGI made capital contributions to AmeriGas OLP of $20 and $11 on March 31, 2023 and April 24, 2023, respectively, which in aggregate represented one equity cure in accordance with the 2022 AmeriGas OLP Credit Agreement. As a result of these capital contributions, AmeriGas OLP and the Partnership were in compliance with all financial covenants after consideration of the equity cure provision as of June 30, 2023 and March 31, 2023.

UGI also provided an irrevocable letter of support whereby UGI has committed to fund any such EBITDA shortfalls and debt service, if any. Based on the support and the projected EBITDA, AmeriGas OLP is expected to remain in compliance with its financial debt covenants for the succeeding twelve-month period. In addition, in May 2023, the Company contributed $52 in an equity contribution principally to fund debt service on the senior notes.

UGI International 2023 Credit Facilities Agreement. On March 7, 2023, UGI International, LLC and its indirect wholly-owned subsidiary, UGI International Holdings B.V., entered into the UGI International 2023 Credit Facilities Agreement, a five-year unsecured senior facilities agreement, maturing March 7, 2028, with a consortium of banks. The UGI International 2023 Credit Facilities Agreement consists of (1) a €300 variable-rate term loan facility ("Facility A") and (2) a €500 multicurrency revolving credit facility, including a €100 sublimit for swingline loans ("Facility B"). We have designated borrowings under Facility A as a net investment hedge. In connection with the entering into of the UGI International 2023 Credit Facilities Agreement, UGI International, LLC paid off in full and terminated the UGI International Credit Facilities Agreement, dated as of October ~~30, 2022, after UGI Utilities receives a securities certificate~~18, 2018. The net proceeds from the ~~PUC authorizing issuance of the security and upon delivery of such certificate to the agent. Proceeds from the Utilities Term Loan~~UGI International 2023 Credit Facilities Agreement were used to ~~repay~~refinance the UGI International Credit Facilities Agreement. Borrowings under the multicurrency revolving credit ~~balances~~facility may be used to finance the working capital needs of UGI International, LLC and its subsidiaries and for general corporate purposes.

Borrowings under Facility A bear interest at the euro interbank offered rate plus the applicable margin and borrowings under Facility B bear interest at the daily non-cumulative compounded Reference Rate Terms, as defined in the Agreement, plus the applicable margin. The applicable margin for Facility A ranges from 1.70% to 3.35%, and for Facility B from 1.35% to 3.35%, and are dependent on the total net leverage ratio of UGI International, LLC and its subsidiaries on a consolidated basis. UGI International, LLC entered into an interest rate swap, effective March 31, 2023, that fixes the underlying market-based interest rate on Facility A at 3.10% through March 2026.

The UGI International 2023 Credit Facilities Agreement requires UGI International, LLC to maintain a consolidated net leverage ratio of not more than 3.85 to 1.00, provided the maximum ratio permitted may be increased to 4.25 to 1.00 for two consecutive testing dates following a permitted acquisition.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

Credit Agreement shall bear interest at a floating rate of, at Energy Services’ option, either (i) Term SOFR plus the Applicable Rate (as defined in the UGI Energy Services Credit Agreement) plus a credit spread adjustment of 0.10%, or (ii) the base rate plus the applicable margin that is based on the leverage of Energy Services.

Energy Services Amended Term Loan Credit Agreement. On February 23, 2023, Energy Services entered into the Energy Services Amended Term Loan Credit Agreement, the first amendment to the Energy Services Term Loan Credit Agreement, dated August 13, 2019. The Energy Services Amended Term Loan Credit Agreement provides, among other items, that (i) the outstanding principal amount of the ~~Utilities~~loans will be increased by $125 to $800, (ii) the maturity date of the loans shall be extended to February 22, 2030, (iii) Term SOFR (as defined in the Energy Services Amended Term Loan isCredit Agreement) shall replace LIBOR as a reference rate and (iv) borrowings under the Energy Services Amended Term Loan Credit Agreement shall bear interest at a floating rate of, at Energy Services’ option, either (x) Term SOFR plus the applicable margin plus a credit spread adjustment of 0.10% or (y) the base rate, as defined in the Agreement, plus the applicable margin. The applicable margin shall be 3.25% per annum for Term SOFR loans and 2.25% per annum for base rate loans. Borrowings under the Energy Services Amended Term Loan Credit Agreement are payable in equal quarterly installments of ~~$1.6~~$2, commencing in March 2023, with the balance of the principal being due and payable in full at maturity.

The Energy Services Amended Term Loan Credit Agreement contains customary covenants and default provisions and requires compliance with certain financial covenants including a minimum debt service coverage ratio as defined in the Agreement.

On March 1, 2023, in connection with the Energy Services Amended Term Loan Credit Agreement, Energy Services terminated and settled its existing interest rate swap derivative instrument associated with the Energy Services Term Loan Credit Agreement at a $32 gain. This gain has been deferred in AOCI and is being amortized to interest expense over the remaining term of the initial interest rate swap ending July 2024. Energy Services entered into a new interest rate swap, effective March 31, 2023, that fixes the underlying market-based interest rate on this variable-rate term loan at 4.53% through September 2026.

UGI Utilities Credit Agreement. On December 13, 2022, UGI Utilities entered into an amendment to the UGI Utilities Credit Agreement, providing for borrowings up to $425 and to replace the use of LIBOR with Term SOFR. Borrowings under the amended UGI Utilities Credit Agreement can be used to finance the working capital needs of UGI Utilities and for general corporate purposes. The UGI Utilities Credit Agreement is scheduled to expire June 2024.

Borrowings under the amended UGI Utilities Credit Agreement bear interest, subject to our election, at a floating rate of either (i) Term SOFR plus the applicable margin plus a credit spread adjustment of 0.10% or (ii) the base rate plus the applicable margin. The applicable margin remains unchanged from the original credit agreement.

Mountaineer Credit Agreement. On October 20, 2022, Mountaineer entered into the Mountaineer 2023 Credit Agreement, with a group of lenders. The Mountaineer 2023 Credit Agreement amends and restates a previous credit agreement and provides for borrowings up to $150, including a $20 sublimit for letters of credit. Mountaineer may request an increase in the amount of loan commitments to a maximum aggregate amount of $250, subject to certain terms and conditions. Borrowings under the Mountaineer 2023 Credit Agreement can be used to finance the working capital needs of Mountaineer and for general corporate purposes. The Mountaineer 2023 Credit Agreement is scheduled to expire in November 2024, with an option to extend the maturity date. ~~Under~~

Borrowings under the ~~Utilities Term Loan, UGI Utilities may borrow~~Mountaineer 2023 Credit Agreement bear interest, subject to our election, at ~~various prevailing market interest rates, including LIBOR and~~either (i) the ~~banks’~~base rate, defined as the highest of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the adjusted Term SOFR rate for a one-month tenor plus 1%, in each case, plus the applicable margin or (ii) the adjusted Term SOFR rate plus the applicable margin. The applicable margin for base rate loans ranges from 0% to 1.25%, and for Term SOFR loans from 1.00% to 2.25%, depending on the debt rating of Mountaineer. The adjusted Term SOFR rate is defined as the Term SOFR reference rate for the selected interest period, plus 0.10% per annum for a one-month interest period, 0.15% per annum for a three-month interest period, or 0.25% per annum for a six-month interest period. The Mountaineer Credit Agreement contains customary covenants and default provisions and requires compliance with certain financial covenants including a maximum leverage ratio and a minimum interest coverage ratio as defined in the agreement.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

UGI Corporation Credit Agreement. On May 12, 2023, the Company entered into the second amendment to the UGI Corporation Credit Agreement, which provides that the Term SOFR rate (as defined in the UGI Corporation Credit Agreement) shall replace LIBOR as a reference rate. After giving effect to the second amendment, the UGI Corporation Credit Agreement shall bear interest at a floating rate of, at the Company’s option, either (i) Term SOFR plus the Applicable Rate (as defined in the UGI Corporation Credit Agreement) plus a ~~margin. The~~credit spread adjustment of 0.10%, or (ii) the base rate plus the applicable margin that will be based on ~~such borrowings ranges from 0.0% to 1.875% and is based upon~~ the leverage of the Company or credit ratings ofassigned to certain indebtedness of ~~UGI Utilities.~~ the Company.

The Utilities Term Loan requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. Because UGI Utilities has not yet received a securities certificate fromCompany is pursuing the ~~PUC authorizing the extension~~refinancing of the UGI Corporation revolving credit facility, which matures August 1, 2024. The UGI Corporation revolving credit facility contains a leverage ratio debt covenant which the Company was in compliance with as of June 30, 2023, and expects to maintain compliance through the August 1, 2024 maturity ~~date~~date. The Company has other sources of liquidity currently available which would be sufficient to ~~October 30, 2022,~~repay the ~~Utilities Term Loan has been reflected in “Current maturities of long-term debt” on the December 31, 2017, Condensed Consolidated Balance Sheet.~~maturing credit facility should a refinancing not be successful.

Note 109 — Commitments and Contingencies

~~UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units~~

On November 7, 2017, UGI entered into a Standby Equity Commitment Agreement (the “Commitment Agreement”) with AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make up to $225 of capital contributions to the Partnership through July 1, 2019 (the “Commitment Period”). UGI’s capital contributions may be made from time to time during the Commitment Period upon request of the Partnership. There have been no capital contributions made to the Partnership under the Commitment Agreement.

In consideration for any capital contributions made pursuant to the Commitment Agreement, the Partnership will issue to UGI or a wholly owned subsidiary new Class B Common Units representing limited partner interests in the Partnership (“Class B Units”). The Class B Units will be issued at a price per unit equal to the 20-day volume-weighted average price of AmeriGas Partners Common Units prior to the date of the Partnership’s related capital call. The Class B Units will be entitled to cumulative quarterly distributions at a rate equal to the annualized Common Unit yield at the time of the applicable capital call, plus 130 basis points. The Partnership may choose to make the distributions in cash or in the form of additional Class B Units. While outstanding, the Class B Units will not be subject to any incentive distributions from the Partnership.

At any time after five years from the initial issuance of the Class B Units, holders may elect to convert all or any portion of the Class B Units they own into Common Units on a one-for-one basis, and at any time after six years from the initial issuance of the Class B Units, the Partnership may elect to convert all or any portion of the Class B Units into Common Units if (i) the closing trading price of the Common Units is greater than 110% of the applicable purchase price for the Class B Units and (ii) the Common Units are listed or admitted for trading on a National Securities Exchange. Upon certain events involving a change of control and immediately prior to a liquidation or winding up of the Partnership, the Class B Units will automatically convert into Common Units on a one-for-one basis.

Environmental Matters

UGI Utilities

From the late 1800s through the mid-1900s, UGI Utilities and its ~~current and~~ former subsidiaries owned and operated a number of ~~manufactured gas plants (“MGPs”)~~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 ~~Pennsylvania operations, including those which now constitute UGI Gas~~gas and ~~Electric Utility.~~electric operations. Beginning in 2006 and 2008, UGI Utilities also ~~has~~owned and operated two acquired subsidiaries, ~~(CPG and PNG)~~ with similar histories of owning, and in some cases operating, MGPs in Pennsylvania.

~~Each of~~ UGI Utilities ~~and its subsidiaries, CPG and PNG, has entered into~~is subject to a ~~consent order and agreement (“COA”)~~COA with the ~~Pennsylvania Department of Environmental Protection (“DEP”)~~PADEP to address the remediation of specified former ~~MGPs~~MGP sites in ~~Pennsylvania.~~Pennsylvania, which is scheduled to terminate at the end of 2031. In accordance with the ~~COAs,~~COA, UGI Utilities ~~CPG and PNG are each~~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, or make expenditures for such activities in an amount equal to an annual environmental ~~cost cap.~~minimum expenditure threshold. The ~~CPG~~annual minimum expenditure threshold of the COA ~~includes an obligation to plug specified natural~~

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~~UGI CORPORATION AND SUBSIDIARIES~~

~~Notes to Condensed Consolidated Financial Statements~~

~~(unaudited)~~

~~(Currency in millions, except per share amounts and where indicated otherwise)~~

gas wells. The COA environmental costs caps are $2.5, $1.8, and $1.1, for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively.is $5. At ~~December 31, 2017,~~June 30, 2023, September 30, ~~2017~~2022 and ~~December 31, 2016,~~June 30, 2022, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the ~~COAs for UGI Utilities, CPG~~COA totaled $52, $53 and ~~PNG totaled $53.4, $54.3 and $55.3,~~$51, respectively. ~~UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 7).~~

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 ~~CPG and PNG receive~~receives ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the ~~COAs.~~COA. 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 7).

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. ~~At December 31, 2017, September 30, 2017 and December 31, 2016, neither~~Neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania were material for all periods presented.

Table of ~~Pennsylvania was material.~~Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

AmeriGas Propane

AmeriGas OLP Saranac Lake. ~~By letter dated March 6,~~In 2008, the ~~New York State Department of Environmental Conservation (“DEC”)~~NYDEC notified AmeriGas OLP that the ~~DEC~~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 ~~DEC~~NYDEC disclosed contamination related to a former MGP. ~~At that time,~~ AmeriGas OLP ~~reviewed the study and researched the history of the site, including the extent of AmeriGas OLP’s ownership. In its written response~~responded to the ~~DEC~~NYDEC in ~~early~~ 2009 ~~AmeriGas OLP disputed DEC’s~~to dispute the contention it was a ~~potentially responsible party (“PRP”)~~PRP as it did not operate the MGP and appeared to only own a portion of the site. ~~The DEC did not respond to the 2009 communication.~~ In ~~March~~ 2017, the ~~DEC~~NYDEC communicated to AmeriGas OLP that the ~~DEC~~NYDEC had previously issued three ~~Records of Decision (“RODs”)~~RODs related to remediation of the site totaling approximately $28 and requested additional information regarding AmeriGas OLP’s purported ownership. The selected remedies identified in the RODs total approximately $27.7. To AmeriGas OLP’s knowledge, the DEC has not yet commenced implementation of the remediation plan but remediation is currently expected to commence in 2018. AmeriGas OLP ~~responded to the DEC’s March 2017 request for ownership information, renewing~~renewed its challenge to designation as a PRP and ~~identifying~~identified potential defenses. ~~In October 2017, the DEC~~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 ~~during the third quarter~~as of ~~Fiscal 2017,~~June 30, 2023, the Partnership ~~accrued~~has an undiscounted environmental remediation liability of ~~$7.5~~$8 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~~West Reading, Pennsylvania Explosion. On March 24, 2023, an explosion occurred in West Reading, Pennsylvania which resulted in seven fatalities, significant injuries to eleven others, and ~~October of 2014, more than 35 purported class action lawsuits were filed~~extensive property damage to buildings owned by R.M. Palmer, a local chocolate manufacturer, and other neighboring structures. The NTSB, OSHA and the PAPUC are investigating the West Reading incident. On July 18, 2023, the NTSB issued an Investigative Update in ~~multiple jurisdictions against the Partnership/~~its ongoing investigation. That report identifies a fracture in a retired UGI gas service tee 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~~fracture 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 behalfa nearby steam system, but it does not address causation of the ~~putative classes.~~ fractures or the explosion. The NTSB investigative team includes representatives from the Company, the PAPUC, the local fire department and the Pipeline and Hazardous Materials Safety Administration. The Company is cooperating with the investigation. The NTSB may invite other parties to participate.

~~On October 16, 2014,~~While the ~~United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to~~investigation into this incident is still underway and the ~~Western Division~~cause of the ~~United States District Court for~~explosion has not been determined, the ~~Western District of Missouri (“District Court”). In July 2015, the District Court dismissed all~~Company has received claims brought by direct customers. In June 2017, the United States Court of Appeals for the Eighth Circuit (“Eighth Circuit”) ruled en banc to reverse the dismissal by the District Court, which had previously been

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~~UGI CORPORATION AND SUBSIDIARIES~~

~~Notes to Condensed Consolidated Financial Statements~~

~~(unaudited)~~

~~(Currency in millions, except per share amounts and where indicated otherwise)~~

affirmed by a panel of the Eighth Circuit. In September 2017, we filed a Petition for a Writ of Certiorari to the U.S. Supreme Court appealing the decision of the Eighth Circuit. The petition was denied in January 2018 and, as a result of the ~~case was transferred back~~explosion and is involved in lawsuits relative to the ~~District Court~~incident. The Company maintains liability insurance for ~~further proceedings.~~

~~In July 2015, the District Court also dismissed all~~personal injury, property and casualty damages and believes that third-party claims ~~brought by the indirect customers other than those for injunctive relief. The indirect customers filed an amended complaint~~associated with the ~~District Court claiming injunctive relief and state law claims under Wisconsin, Maine and Vermont law. In September 2016, the District Court dismissed the amended complaint~~explosion, in ~~its entirety. The indirect customers appealed this decision to the Eighth Circuit; such appeal was subject to a stay pending the en banc review~~excess of the ~~direct purchasers’ claims. In light~~Company’s deductible, are recoverable through the Company’s insurance. The Company cannot predict the result of the Eighth Circuit decision with respect to the direct purchaser claims, the briefing schedule in respect of the indirect purchaser appeal will now resume. On July 21, 2016, several new indirect customer plaintiffs filed an antitrust class action lawsuit against the Partnership in the Western District of Missouri. The new indirect customer class action lawsuit was dismissed in September 2016 and certain indirect customer plaintiffs appealed the decision, consolidating their appeal with the indirect customer appeal stillthese pending ~~in the Eighth Circuit. Now that the Eighth Circuit has ruled on the direct purchasers’ claims, the stay has been lifted for the indirect~~or future claims and ~~the parties submitted briefs in October 2017 to the Eighth Circuit and are awaiting the court’s ruling.~~legal actions at this time.

~~We are unable to reasonably estimate the impact, if any, arising from such litigation. We believe we have strong defenses to the claims and intend to vigorously defend against them.~~

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, including those described above, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial statements.

Note 1110 — Defined Benefit Pension and Other Postretirement Plans

~~In the U.S., we sponsor a~~The Company maintains defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, employees of UGI France SAS and its subsidiaries are covered by certain defined benefit pension and postretirement plans.

~~Net periodic pension expense~~plans and other postretirement plans for certain current and former employees. 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 components, net of amounts capitalized by Utilities as a regulatory asset, are reflected in “Other non-operating income (expense), net” on the Condensed Consolidated Statements of Income. Other postretirement benefit ~~costs include the following components:~~cost was not material for all periods presented.

Pension Benefits Other Postretirement Benefits
Three Months Ended December 31, 2017 2016 2017 2016
Service cost $ 2.8
$ 3.0
$ 0.2
$ 0.2
Interest cost 6.5
6.2
0.2
0.2
Expected return on assets (8.6 ) (8.3 ) (0.2 ) (0.2 )
Amortization of:
Prior service cost (benefit) 0.1
0.1
(0.1 ) (0.1 )
Actuarial loss 3.3
4.1
0.1
0.1
Net benefit cost 4.1
5.1
0.2
0.2
Change in associated regulatory liabilities —
—
(0.1 ) (0.1 )
Net benefit cost after change in regulatory liabilities $ 4.1
$ 5.1
$ 0.1
$ 0.1

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 three months ended December 31, 2017 and 2016, the Company made cash contributions to the U.S. Pension Plan of $3.4 and $2.8, respectively. The Company expects to make additional discretionary cash contributions of approximately $10.1 to the U.S. Pension Plan during the remainder of Fiscal 2018.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“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. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the three months ended December 31, 2017 and 2016.

~~We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans.~~ Net periodic ~~costs associated with these plans for~~pension benefit includes the ~~three months ended December 31, 2017 and 2016, were not material.~~following components:



	Pension Benefits
Three Months Ended June 30,	2023		2022
Service cost	$	2	$	4
Interest cost	9		6
Expected return on assets	(11)		(12)

Amortization of:

Actuarial (gain) loss	(1)		2
Net benefit	$	(1)	$	—



Nine Months Ended June 30,	2023		2022
Service cost	$	7	$	12
Interest cost	26		19
Expected return on plan assets	(34)		(37)

Amortization of:

Actuarial (gain) loss	(2)		6
Net benefit	$	(3)	$	—

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

Note 1211 — 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,~~hierarchy:


	Asset (Liability)
	Level 1		Level 2		Level 3		Total
June 30, 2023:
Derivative instruments:
Assets:
Commodity contracts (c)	$	146	$	111	$	—	$	257
Foreign currency contracts	$	—	$	18	$	—	$	18
Interest rate contracts	$	—	$	30	$	—	$	30

Liabilities:
Commodity contracts (c)	$	(242)	$	(224)	$	—	$	(466)
Foreign currency contracts	$	—	$	(4)	$	—	$	(4)
Interest rate contracts	$	—	$	(4)	$	—	$	(4)

Non-qualified supplemental postretirement grantor trust investments (a)	$	40	$	—	$	—	$	40
September 30, 2022:
Derivative instruments:
Assets:
Commodity contracts (b)	$	938	$	1,268	$	27	$	2,233
Foreign currency contracts	$	—	$	119	$	—	$	119
Interest rate contracts	$	—	$	66	$	—	$	66

Liabilities:
Commodity contracts (b)	$	(377)	$	(136)	$	—	$	(513)
Foreign currency contracts	$	—	$	(2)	$	—	$	(2)


Non-qualified supplemental postretirement grantor trust investments (a)	$	43	$	—	$	—	$	43
June 30, 2022:
Derivative instruments:
Assets:
Commodity contracts	$	816	$	1,149	$	—	$	1,965
Foreign currency contracts	$	—	$	59	$	—	$	59
Interest rate contracts	$	—	$	44	$	—	$	44

Liabilities:
Commodity contracts	$	(324)	$	(37)	$	—	$	(361)
Foreign currency contracts	$	—	$	(2)	$	—	$	(2)


Non-qualified supplemental postretirement grantor trust investments (a)	$	46	$	—	$	—	$	46

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

(b)Includes derivative assets and liabilities associated with the October 2022 sale of the U.K. energy marketing business classified as ~~of December 31, 2017, September 30, 2017~~held for sale (see Note 5).

(c)Includes derivative assets and ~~December 31, 2016:~~ liabilities associated with certain UGI International energy marketing businesses classified as held for sale (see Note 5).

Asset (Liability)
Level 1 Level 2 Level 3 Total
December 31, 2017:
Derivative instruments:
Assets:
Commodity contracts $ 47.9
$ 71.7
$ —
$ 119.6
Foreign currency contracts $ —
$ 11.6
$ —
$ 11.6
Liabilities:
Commodity contracts $ (31.0 ) $ (13.5 ) $ —
$ (44.5 )
Foreign currency contracts $ —
$ (39.9 ) $ —
$ (39.9 )
Interest rate contracts $ —
$ (2.1 ) $ —
$ (2.1 )
Cross-currency contracts $ —
$ (0.9 ) $ —
$ (0.9 )
Non-qualified supplemental postretirement grantor trust investments (a) $ 37.7
$ —
$ —
$ 37.7
September 30, 2017:
Derivative instruments:
Assets:
Commodity contracts $ 27.2
$ 76.9
$ —
$ 104.1
Foreign currency contracts $ —
$ 12.2
$ —
$ 12.2
Liabilities:
Commodity contracts $ (27.7 ) $ (11.4 ) $ —
$ (39.1 )
Foreign currency contracts $ —
$ (38.2 ) $ —
$ (38.2 )
Interest rate contracts $ —
$ (2.3 ) $ —
$ (2.3 )
Cross-currency contracts $ —
$ (2.9 ) $ —
$ (2.9 )
Non-qualified supplemental postretirement grantor trust investments (a) $ 35.6
$ —
$ —
$ 35.6
December 31, 2016:
Derivative instruments:
Assets:
Commodity contracts $ 62.7
$ 61.8
$ —
$ 124.5
Foreign currency contracts $ —
$ 26.0
$ —
$ 26.0
Cross-currency contracts $ —
$ 3.5
$ —
$ 3.5
Liabilities:
Commodity contracts $ (53.1 ) $ (12.4 ) $ —
$ (65.5 )
Foreign currency contracts $ —
$ (0.2 ) $ —
$ (0.2 )
Interest rate contracts $ —
$ (2.8 ) $ —
$ (2.8 )
Non-qualified supplemental postretirement grantor trust investments (a) $ 34.2
$ —
$ —
$ 34.2

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

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

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~~Substantially all of ~~our~~the remaining derivative instruments are designated as Level 2. The fair values of certain non-exchange-traded commodity derivatives

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~~UGI CORPORATION AND SUBSIDIARIES~~

~~Notes to Condensed Consolidated Financial Statements~~

~~(unaudited)~~

~~(Currency in millions, except per share amounts and where indicated otherwise)~~

designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 that are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts and foreign currency ~~contracts and cross-currency~~ contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of our Level 3 natural gas commodity contracts at September 30, 2022 attributable to our UGI International operations have been determined using unobservable inputs in an illiquid market and ranged from $7 to $27 given the available inputs considered. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. ~~There were no transfers between Level 1 and Level~~

Nonrecurring Fair Value Measurements

During the quarter ended June 30, 2023, the Company performed an interim goodwill impairment test for its AmeriGas Propane reporting unit, which resulted in a non-cash pre-tax goodwill impairment charge of $656 to reduce the carrying value of AmeriGas Propane to its fair value as of May 31, 2023. See Note 2 ~~during~~for further information on the ~~periods presented.~~results of the impairment test including the key assumptions used to determine the fair value of the AmeriGas Propane reporting unit.

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 ~~amount~~amounts and estimated fair ~~value~~values of our long-term debt (including current maturities but excluding unamortized debt issuance costs) ~~at December 31, 2017, September 30, 2017 and December 31, 2016~~ were as follows:


	June 30, 2023		September 30, 2022		June 30, 2022
Carrying amount	$	6,682	$	6,665	$	6,483
Estimated fair value	$	6,318	$	6,189	$	6,145

December 31, 2017 September 30, 2017 December 31, 2016
Carrying amount $ 4,319.5
$ 4,211.9
$ 4,083.8
Estimated fair value $ 4,430.0
$ 4,346.8
$ 4,171.0

Financial instruments other than derivative instruments, such as short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk arising from concentrations of trade accounts receivable is limited because we have a large customer base that extends across many different U.S. markets and a number of foreign countries. For information regarding concentrations of credit risk associated with our derivative instruments, see Note 13. Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value.12.

Note 1312 — 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~~manage: (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 information on the accounting for our derivative instruments, see Note 2.

The following sections summarize the types of derivative instruments used by the Company to manage these market risks.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

Commodity Price Risk

Regulated Utility Operations

Natural Gas

PA Gas Utility’s tariffs contain clauses that permit recovery of all ~~of the~~ prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge ~~PGC.~~purchased gas costs. As permitted and agreed to by the ~~PUC~~PAPUC pursuant to PA Gas Utility’s annual PGC filings, PA Gas Utility currently uses ~~New York Mercantile Exchange (“NYMEX”)~~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~~See Note 7 for further information 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 7).~~regulatory accounting treatment for these derivative instruments.

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~~UGI CORPORATION AND SUBSIDIARIES~~

~~Notes to Condensed Consolidated Financial Statements~~

~~(unaudited)~~

~~(Currency in millions, except per share amounts and where indicated otherwise)~~

~~Electricity~~

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At December 31, 2017, September 30, 2017 and December 31, 2016, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs 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 DS mechanism (see Note 7).

Non-utility Operations

LPG

In order to manage market price risk associated with the ~~Partnerships’~~Partnership’s fixed-price programs and to reduce the effects of short-term commodity price volatility, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, ~~AmeriGas Partners, certain other domestic businesses~~the Partnership and our UGI International operations also use over-the-counter price swap and option 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 and put option agreements to reduce the effects of short-term commodity price volatility. Also, Midstream & Marketing 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 ~~forward contracts~~over-the-counter and ~~Intercontinental Exchange (“ICE”)~~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 ~~associated with~~derived from the purchase and anticipated later near-term sale of natural ~~gas.~~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 a substantial portion of anticipated volumes under 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. From time to time, Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. 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

~~UGI France SAS’ and Flaga’s~~Certain of our long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. ~~UGI France SAS and Flaga have each entered~~In order to fix the underlying short-term market interest rates, we may enter into pay-fixed, receive-variable interest rate swap agreements ~~to hedge the underlying euribor rates~~ and ~~LIBOR rates~~designate such swaps as cash flow hedges.

The remainder of ~~interest on their variable-rate term loans.~~

~~Our domestic businesses’~~our long-term debt is typically issued at fixed rates of interest. As ~~these~~this long-term debt ~~issues mature,~~matures, 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 ~~interest rate protection agreements (“IRPAs”).~~IRPAs. We account for ~~interest rate swaps and~~ IRPAs as cash flow hedges. There were no unsettled IRPAs during any of the periods presented. At June 30, 2023, the amount of pre-tax net gains associated with interest rate hedges expected to be reclassified into earnings during the next twelve months is $49.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

At December 31, 2017, the amount of 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 exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we 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. We account for these foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At December 31, 2017, the amount of net losses associated with currency rate risk expected to be reclassified into earnings during the next twelve months based upon current fair values is $3.2.

~~Beginning October 1, 2016, 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~~USD exchange rate ~~between~~to the euro and British pound sterling, we ~~have entered~~enter into forward foreign currency exchange contracts. ~~The fair value of these forward foreign currency contracts are recorded as assets or liabilities on the condensed consolidated balance sheets. Changes~~We layer in ~~the fair value of~~ these foreign currency exchange contracts over multi-year periods to eventually equal approximately 90% of anticipated UGI International foreign 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 ~~“Losses on foreign currency contracts, net”~~“Other non-operating income (expense), net,” on the Condensed Consolidated Statements of Income.

Net Investment Hedges

From time to time, we also enter into certain forward foreign currency exchange contracts to reduce the volatility of the ~~U.S. dollar~~USD value of a portion of our UGI International euro-denominated net ~~investments.~~investments, including anticipated foreign currency denominated dividends. We account for these foreign currency exchange contracts as net investment hedges and all changes in the fair value of these contracts are reported in the cumulative translation adjustment component in AOCI. We use the spot rate method to measure ineffectiveness of our net investment hedges. At

Concurrent with the repayment of UGI International’s 3.25% Senior Notes on December ~~31, 2017 and 2016, there were no unsettled~~7, 2021, we settled an associated net investment hedge having a notional value of €93. Additionally, in May 2022, we restructured certain net investment hedges ~~outstanding.~~

~~Cross-currency Swaps~~

~~From time to time, Flaga enters into cross-currency swaps to hedge its exposure to the variability~~associated with anticipated foreign currency denominated dividends. Cash flows from these settlements are included in ~~expected future~~ cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows.

Our euro-denominated long-term debt has also been designated as net investment hedges, representing a portion of our UGI International euro-denominated net investment. We recognized pre-tax (losses) gains associated with these net investment hedges in the ~~foreign currency~~cumulative translation adjustment component in AOCI of $(7) and interest rate risk of U.S. dollar-denominated debt. These cross-currency hedges include initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also include interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designate these cross-currency swaps as cash flow hedges.

~~At December 31, 2017, the amount of net losses associated with such cross-currency swaps expected to be reclassified into earnings~~$41 during the ~~next twelve~~three months ~~is not material.~~

ended June 30, 2023 and 2022, respectively, and $(80) and $75 during the nine months ended June 30, 2023 and 2022, respectively.

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Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

Quantitative Disclosures Related to Derivative Instruments

The following table summarizes by derivative type the gross notional amounts related to open derivative contracts ~~as of December 31, 2017,~~at June 30, 2023, September 30, ~~2017~~2022 and ~~December 31, 2016,~~June 30, 2022, and the final settlement ~~date~~dates of the Company's open derivative ~~transactions~~contracts as of ~~December 31, 2017,~~June 30, 2023, but excluding those derivatives that qualified for the NPNS exception:


			Notional Amounts (in millions)
Type	Units	Settlements Extending Through	June 30, 2023		September 30, 2022		June 30, 2022
Commodity Price Risk:
Regulated Utility Operations
PA Gas Utility NYMEX natural gas futures and option contracts	Dekatherms	February 2024	24		19		13


Non-utility Operations
LPG swaps	Gallons	September 2025	734		874		669
Natural gas futures, forward, basis swap, options and pipeline contracts (a)	Dekatherms	October 2027	357		363		353




Electricity forward and futures contracts	Kilowatt hours	December 2026	1,586		2,446		2,621

Interest Rate Risk:
Interest rate swaps	Euro	March 2026	€	300	€	300	€	300
Interest rate swaps	USD	September 2026	$	1,274	$	1,358	$	1,411

Foreign Currency Exchange Rate Risk:
Forward foreign currency exchange contracts	USD	September 2026	$	434	$	465	$	435
Net investment hedge forward foreign exchange contracts	Euro	December 2026	€	256	€	411	€	411

Notional Amounts
(in millions)
Type Units Settlements Extending Through December 31, 2017 September 30, 2017 December 31, 2016
Commodity Price Risk:
Regulated Utility Operations
Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2018 13.4
14.8
11.7
FTRs contracts Kilowatt hours May 2018 63.1
101.2
36.2
Non-utility Operations
LPG swaps & options Gallons December 2020 275.4
325.5
325.9
Natural gas futures, forward and pipeline contracts (a) Dekatherms December 2021 128.3
75.9
70.2
Natural gas basis swap contracts Dekatherms March 2022 90.2
104.2
120.1
NYMEX natural gas storage Dekatherms March 2019 1.3
1.9
1.3
NYMEX propane storage Gallons March 2018 0.1
0.3
—
Electricity long forward and futures contracts (a) Kilowatt hours May 2021 4,733.9
4,440.3
685.5
Electricity short forward and futures contracts Kilowatt hours May 2021 325.2
447.0
352.5
Interest Rate Risk:
Interest rate swaps Euro October 2020 € 645.8
€ 645.8
€ 645.8
Foreign Currency Exchange Rate Risk:
Forward foreign currency exchange contracts USD August 2021 $ 485.7
$ 424.8
$ 416.7
Cross-currency contracts USD April 2020 $ 49.9
$ 59.1
$ 59.1
(a)Amounts at June 30, 2023 and September 30, 2022 include contracts associated with certain UGI International energy marketing businesses classified as held for sale (see Note 5).


~~(a)~~	~~Amounts at December 31, 2017 and September 30, 2017, include derivative contracts held by DVEP which was acquired on August 31, 2017.~~

Derivative Instrument Credit Risk

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~~

We have concentrations of credit risk associated with derivative instruments and we evaluate the creditworthiness of our derivative counterparties on an ongoing basis. As of June 30, 2023, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these ~~agreements~~counterparties failed to perform according to the terms of their contracts was $305. In general, many of our over-the-counter derivative instruments and all exchange contracts 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~~At June 30, 2023, we had received cash ~~deposits in margin accounts. At December 31, 2017, September 30, 2017~~collateral from derivative instrument counterparties totaling $36. In addition, we may have offsetting derivative liabilities and ~~December 31, 2016, restricted cash in brokerage~~certain accounts ~~totaled $19.8, $10.3 and $7.9, respectively. Although we have concentrations~~payable balances with certain of ~~credit risk associated with derivative instruments,~~these counterparties, which further mitigates the previously mentioned 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 December 31, 2017.losses. 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.~~

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Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

Partnership’s debt rating. At ~~December 31, 2017,~~June 30, 2023, 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~~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~~many 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~~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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Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

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, as of December 31, 2017,~~offsetting:


	June 30, 2023		September 30, 2022		June 30, 2022
Derivative assets:
Derivatives designated as hedging instruments:

Foreign currency contracts	$	6	$	57	$	28
Interest rate contracts	30		66		44
	36		123		72
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	11		31		30
Derivatives not designated as hedging instruments:
Commodity contracts (a)	246		2,202		1,935
Foreign currency contracts	12		62		31
	258		2,264		1,966
Total derivative assets — gross	305		2,418		2,068
Gross amounts offset in the balance sheet	(134)		(295)		(226)
Cash collateral received	(36)		(398)		(659)
Total derivative assets — net	$	135	$	1,725	$	1,183
Derivative liabilities:
Derivatives designated as hedging instruments:



Interest rate contracts	(4)		—		—

Derivatives subject to PGC and DS mechanisms:
Commodity contracts	(18)		(26)		(23)
Derivatives not designated as hedging instruments:
Commodity contracts (a)	(448)		(487)		(338)
Foreign currency contracts	(4)		(2)		(2)
	(452)		(489)		(340)
Total derivative liabilities — gross	(474)		(515)		(363)
Gross amounts offset in the balance sheet	134		295		226
Cash collateral pledged	137		7		13
Total derivative liabilities — net	$	(203)	$	(213)	$	(124)

(a)Amounts at June 30, 2023 and September 30, ~~2017 and December 31, 2016:~~2022 include contracts associated with certain UGI International energy marketing businesses classified as held for sale (see Note 5).

December 31,
2017 September 30,
2017 December 31,
2016
Derivative assets:
Derivatives designated as hedging instruments:
Foreign currency contracts $ 1.2
$ 3.2
$ 24.6
Cross-currency contracts —
—
3.5
1.2
3.2
28.1
Derivatives subject to PGC and DS mechanisms:
Commodity contracts 0.4
1.7
6.9
Derivatives not designated as hedging instruments:
Commodity contracts 119.2
102.4
117.6
Foreign currency contracts 10.4
9.0
1.4
129.6
111.4
119.0
Total derivative assets — gross 131.2
116.3
154.0
Gross amounts offset in the balance sheet (32.5 ) (35.7 ) (35.7 )
Cash collateral received (12.0 ) (8.3 ) (7.1 )
Total derivative assets — net $ 86.7
$ 72.3
$ 111.2
Derivative liabilities:
Derivatives designated as hedging instruments:
Foreign currency contracts $ (5.6 ) $ (5.5 ) $ —
Cross-currency contracts (0.9 ) (2.9 ) —
Interest rate contracts (2.1 ) (2.3 ) (2.8 )
(8.6 ) (10.7 ) (2.8 )
Derivatives subject to PGC and DS mechanisms:
Commodity contracts (2.3 ) (1.5 ) (0.3 )
Derivatives not designated as hedging instruments:
Commodity contracts (42.2 ) (37.6 ) (65.2 )
Foreign currency contracts (34.3 ) (32.7 ) (0.2 )
(76.5 ) (70.3 ) (65.4 )
Total derivative liabilities — gross (87.4 ) (82.5 ) (68.5 )
Gross amounts offset in the balance sheet 32.5
35.7
35.7
Total derivative liabilities — net $ (54.9 ) $ (46.8 ) $ (32.8 )

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Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

~~Effect~~Effects of Derivative Instruments

The following tables provide information on the effects of derivative instruments on the ~~condensed consolidated statements~~Condensed Consolidated Statements of ~~income~~Income and changes in ~~AOCI for the three months ended~~ ~~December 31, 2017~~ ~~and~~ ~~2016~~:AOCI:


Three Months Ended June 30,:
	Gain (Loss) Recognized in AOCI				Gain (Loss) Reclassified from AOCI into Income				Location of Gain (Loss) Reclassified from AOCI into Income
Cash Flow Hedges:	2023		2022		2023		2022



Interest rate contracts	$	32	$	11	$	14	$	(4)	Interest expense


Net Investment Hedges:
Foreign currency contracts	$	(5)	$	23

	Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2023		2022		Location of Gain (Loss) Recognized in Income
Commodity contracts	$	1	$	(6)	Revenues
Commodity contracts	(224)		466		Cost of sales

Commodity contracts	(10)		6		Other operating income, net
Foreign currency contracts	(2)		17		Other non-operating income (expense), net
Total	$	(235)	$	483

Nine Months Ended June 30,:
	Gain (Loss) Recognized in AOCI				Gain (Loss) Reclassified from AOCI into Income				Location of Gain (Loss) Reclassified from AOCI into Income
Cash Flow Hedges:	2023		2022		2023		2022



Interest rate contracts	$	15	$	59	$	28	$	(17)	Interest expense


Net Investment Hedges:
Foreign currency contracts	$	(28)	$	34

	Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2023		2022		Location of Gain (Loss) Recognized in Income
Commodity contracts	$	11	$	(5)	Revenues
Commodity contracts	(1,893)		792		Cost of sales

Commodity contracts	(5)		6		Other operating income, net
Foreign currency contracts	(36)		32		Other non-operating income (expense), net
Total	$	(1,923)	$	825

Three Months Ended December 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: 2017 2016 2017 2016
Foreign currency contracts $ (1.4 ) $ 17.2
$ 0.8
$ 7.9
Cost of sales
Cross-currency contracts 0.1
(0.1 ) 0.2
(0.3 ) Interest expense/other operating income, net
Interest rate contracts 0.7
1.2
(0.5 ) (1.0 ) Interest expense
Total $ (0.6 ) $ 18.3
$ 0.5
$ 6.6

Gain (Loss)
Recognized in Income Location of Gain (Loss)
Recognized in Income
Derivatives Not Designated as Hedging Instruments: 2017 2016
Commodity contracts $ 24.4
$ 108.5
Cost of sales
Commodity contracts (1.3 ) 0.1
Revenues
Commodity contracts 0.1
(0.1 ) Operating and administrative expenses
Foreign currency contracts (4.8 ) 1.3
(Losses) gains on foreign currency contracts, net
Total $ 18.4
$ 109.8

For the three months ended December 31, 2017 and 2016, the amounts of derivative gains or losses representing ineffectiveness and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing were not material.

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 used in the normal course of operating our business and the price in these contracts are 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. Although certain of these contracts have the requisite elements of a derivative instrument, these contracts qualify for NPNS exception accounting because they provide for the delivery of products or services in quantities that are expected to be 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.

~~- 26 -~~

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

Note 1413 — Accumulated Other Comprehensive Income (Loss)

The tables below present changes in AOCI, ~~during the three months ended December 31, 2017 and 2016:~~net of tax:


Three Months Ended June 30, 2023	Postretirement Benefit Plans		Derivative Instruments		Foreign Currency		Total
AOCI — March 31, 2023	$	14	$	15	$	(270)	$	(241)
Other comprehensive income before reclassification adjustments	—		22		8		30
Amounts reclassified from AOCI	(1)		(10)		—		(11)
Other comprehensive (loss) income attributable to UGI	(1)		12		8		19
AOCI — June 30, 2023	$	13	$	27	$	(262)	$	(222)

Three Months Ended June 30, 2022	Postretirement Benefit Plans		Derivative Instruments		Foreign Currency		Total
AOCI — March 31, 2022	$	(14)	$	11	$	(175)	$	(178)
Other comprehensive income (loss) before reclassification adjustments	—		8		(106)		(98)
Amounts reclassified from AOCI	—		3		—		3
Other comprehensive income (loss) attributable to UGI	—		11		(106)		(95)
AOCI — June 30, 2022	$	(14)	$	22	$	(281)	$	(273)

Nine Months Ended June 30, 2023	Postretirement Benefit Plans		Derivative Instruments		Foreign Currency		Total
AOCI — September 30, 2022	$	14	$	37	$	(431)	$	(380)
Other comprehensive income before reclassification adjustments	—		10		169		179
Amounts reclassified from AOCI	(1)		(20)		—		(21)
Other comprehensive (loss) income attributable to UGI	(1)		(10)		169		158
AOCI — June 30, 2023	$	13	$	27	$	(262)	$	(222)

Nine Months Ended June 30, 2022	Postretirement Benefit Plans		Derivative Instruments		Foreign Currency		Total
AOCI — September 30, 2021	$	(17)	$	(33)	$	(90)	$	(140)
Other comprehensive income (loss) before reclassification adjustments	—		42		(191)		(149)
Amounts reclassified from AOCI	3		13		—		16
Other comprehensive income (loss) attributable to UGI	3		55		(191)		(133)
AOCI — June 30, 2022	$	(14)	$	22	$	(281)	$	(273)

Three Months Ended December 31, 2017 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total
AOCI — September 30, 2017 $ (19.2 ) $ (21.4 ) $ (52.8 ) $ (93.4 )
Other comprehensive (loss) income before reclassification adjustments (after-tax) —
(0.4 ) 22.3
21.9
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax) 0.6
(0.5 ) —
0.1
Reclassification adjustments tax (benefit) expense (0.2 ) 0.1
—
(0.1 )
Reclassification adjustments (after-tax) 0.4
(0.4 ) —
—
Other comprehensive income (loss) attributable to UGI 0.4
(0.8 ) 22.3
21.9
AOCI — December 31, 2017 $ (18.8 ) $ (22.2 ) $ (30.5 ) $ (71.5 )

Three Months Ended December 31, 2016 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total
AOCI — September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 )
Other comprehensive income (loss) before reclassification adjustments (after-tax) —
12.3
(70.9 ) (58.6 )
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax) 1.6
(6.6 ) —
(5.0 )
Reclassification adjustments tax (benefit) expense (0.6 ) 2.1
—
1.5
Reclassification adjustments (after-tax) 1.0
(4.5 ) —
(3.5 )
Other comprehensive income (loss) attributable to UGI 1.0
7.8
(70.9 ) (62.1 )
AOCI — December 31, 2016 $ (28.1 ) $ (5.6 ) $ (183.1 ) $ (216.8 )

~~For additional information on amounts reclassified from AOCI relating to derivative instruments, see~~ Note ~~13.~~

~~Note 15~~14 — 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.

Corporate & Other ~~principally comprise (1)~~includes certain items that are excluded from our CODM’s assessment of segment performance (see below for further details on these items). Corporate & Other also includes the net expenses of UGI’s captive general liability insurance company, ~~and~~ UGI’s corporate headquarters facility and UGI’s unallocated corporate and general expenses ~~and~~as well as interest income. In addition, Corporate & Other includes net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) because such items are excluded from profit measures evaluated by our chief operating decision maker (“CODM”) in assessing our reportable segments’ performance or allocating resources. 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 2017 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization as adjusted for the effects of gains and losses on commodity derivative instruments not associated with current-period transactions and other gains and losses that competitors do not necessarily have (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure

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Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)

expense on UGI debt that is not allocated. Corporate & Other assets principally comprise cash and cash equivalents of ~~performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies. Our CODM evaluates the performance~~UGI and its captive insurance company, and UGI corporate headquarters’ assets. The accounting policies of our ~~other~~ reportable segments ~~principally based upon their income before income taxes excluding gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions,~~are the same as ~~previously mentioned.~~those described in Note 2, “Summary of Significant Accounting Policies,” in the Company’s 2022 Annual Report.


Three Months Ended June 30, 2023	Total		Eliminations			AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other (a)
Revenues from external customers	$	1,659	$	—		$	514	$	611	$	260	$	270	$	4
Intersegment revenues	$	—	$	(25)	(b)	$	—	$	—	$	19	$	8	$	(2)
Cost of sales	$	1,104	$	(26)	(b)	$	251	$	418	$	192	$	118	$	151
Operating (loss) income	$	(732)	$	—		$	(8)	$	21	$	40	$	32	$	(817)
Income from equity investees	1		—			—		—		1		—		—
Loss on extinguishment of debt	(9)		—			—		—		—		—		(9)
Other non-operating income (expense), net	1		—			—		1		—		2		(2)
(Loss) earnings before interest expense and income taxes	(739)		—			(8)		22		41		34		(828)
Interest expense	(96)		—			(40)		(10)		(11)		(20)		(15)
(Loss) income before income taxes	$	(835)	$	—		$	(48)	$	12	$	30	$	14	$	(843)

Depreciation and amortization	$	134	$	—		$	43	$	30	$	22	$	38	$	1
Capital expenditures (including the effects of accruals)	$	255	$	—		$	42	$	27	$	40	$	146	$	—

Three Months Ended June 30, 2022	Total		Eliminations			AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other (a)
Revenues from external customers	$	2,033	$	—		$	597	$	738	$	450	$	250	$	(2)
Intersegment revenues	$	—	$	(99)	(b)	$	—	$	—	$	75	$	24	$	—
Cost of sales	$	1,361	$	(99)	(b)	$	370	$	544	$	436	$	121	$	(11)
Operating income (loss)	$	99	$	—		$	(10)	$	22	$	38	$	38	$	11

(Loss) income from equity investees	(45)		—			—		—		6		—		(51)


Other non-operating income, net	20		—			—		4		—		2		14
Earnings (loss) before interest expense and income taxes	74		—			(10)		26		44		40		(26)
Interest expense	(82)		—			(41)		(7)		(11)		(15)		(8)
(Loss) income before income taxes	$	(8)	$	—		$	(51)	$	19	$	33	$	25	$	(34)

Depreciation and amortization	$	130	$	—		$	44	$	29	$	20	$	37	$	—
Capital expenditures (including the effects of accruals)	$	201	$	—		$	28	$	25	$	9	$	139	$	—

Three Months Ended December 31, 2017 Total Eliminations AmeriGas
Propane UGI International Midstream & Marketing UGI
Utilities Corporate
& Other (b)
Revenues $ 2,125.2
$ —
$ 787.3
$ 784.2
$ 249.8
$ 305.4
$ (1.5 )
Intersegment revenues $ —
$ (97.1 ) (c) $ —
$ —
$ 78.2
$ 17.7
$ 1.2
Cost of sales $ 1,137.4
$ (96.0 ) (c) $ 366.1
$ 484.8
$ 239.0
$ 151.8
$ (8.3 )
Segment profit:
Operating income $ 391.8
$ 0.2
$ 147.9
$ 93.1
$ 52.3
$ 96.3
$ 2.0
Income (loss) from equity investees 1.0
—
—
(0.2 ) 1.2
(d) —
—
Losses on foreign currency contracts, net (4.8 ) —
—
(4.7 ) —
—
(0.1 )
Interest expense (58.2 ) —
(40.6 ) (5.6 ) (0.9 ) (10.9 ) (0.2 )
Income before income taxes $ 329.8
$ 0.2
$ 107.3
$ 82.6
$ 52.6
$ 85.4
$ 1.7
Partnership Adjusted EBITDA (a)
$ 194.1

Noncontrolling interests’ net income (loss) $ 68.3
$ —
$ 68.0
$ (0.3 ) $ —
$ —
$ 0.6
Depreciation and amortization $ 110.3
$ —
$ 47.4
$ 32.2
$ 10.1
$ 20.4
$ 0.2
Capital expenditures (including the effects of accruals) $ 128.5
$ —
$ 23.6
$ 21.7
$ 11.3
$ 71.7
$ 0.2
As of December 31, 2017
Total assets $ 12,343.9
$ (62.6 ) $ 4,206.2
$ 3,450.1
$ 1,325.1
$ 3,174.7
$ 250.4
Short-term borrowings $ 586.1
$ —
$ 263.5
$ 41.1
$ 100.0
$ 181.5
$ —
Goodwill $ 3,185.5
$ —
$ 2,001.3
$ 990.6
$ 11.5
$ 182.1
$ —

Three Months Ended December 31, 2016 Total Eliminations AmeriGas
Propane UGI International Midstream & Marketing UGI
Utilities Corporate
& Other (b)
Revenues $ 1,679.5
$ —
$ 677.2
$ 539.1
$ 209.6
$ 253.9
$ (0.3 )
Intersegment revenues $ —
$ (68.5 ) (c) $ —
$ —
$ 60.2
$ 7.5
$ 0.8
Cost of sales $ 647.4
$ (67.7 ) (c) $ 260.7
$ 258.0
$ 191.8
$ 109.5
$ (104.9 )
Segment profit:
Operating income $ 466.2
$ 0.1
$ 141.9
$ 88.9
$ 49.7
$ 82.2
$ 103.4
Loss from equity investees (0.2 ) —
—
(0.2 ) —
—
—
Gains on foreign currency contracts, net 1.3
—
—
0.1
—
—
1.2
Loss on extinguishments of debt (33.2 ) —
(33.2 ) —
—
—
—
Interest expense (55.4 ) —
(40.0 ) (4.8 ) (0.6 ) (10.0 ) —
Income before income taxes $ 378.7
$ 0.1
$ 68.7
$ 84.0
$ 49.1
$ 72.2
$ 104.6
Partnership Adjusted EBITDA (a) $ 185.1

Noncontrolling interests’ net income $ 60.2
$ —
$ 41.2
$ 0.2
$ —
$ —
$ 18.8
Depreciation and amortization $ 98.1
$ —
$ 44.6
$ 27.9
$ 8.0
$ 17.4
$ 0.2
Capital expenditures (including the effects of accruals) $ 173.6
$ —
$ 26.4
$ 21.5
$ 61.5
$ 64.1
$ 0.1
As of December 31, 2016
Total assets $ 11,300.5
$ (107.9 ) $ 4,217.9
$ 2,853.4
$ 1,178.4
$ 2,898.5
$ 260.2
Short-term borrowings $ 234.4
$ —
$ 77.5
$ 3.5
$ 55.0
$ 98.4
$ —
Goodwill $ 2,935.8
$ —
$ 1,978.5
$ 763.7
$ 11.5
$ 182.1
$ —

~~- 28 -~~

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)



Nine Months Ended June 30, 2023	Total		Eliminations			AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other (a)
Revenues from external customers	$	7,524	$	—		$	2,147	$	2,436	$	1,354	$	1,575	$	12
Intersegment revenues	$	—	$	(302)	(b)	$	—	$	—	$	232	$	69	$	1
Cost of sales	$	6,358	$	(301)	(b)	$	1,067	$	1,713	$	1,185	$	873	$	1,821
Operating (loss) income	$	(1,681)	$	—		$	240	$	197	$	249	$	361	$	(2,728)
Income (loss) from equity investees	2		—			—		(2)		4		—		—
Loss on extinguishment of debt	(9)		—			—		—		—		—		(9)
Other non-operating (loss) income, net	(25)		—			—		21		—		6		(52)
(Loss) earnings before interest expense and income taxes	(1,713)		—			240		216		253		367		(2,789)
Interest expense	(281)		—			(122)		(26)		(33)		(62)		(38)
(Loss) income before income taxes	$	(1,994)	$	—		$	118	$	190	$	220	$	305	$	(2,827)

Depreciation and amortization	$	397	$	—		$	132	$	86	$	65	$	112	$	2
Capital expenditures (including the effects of accruals)	$	647	$	—		$	93	$	84	$	74	$	396	$	—
As of June 30, 2023
Total assets	$	15,243	$	(182)		$	3,443	$	3,179	$	3,050	$	5,560	$	193

Nine Months Ended June 30, 2022	Total		Eliminations			AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other (a)
Revenues from external customers	$	8,172	$	—		$	2,423	$	3,011	$	1,424	$	1,313	$	1
Intersegment revenues	$	—	$	(396)	(b)	$	—	$	—	$	307	$	87	$	2
Cost of sales	$	4,951	$	(394)	(b)	$	1,333	$	2,267	$	1,389	$	701	$	(345)
Operating income	$	1,363	$	—		$	303	$	211	$	197	$	325	$	327
(Loss) income from equity investees	(32)		—			—		—		19		—		(51)
Loss on extinguishments of debt	(11)		—			—		—		—		—		(11)
Other non-operating income, net	41		—			—		17		—		7		17
Earnings before interest expense and income taxes	1,361		—			303		228		216		332		282
Interest expense	(245)		—			(120)		(22)		(31)		(47)		(25)
Income before income taxes	$	1,116	$	—		$	183	$	206	$	185	$	285	$	257

Depreciation and amortization	$	387	$	—		$	132	$	89	$	57	$	108	$	1
Capital expenditures (including the effects of accruals)	$	546	$	—		$	99	$	71	$	25	$	351	$	—
As of June 30, 2022
Total assets	$	17,111	$	(182)		$	4,365	$	4,410	$	3,198	$	5,146	$	174

(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 ~~provides a reconciliation of Partnership Adjusted EBITDA~~presents such pre-tax gains (losses) which have been included in Corporate & Other, and the reportable segments to ~~AmeriGas Propane income before income taxes:~~

Three Months Ended
December 31,
2017 2016
Partnership Adjusted EBITDA $ 194.1
$ 185.1
Depreciation and amortization (47.4 ) (44.6 )
Interest expense (40.6 ) (40.0 )
Loss on extinguishments of debt —
(33.2 )
Noncontrolling interest (i) 1.2
1.4
Income before income taxes $ 107.3
$ 68.7


~~(i)~~	~~Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.~~


~~(b)~~	Includes net pre-tax gains on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $6.6 and $105.5 during the three months ended December 31, 2017 and 2016, respectively.


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


~~(d)~~	~~Represents allowance for funds used during construction (“AFUDC”) associated with our PennEast Pipeline equity investment.~~

which they relate:

~~- 29 -~~

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)



Three Months Ended June 30, 2023	Location on Income Statement	AmeriGas Propane		UGI International		Midstream & Marketing
Net gains on commodity derivative instruments not associated with current-period transactions	Revenues	$	—	$	1	$	1
Net losses on commodity derivative instruments not associated with current-period transactions	Cost of sales	$	(51)	$	(87)	$	(14)
Net losses on commodity derivative instruments not associated with current-period transactions	Other operating income, net	$	—	$	(1)	$	—
AmeriGas operations enhancement for growth project	Operating and administrative expenses	$	(6)	$	—	$	—
Loss on extinguishment of debt	Loss on extinguishments of debt	$	(9)	$	—	$	—
Unrealized losses on foreign currency derivative instruments	Other non-operating income (expense), net	$	—	$	(2)	$	—


Loss associated with impairment of AmeriGas Propane goodwill	Impairment of goodwill	$	(656)	$	—	$	—

Three Months Ended June 30, 2022	Location on Income Statement	AmeriGas Propane		UGI International		Midstream & Marketing
Net gains (losses) on commodity derivative instruments not associated with current-period transactions	Revenues	$	—	$	2	$	(4)
Net (losses) gains on commodity derivative instruments not associated with current-period transactions	Cost of sales	$	(46)	$	110	$	(51)
Net gains on commodity derivative instruments not associated with current-period transactions	Other operating income, net	$	—	$	6	$	—
Restructuring costs	Operating and administrative expenses	$	(1)	$	(2)	$	(1)
Unrealized gains on foreign currency derivative instruments	Other non-operating income (expense), net	$	—	$	14	$	—
Impairments associated with certain equity method investments	Income (loss) from equity investees	$	—	$	—	$	(50)



Nine Months Ended June 30, 2023	Location on Income Statement	AmeriGas Propane		UGI International		Midstream & Marketing
Net gains on commodity derivative instruments not associated with current-period transactions	Revenues	$	—	$	4	$	7
Net losses on commodity derivative instruments not associated with current-period transactions	Cost of sales	$	(55)	$	(1,491)	$	(275)
Net losses on commodity derivative instruments not associated with current-period transactions	Other operating income, net	$	—	$	(4)	$	—

Loss on extinguishment of debt	Loss on extinguishments of debt	$	(9)	$	—	$	—
Unrealized losses on foreign currency derivative instruments	Other non-operating income (expense), net	$	—	$	(52)	$	—
AmeriGas operations enhancement for growth project	Operating and administrative expenses	$	(19)	$	—	$	—
Loss on disposal of U.K. energy marketing business	Loss on disposal of U.K. energy marketing business	$	—	$	(215)	$	—
Impairment of assets	Operating and administrative expenses	$	—	$	(19)	$	—
Loss associated with impairment of AmeriGas Propane goodwill	Impairment of goodwill	$	(656)	$	—	$	—

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Currency in millions, except per share amounts and where indicated otherwise)


Nine Months Ended June 30, 2022	Location on Income Statement	AmeriGas Propane		UGI International		Midstream & Marketing
Net gains (losses) on commodity derivative instruments not associated with current-period transactions	Revenues	$	—	$	7	$	(6)
Net (losses) gains on commodity derivative instruments not associated with current-period transactions	Cost of sales	$	(83)	$	458	$	(29)
Net gains on commodity derivative instruments not associated with current-period transactions	Other operating income, net	$	—	$	6	$	—
Restructuring costs	Operating and administrative expenses	$	(15)	$	(4)	$	(1)
Loss on extinguishment of debt	Loss on extinguishment of debt	$	—	$	(11)	$	—
Unrealized gain on foreign currency derivative instruments	Other non-operating income (expense), net	$	—	$	19	$	—
Impairments associated with certain equity method investments	Income (loss) from equity investees	$	—	$	—	$	(50)

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

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UGI CORPORATION AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

Information contained in this Quarterly Report on Form 10-Q ~~may contain~~contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as ~~amended (the “Exchange Act”).~~amended. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” or other similar words and terms of similar meaning, although not all forward-looking statements contain such words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future. All forward-looking statements made in this Quarterly Report on Form 10-Q rely upon the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you against relying on any forward-looking statement as these statements are subject to risks and uncertainties that may cause actual results ~~almost always~~to vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind those factors set forth in Item 1A. Risk Factors in this report and in the Company’s 2022 Annual Report and the Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2022 as well as the following important factors that could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) ~~adverse~~ weather conditions, including increasingly uncertain weather patterns due to climate change, resulting in reduced ~~demand;~~demand, the seasonal nature of our business, and disruptions in our operations and supply chain; (2) cost volatility and availability of energy products, including propane and other ~~liquefied petroleum gases (“LPG”), oil,~~LPG, electricity, and natural gas, as well as the availability of LPG cylinders, and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, health, tax, transportation, consumer protection, data privacy, accounting, and environmental ~~and accounting matters;~~matters, such as regulatory responses to climate change; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal ~~proceedings;~~or regulatory proceedings, inquiries or investigations; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers ~~and~~or retain current customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor ~~relations;~~relations and our ability to address existing or potential workforce shortages; (11) customer, counterparty, supplier, or vendor defaults; (12) liability for uninsured claims and for claims in excess of insurance coverage, including those for personal injury and property damage arising from explosions, acts of war, terrorism, natural disasters, pandemics, and other catastrophic events that may result from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and ~~LPG;~~LPG in all forms; (13) transmission or distribution system service interruptions; (14) political, regulatory and economic conditions in the United States, Europe and inother foreign countries, including uncertainties related to the ~~current conflicts in~~war between Russia and Ukraine, the ~~Middle East,~~European energy crisis, and foreign currency exchange rate fluctuations, particularly the euro; (15) credit and capital market conditions, including reduced access to capital markets and interest rate fluctuations; (16) changes in commodity market prices resulting in significantly higher cash collateral requirements; (17) impacts of our indebtedness and the restrictive covenants in our debt agreements; (18) reduced distributions from subsidiaries impacting the ability to pay ~~dividends; (18)~~dividends or service debt; (19) changes in Marcellus and Utica Shale gas production; ~~(19)~~(20) the availability, timing and success of our acquisitions, commercial initiatives and investments to grow our businesses; ~~(20)~~(21) our ability to successfully integrate acquired businesses and achieve anticipated synergies; ~~(21)~~(22) the interruption, disruption, failure, malfunction, or breach of our information technology systems, and those of our third-party vendors or service providers, including due to cyber attack; (23) the inability to complete pending or future energy infrastructure projects; (24) our ability to achieve the operational benefits and ~~(22) continued analysis~~cost efficiencies expected from the completion of ~~recent~~pending and future business transformation initiatives, including the impact of customer service disruptions resulting in potential customer loss due to the transformation activities; (25) our ability to attract, develop, retain and engage key employees; (26) uncertainties related to global pandemics; (27) the impact of proposed or future tax ~~legislation.~~legislation; (28) the impact of declines in the stock market or bond market, and a low interest rate environment, on our pension liability; (29) our ability to protect our intellectual property; and (30) our ability to overcome supply chain issues that may result in delays or shortages in, as well as increased costs of, equipment, materials or other resources that are critical to our business operations.

These factors, and those factors set forth in Item 1A. Risk Factors in this report and those factors set forth in Item 1A. Risk Factors in the Company’s ~~2017~~2022 Annual Report and the Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2022, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. Any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation (and expressly disclaim any obligation) to update publicly any forward-looking statement, whether as a result of new information or future events, except as required by the federal securities laws.

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UGI CORPORATION AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare the Company’s results of operations for the ~~three months ended December 31, 2017 (“2017~~2023 three-month ~~period”)~~period with the ~~three months ended December 31, 2016 (“2016~~2022 three-month ~~period”).~~period and the 2023 nine-month period with the 2022 nine-month period. Our ~~analyses~~analysis of results of operations should be read in conjunction with the segment information included in Note 1514 to ~~the condensed consolidated financial statements.~~Condensed Consolidated Financial Statements.

Because most of our businesses sell or distribute energy products used in large part for heating purposes, our results are significantly influenced by temperatures in our service territories, particularly during the heating-season months of October through March. As a result, our operating results, excluding the effects of gains and losses on ~~commodity~~ derivative instruments not associated with current-period transactions as further discussed below, are significantly higher in our first and second fiscal quarters.

Non-GAAP Financial Measures

UGI management uses “adjusted net income attributable to UGI Corporation” and “adjusted diluted earnings per share,” both of which are non-GAAP financial measures, when evaluating UGI’s overall performance. Management believes that these non-GAAP measures provide meaningful information to ~~investors. Adjusted net income attributable to UGI Corporation excludes (1) net after-tax~~investors about UGI’s performance because they eliminate gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions and ~~(2)~~ other significant discrete items that ~~management believes~~can affect the comparison of period-over-period ~~results (as such items are further described below).~~ results.

UGI does not designate its commodity and certain foreign currency derivative

~~- 30 -~~

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~~UGI CORPORATION AND SUBSIDIARIES~~

instruments as hedges under ~~U.S. generally accepted accounting principles (“GAAP”).~~GAAP. Volatility in net income (loss) attributable to UGI Corporation ~~as determined in accordance with GAAP~~ can occur as a result of gains and losses on ~~commodity and certain foreign currency~~such derivative instruments not associated with current-period transactions. These gains and losses result principally from recording changes in unrealized gains and losses on unsettled commodity and certain foreign currency derivative instruments and, to a much lesser extent, certain realized gains and losses on settled commodity derivative instruments that are not associated with current-period transactions. However, because these derivative instruments economically hedge anticipated future purchases or sales of energy commodities, or in the case of certain foreign currency derivatives reduce volatility in anticipated future earnings associated with our foreign operations, we expect that such gains or losses will be largely offset by gains or losses on anticipated future energy commodity transactions or mitigate ~~the~~ volatility in anticipated future earnings. ~~For further information, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share” below.~~

As further discussed below and in Note 5 to condensed consolidated financial statements, our net income for the three months ended December 31, 2017, was significantly affected by the December 22, 2017, enactment of the Tax Cuts and Jobs Act (the “TCJA”) and changes in French tax laws.

~~EXECUTIVE OVERVIEW~~

~~Net Income Attributable to UGI Corporation by Business Unit (GAAP):~~

For the three months ended December 31, 2017 2016
Variance - Favorable
(Unfavorable)
(Dollars in millions) Amount (a) % of Total Amount % of Total Amount % Change
AmeriGas Propane (b) $ 141.6
38.7 % $ 16.6
7.2 % $ 125.0
753.0 %
UGI International (c)(d) 61.1
16.7 % 88.3
38.3 % (27.2 ) (30.8 )%
Midstream & Marketing 112.0
30.6 % 29.9
13.0 % 82.1
274.6 %
UGI Utilities 68.3
18.7 % 44.3
19.2 % 24.0
54.2 %
Corporate & Other (e) (17.1 ) (4.7 )% 51.6
22.3 % (68.7 ) N.M.
Net income attributable to UGI Corporation $ 365.9
100.0 % $ 230.7
100.0 % $ 135.2
58.6 %


~~(a)~~	Net income attributable to UGI Corporation for the three months ended December 31, 2017, includes income (loss) from one-time adjustments to tax-related accounts as a result of the enactment of the TCJA as follows:

AmeriGas Propane $ 113.1
UGI International (9.3 )
Midstream & Marketing 74.3
UGI Utilities 8.1
Corporate & Other (20.2 )
Net income attributable to UGI Corporation $ 166.0

In addition to the one-time adjustments of the TCJA , net income attributable to UGI for the three months ended December 31, 2017, includes the beneficial impact of the TCJA, principally as a result of the lower federal income tax rate, of $20.4 million (as further described below under “Impact of Changes in U.S. and French Tax Laws”).


~~(b)~~	~~Three months ended December 31, 2016, includes net after-tax loss of $5.3 million from extinguishments of debt.~~

~~(c)~~

Three months ended December 31, 2017, includes beneficial impact of a $17.3 million adjustment to net deferred income tax liabilities associated with a December 2017 change in French income tax rates. Three months ended December 31, 2016, includes beneficial impact of a $27.4 million adjustment to net deferred income tax liabilities associated with a change in French income tax rate and an income tax settlement refund of $6.7 million, plus interest, in France. In addition to these one-time adjustments, net income attributable to UGI for the three months ended December 31, 2017, includes the negative impact of a higher 2018 French corporate income tax rate of $3.9 million (as further described below under “Impact of Changes in U.S. and French Tax Laws”).


~~(d)~~	~~Includes after-tax integration expenses associated with Finagaz of $1.2 million and $5.3 million for the three months ended December 31, 2017 and 2016, respectively.~~

~~(e)~~

Includes net after-tax gains on commodity derivative instruments not associated with current-period transactions of $4.6 million and $52.2 million for the three months ended December 31, 2017 and 2016, respectively. Also includes after-tax unrealized gains (losses) on certain foreign currency derivative instruments of $(0.1) million and $0.8 million for the three months ended December 31, 2017 and 2016, respectively.

~~N.M. — Variance is not meaningful.~~

~~- 31 -~~

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~~UGI CORPORATION AND SUBSIDIARIES~~

~~Impact of Changes in U.S. and French Tax Laws~~

On December 22, 2017, the TCJA was enacted into law. Among the significant changes resulting from the law, the TCJA reduces the U.S. federal income tax rate from 35% to 21% effective January 1, 2018, creates a territorial tax system with a one-time mandatory “toll tax” on previously unrepatriated foreign earnings, and allows for immediate capital expensing of certain qualified property. It also applies restrictions on the deductibility of interest expense and applies a broader application of compensation limitations. In addition, in December 2017 the French Parliament approved the Finance Bill for 2018 and the second amended Finance Bill for 2017 (collectively, the “December 2017 French Finance Bills”). One impact of the December 2017 French Finance Bills is an increase in the Fiscal 2018 corporate income tax rate in France to 39.4% from 34.4% previously. The December 2017 French Finance Bills also include measures to reduce the corporate income tax rate to 25.8% effective for fiscal years starting after January 1, 2022 (Fiscal 2023).

During the three months ended December 31, 2017, we recorded two impacts of the enactment of the TCJA and the December 2017 French Finance Bills. The first impact comprises “one-time” discrete adjustments to our deferred income tax assets and liabilities, accrued income taxes and deferred tax valuation allowances. For the three months ended December 31, 2017, the one-time adjustments associated with the TCJA decreased income tax expense and increased net income attributable to UGI by $166.0 million, or $0.94 per diluted share. For the three months ended December 31, 2017, the one-time remeasurement of our French deferred income tax assets and liabilities associated with the December 2017 French Finance Bills decreased income tax expense, and increased net income attributable to UGI, by $17.3 million, or $0.10 per diluted share. These one-time adjustments to our income tax assets and liabilities resulting from the TCJA and the December 2017 French Finance Bills have been excluded from our non-GAAP earnings in our non-GAAP disclosures below.

The second impact of the enactments of the TCJA and the December 2017 French Finance Bills primarily comprises the effects of the tax law changes on current-period results. With respect to the TCJA, the impact on current-period results principally reflects the lower federal corporate income tax rate, which for UGI in Fiscal 2018 consists of a blended federal income tax rate of 24.5%. For the three months ended December 31, 2017, the effects of the TCJA on current period results (excluding the one-time impacts described above) decreased income tax expense, and increased net income attributable to UGI, by approximately $20.4 million. With respect to the December 2017 French Finance Bills, the impact on current-period results reflects the higher 2018 French corporate income tax rate which increased income taxes, and decreased net income attributable to UGI, by approximately $3.9 million. On a combined basis (excluding the previously mentioned one-time discrete adjustments from the TCJA and the December 2017 French Finance Bills on income tax assets and liabilities), the TCJA and the December 2017 French Finance Bills decreased 2017 three-month period income tax expense, and increased net income attributable to UGI, by $16.5 million, or $0.09 per diluted share.

~~The impacts of the TCJA and the December 2017 French Finance Bills are more fully described below and in Note 5 to condensed consolidated financial statements.~~

~~Adjusted Net Income (Loss) Attributable to UGI Corporation by Business Unit (Non-GAAP):~~

~~Adjusted net income (loss) attributable to UGI Corporation for the three months ended December 31, 2017 and 2016 is as follows:~~

For the three months ended December 31, 2017 2016
Variance - Favorable
(Unfavorable)
(Dollars in millions) Amount % of Total Amount % of Total Amount % Change
AmeriGas Propane $ 28.5
15.9 % $ 21.9
13.6 % $ 6.6
30.1 %
UGI International 54.3
30.3 % 66.2
41.1 % (11.9 ) (18.0 )%
Midstream & Marketing 37.7
21.0 % 29.9
18.6 % 7.8
26.1 %
UGI Utilities 60.2
33.6 % 44.3
27.5 % 15.9
35.9 %
Corporate & Other (1.4 ) (0.8 )% (1.4 ) (0.8 )% —
N.M.
Adjusted net income attributable to UGI Corporation $ 179.3
100.0 % $ 160.9
100.0 % $ 18.4
11.4 %

Adjusted net income attributable to UGI Corporation for the 2017 three-month period was $179.3 million (equal to $1.01 per diluted share) compared to adjusted net income attributable to UGI Corporation for the 2016 three-month period of $160.9 million (equal to $0.91 per diluted share). Adjusted net income attributable to UGI in the 2017 and 2016 three-month periods includes the following:

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~~UGI CORPORATION AND SUBSIDIARIES~~

~~a $15.9 million increase in adjusted net income from UGI Utilities;~~

~~a $7.8 million increase in adjusted net income from Midstream & Marketing;~~

~~a $6.6 million increase in adjusted net income attributable to UGI from AmeriGas Propane; and~~

~~an $11.9 million decrease in adjusted net income from UGI International.~~

Adjusted results for the three months ended December 31, 2017, include approximately $16.5 million of lower income taxes on our current-period results reflecting the beneficial effects of the TCJA ($20.4 million) offset in part by an increase in UGI International income taxes of $3.9 million as a result of the increase in the French income tax rate for Fiscal 2018.

Temperatures in our domestic business units were slightly warmer than normal but colder than the prior-year period, while average temperatures at UGI International were approximately normal but warmer than the prior-year period. UGI Utilities improved results reflect the impact of the colder weather as well as higher base rates at PNG, which became effective on October 20, 2017. Although temperatures at AmeriGas Propane during the 2017 three-month period were colder than the prior-year period, the year-to-year comparison was significantly influenced by much colder temperatures that occurred in late December 2017. Much of the impact of this late December 2017 cold weather on volumes at AmeriGas Propane will be realized in January 2018. Our 2017 three-month period UGI International net income was negatively impacted by lower heating-related sales, slightly lower average bulk and cylinder unit margins and the $3.9 million increase in income tax expense as a result of the higher French income tax rate in Fiscal 2018.

We believe that each of our business units has sufficient liquidity in the form of revolving credit facilities and with respect to Midstream & Marketing, also an accounts receivable securitization facility, to fund business operations during Fiscal 2018 (see “Financial Condition and Liquidity” below).

~~Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share~~

As previously mentioned, UGI management uses “adjusted net income attributable to UGI Corporation” and “adjusted diluted earnings per share,” both of which are non-GAAP financial measures, when evaluating UGI’s overall performance. For the 2017 and 2016 three-month periods, adjusted net income attributable to UGI Corporation is net income attributable to UGI after excluding net after-tax gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (principally comprising changes in unrealized gains and losses on such derivative instruments), Finagaz integration expenses, losses associated with extinguishments of debt at AmeriGas Propane and the one-time impacts on income tax balances resulting from the enactment of TCJA and the French Finance Bills.

Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide meaningful information to investors about UGI’s performance because they eliminate gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions and other significant discrete items that can affect the comparison of period-over-period results.

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The following tables reflect the adjustments referred to above and reconcile ~~consolidated~~ net income (loss) attributable to UGI Corporation, the most directly comparable GAAP measure, to adjusted net income (loss) attributable to UGI Corporation, and reconcile diluted earnings (loss) per share, the most directly comparable GAAP measure, to adjusted diluted earnings (loss) per ~~share, to reflect the adjustments referred to above:~~share:


Adjusted net income (loss) attributable to UGI Corporation	Three Months Ended June 30,				Nine Months Ended June 30,
(Dollars in millions)	2023		2022		2023		2022
AmeriGas Propane	$	(35)	$	(37)	$	87	$	135
UGI International	13		15		150		161
Midstream & Marketing	22		23		165		132
Utilities	10		19		234		216
Corporate & Other (a)	(799)		(27)		(2,269)		185
Net (loss) income attributable to UGI Corporation	(789)		(7)		(1,633)		829
Net losses (gains) on commodity derivative instruments not associated with current-period transactions (net of tax of $(36), $5, $(465) and $98, respectively)	115		(12)		1,349		(255)
Unrealized losses (gains) on foreign currency derivative instruments (net of tax of $(1), $4, $(15) and $5, respectively)	1		(10)		37		(14)
Loss associated with impairment of AmeriGas Propane goodwill (net of tax of $4, $0, $4 and $0, respectively)	660		—		660		—
Loss on extinguishments of debt (net of tax of $(2), $0, $(2) and $(3), respectively)	7		—		7		8
Acquisition and integration expenses associated with the Mountaineer Acquisition (net of tax of $0, $0, $0 and $0, respectively)	—		—		—		1
Business transformation expenses (net of tax of $(1), $(1), $(2) and $(2), respectively)	1		1		4		4
AmeriGas operations enhancement for growth project (net of tax of $(2), $0, $(5) and $0, respectively)	4		—		14		—

Impairments associated with certain equity method investments (net of tax of $0, $(14), $0 and $(14), respectively)	—		36		—		36
Restructuring costs (net of tax of $0, $(1), $0 and $(6), respectively)	—		4		—		17
Loss on disposal of U.K. energy marketing business (net of tax of $0, $0, $(64) and $0, respectively)	—		—		151		—
Impairment of assets (net of tax of $0, $0, $0, and $0, respectively)	—		—		19		—
Total adjustments (a) (b)	788		19		2,241		(203)
Adjusted net (loss) income attributable to UGI Corporation	$	(1)	$	12	$	608	$	626

Three Months Ended December 31, 2017 Total AmeriGas Propane UGI International Midstream & Marketing UGI
Utilities Corporate
& Other
Adjusted net income attributable to UGI Corporation (millions):
Net income (loss) attributable to UGI Corporation $ 365.9
$ 141.6
$ 61.1
$ 112.0
$ 68.3
$ (17.1 )
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $2.1) (a) (4.6 ) —
—
—
—
(4.6 )
Unrealized losses on foreign currency derivative instruments (net of tax of $(0.0)) (a) 0.1
—
—
—
—
0.1
Integration expenses associated with Finagaz (net of tax of $(0.7)) (a) 1.2
—
1.2
—
—
—
Impact of French Finance Bill (17.3 ) —
(17.3 ) —
—
—
Impact from TCJA (166.0 ) (113.1 ) 9.3
(74.3 ) (8.1 ) 20.2
Adjusted net income (loss) attributable to UGI Corporation $ 179.3
$ 28.5
$ 54.3
$ 37.7
$ 60.2
$ (1.4 )

Adjusted diluted earnings per share:
UGI Corporation earnings (loss) per share — diluted $ 2.07
$ 0.80
$ 0.35
$ 0.63
$ 0.39
$ (0.10 )
Net gains on commodity derivative instruments not associated with current-period transactions (0.03 ) —
—
—
—
(0.03 )
Unrealized losses on foreign currency derivative instruments —
—
—
—
—
—
Integration expenses associated with Finagaz 0.01
—
0.01
—
—
—
Impact of French Finance Bill (0.10 ) —
(0.10 ) —
—
—
Impact from TCJA (0.94 ) (0.64 ) 0.05
(0.42 ) (0.05 ) 0.12
Adjusted diluted earnings (loss) per share $ 1.01
$ 0.16
$ 0.31
$ 0.21
$ 0.34
$ (0.01 )

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	Three Months Ended June 30,				Nine Months Ended June 30,
Adjusted diluted earnings per share	2023		2022		2023		2022
AmeriGas Propane	$	(0.17)	$	(0.17)	$	0.40	$	0.63
UGI International	0.06		0.07		0.69		0.75
Midstream & Marketing	0.10		0.11		0.76		0.61
Utilities	0.05		0.08		1.08		1.00
Corporate & Other (a)	(3.80)		(0.12)		(10.71)		0.85
Diluted (loss) earnings per share (c)	(3.76)		(0.03)		(7.78)		3.84
Net losses (gains) on commodity derivative instruments not associated with current-period transactions (c)	0.55		(0.06)		6.34		(1.18)
Unrealized losses (gains) on foreign currency derivative instruments	0.01		(0.05)		0.18		(0.06)
Loss associated with impairment of AmeriGas Propane goodwill	3.14		—		3.14		—
Loss on extinguishments of debt	0.03		—		0.03		0.03
Acquisition and integration expenses associated with the Mountaineer Acquisition	—		—		—		—
Business transformation expenses	0.01		0.01		0.02		0.02
AmeriGas operations enhancement for growth project	0.02		—		0.07		—
Impairments associated with certain equity method investments	—		0.17		—		0.17

Restructuring costs	—		0.02		—		0.08
Loss on disposal of U.K. energy marketing business	—		—		0.72		—
Impairment of assets	—		—		0.09		—

Total adjustments (a)	3.76		0.09		10.59		(0.94)
Adjusted diluted earnings per share (c)	$	—	$	0.06	$	2.81	$	2.90

Three Months Ended December 31, 2016 Total AmeriGas Propane UGI International Midstream & Marketing UGI
Utilities Corporate
& Other
Adjusted net income attributable to UGI Corporation (millions):
Net income attributable to UGI Corporation $ 230.7
$ 16.6
$ 88.3
$ 29.9
$ 44.3
$ 51.6
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $33.3) (a) (52.2 ) —
—
—
—
(52.2 )
Unrealized gains on foreign currency derivative instruments (net of tax of $0.4) (a) (0.8 ) —
—
—
—
(0.8 )
Loss on extinguishments of debt (net of tax of $(3.4)) (a) 5.3
5.3
—
—
—
—
Integration expenses associated with Finagaz (net of tax of $(2.8)) (a) 5.3
—
5.3
—
—
—
Impact from change in French tax rate (27.4 ) —
(27.4 ) —
—
—
Adjusted net income (loss) attributable to UGI Corporation $ 160.9
$ 21.9
$ 66.2
$ 29.9
$ 44.3
$ (1.4 )

Adjusted diluted earnings per share:
UGI Corporation earnings per share — diluted $ 1.30
$ 0.09
$ 0.50
$ 0.17
$ 0.25
$ 0.29
Net gains on commodity derivative instruments not associated with current-period transactions (0.29 ) —
—
—
—
(0.29 )
Unrealized gains on foreign currency derivative instruments (b) (0.01 ) —
—
—
—
(0.01 )
Loss on extinguishments of debt 0.03
0.03
—
—
—
—
Integration expenses associated with Finagaz 0.03
—
0.03
—
—
—
Impact from change in French tax rate (0.15 ) —
(0.15 ) —
—
—
Adjusted diluted earnings (loss) per share $ 0.91
$ 0.12
$ 0.38
$ 0.17
$ 0.25
$ (0.01 )


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


~~(b)~~	~~Includes the effects of rounding associated with per share amounts.~~

(a)Corporate & Other includes certain adjustments made to our reporting segments in arriving at net income (loss) attributable to UGI Corporation. 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 Note 14 to Condensed Consolidated Financial Statements for additional information related to these adjustments, as well as other items included within Corporate & Other.

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

~~2017 three-month period compared~~(c)The loss per share for the three months ended June 30, 2022, was determined excluding the effect of 5.67 million dilutive shares as the impact of such shares would have been antidilutive due to the ~~2016 three-month~~net loss for the period,

~~Note - Average temperatures~~ while the adjusted earnings per share for the three months ended June 30, 2022, was determined based upon ~~heating degree days~~fully diluted shares of 215.89 million. The loss per share for ~~all~~the nine months ended June 30, 2023, was determined excluding the effect of ~~our business segments presented below are now~~6.22 million dilutive shares as the impact of such shares would have been antidilutive due to the net loss for the period, while the adjusted earnings per share for the nine months ended June 30, 2023, was determined based upon ~~recent 15-year periods (rather than recent 30-year periods) as we believe more recent temperatures are a better indication~~fully diluted shares of ~~normal heating degree days. Prior-period weather statistics have been restated, as appropriate, to conform to the new periods.~~216.03 million.

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EXECUTIVE OVERVIEW

Recent Developments

Impairment of Goodwill. During the quarter ended June 30, 2023, the Company identified interim impairment indicators related to goodwill within the AmeriGas Propane reporting unit: (1) AmeriGas Partners issued $500 million of Senior Notes at an interest rate of 9.375%, which was significantly higher than the interest rates on the other AmeriGas Propane debt obligations; and (2) financial projections for the AmeriGas Propane reporting unit were reduced significantly compared to previous forecasts following declines in gross margins and customer retention and higher operating expenses. The Company concluded that these events constituted triggering events that indicate that the AmeriGas Propane goodwill may be impaired and, as such, performed an interim impairment test of its goodwill as of May 31, 2023.

We performed a quantitative assessment of the AmeriGas Propane reporting unit using a weighting of the income and market approaches to determine its fair value. Based on our evaluation, the estimated fair value of the reporting unit was determined to be less than its carrying value. As a result, the Company recorded a non-cash pre-tax goodwill impairment charge of $656 million, included in “Impairment of goodwill” on the Condensed Consolidated Statement of Income, to reduce the carrying value of AmeriGas Propane to its fair value. The Company calculated the deferred tax effect using the simultaneous equation method.

The performance of the AmeriGas Propane reporting unit and the potential for future developments in the global economic environment, including the prospect of higher interest rates, introduces a heightened risk for additional impairment in the AmeriGas Propane reporting unit. If there is continued deterioration in the results of operations, a portion or all of the remaining recorded goodwill for the AmeriGas Propane reporting unit, which was $1.3 billion as of June 30, 2023, could be subject to further impairment.

See Note 2 to Condensed Consolidated Financial Statements for additional information.

Sale of U.K. Energy Marketing Business. On October 21, 2022, UGI International, through a wholly-owned subsidiary, sold its natural gas marketing business located in the U.K. for a net cash payment of $19 million which includes certain working capital adjustments. In conjunction with the sale, during the first quarter of Fiscal 2023, the Company recorded a pre-tax loss of $215 million ($151 million after-tax) substantially all of which loss was due to the non-cash transfer of commodity derivative instruments associated with the business. At the date of closing of the sale, these commodity derivative instruments had a net carrying value of $206 million which is attributable to net unrealized gains on such instruments. At September 30, 2022, these derivative instruments had a net carrying value of $276 million. The change in the carrying amount of these derivative instruments between September 30, 2022 and October 21, 2022 resulted from changes in their fair value during that period.

Other UGI International Energy Marketing Businesses. In November 2022, the Company announced that it expected to sign a definitive agreement during the first quarter of Fiscal 2023 to sell its energy marketing business in France. In December 2022, the Company announced that it no longer expected to sign a such agreement as extended negotiations with the potential buyer had been discontinued.

During the first quarter of Fiscal 2023, the Company recorded a $19 million pre-tax impairment charge to reduce the carrying values of certain assets associated with its energy marketing business in the Netherlands, comprising property, plant and equipment and intangible assets.

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For the three months ended December 31, 2017 2016 Increase (Decrease)
(Dollars in millions)
Revenues $ 787.3
$ 677.2
$ 110.1
16.3 %
Total margin (a) $ 421.2
$ 416.5
$ 4.7
1.1 %
Partnership operating and administrative expenses $ 230.3
$ 226.8
$ 3.5
1.5 %
Partnership Adjusted EBITDA (b)(c) $ 194.1
$ 185.1
$ 9.0
4.9 %
Operating income (c) (d) $ 147.9
$ 141.9
$ 6.0
4.2 %
Retail gallons sold (millions) 305.0
305.7
$ (0.7 ) (0.2 )%
Heating degree days—% (warmer) than normal (e) (1.4 )% (10.3 )% —
—
actual date of closing, the fair value of derivative commodity hedge contracts currently held by the Company but not subject to transfer to the buyer, and conditions associated with certain customer contracts. The effects of these adjustments will be settled on, or subsequent to, the closing date. The closing of the pending sale is subject to regulatory and other third-party approvals and is expected to occur during the first quarter of Fiscal 2024.


~~(a)~~	Total margin represents total revenues less total cost of sales. Total margin for the three months ended December 31, 2017 and 2016 excludes net pre-tax gains of $0.8 million and $25.7 million, respectively, on AmeriGas Propane commodity derivative instruments not associated with current-period transactions.


~~(b)~~	Partnership Adjusted EBITDA should not be considered as an alternative to net income (loss) (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 15 to condensed consolidated financial statements).


~~(c)~~	Amounts for the three months ended December 31, 2016, reflect adjustments to correct previously recorded gains on sales of fixed assets ($8.8 million) and decreased depreciation expense ($1.1 million) relating to certain assets acquired with the Heritage Propane acquisition in 2012, which adjustments reduced Partnership Adjusted EBITDA by $8.8 million and reduced operating income by $7.7 million.


~~(d)~~	~~Operating income reflects certain operating and administrative expenses of the General Partner.~~


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

See Note 5 to Condensed Consolidated Financial Statements for additional information.

Global Macroeconomic Conditions. Beginning in Fiscal 2021 and continuing into Fiscal 2023, global commodity and labor markets have experienced significant inflationary pressures attributable to various economic and political factors, including, among others: the economic recovery and evolving consumer patterns associated with the COVID-19 pandemic; supply chain issues including those associated with labor shortages; significant increases and volatility in energy commodity prices; and political and regulatory conditions resulting from the war between Russia and Ukraine. These factors have contributed to inflationary pressures as evidenced by recent increases in various consumer price indices. In response to these inflationary pressures, central banks in the U.S. and Europe began increasing interest rates during Fiscal 2022. In addition, during the last several years, we have experienced significant volatility in energy commodity prices, particularly in LPG, natural gas and electricity prices, which have resulted in substantial fluctuations in the fair values of our commodity derivative instruments. These inflationary pressures and commodity price fluctuations have resulted in, among other things, increases in inventory and certain operating and distribution expenses across all of our businesses. Commodity price fluctuations have also significantly affected the cash collateral deposit requirements of our derivative instrument counterparties and the restricted cash required to be held in our derivative broker and clearing institution accounts. We cannot predict the duration or total magnitude of these conditions and the effects such conditions may have on our future business, financial results, financial position, and liquidity and cash flows. However, we continue to monitor and respond to these global economic and political conditions and remain focused on managing our financial condition and liquidity as these conditions continue to evolve.

2023 three-month period compared with 2022 three-month period

Discussion. Net loss attributable to UGI Corporation for the 2023 three-month period was $789 million (equal to $3.76 loss per diluted share) compared to $7 million (equal to $0.03 loss per diluted share) for the 2022 three-month period. These results include net (losses) gains from changes in unrealized commodity derivative instruments and certain foreign currency derivative instruments of $(116) million and $22 million during the 2023 and 2022 three-month periods, respectively. The higher losses from changes in commodity derivative instruments during the 2023 three-month period principally reflects significant declines in commodity energy prices in Europe following unprecedented increases in such prices during Fiscal 2022.

Net loss attributable to UGI Corporation during the 2023 three-month period also includes (1) a $660 million loss associated with impairment of AmeriGas Propane goodwill; (2) loss on extinguishment of debt of $7 million at AmeriGas Propane; (3) external advisory fees of $4 million associated with AmeriGas operations enhancement for growth project; and (4) business transformation expenses of $1 million associated with corporate support functions.

Net loss attributable to UGI Corporation during the 2022 three-month period also includes (1) impairments of $36 million associated with certain equity method investments; (2) restructuring costs of $4 million largely attributable to a reduction in workforce and related costs; and (3) business transformation expenses of $1 million associated with corporate support functions.

Adjusted net loss attributable to UGI Corporation for the 2023 three-month period was $1 million (equal to $0.00 per diluted share) compared to adjusted net income of $12 million (equal to $0.06 per diluted share) for the 2022 three-month period. The increase in adjusted net loss attributable to UGI Corporation during the 2023 three-month period reflects a lower earnings contribution from Utilities, UGI International and Midstream & Marketing business segments, partially offset by a slightly higher earnings contribution from the AmeriGas Propane business segment. During the 2023 three-month period, temperatures in all of our business segments, except for our UGI International business segment, were warmer than the prior-year period.

AmeriGas Propane’s adjusted net loss attributable to UGI Corporation decreased $2 million in the 2023 three-month period. This decrease principally reflects higher total margin primarily resulting from the benefit of higher average retail propane unit margin in the 2023 three-month period, partially offset by lower volumes sold and higher operating and administrative

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expenses. The higher operating and administrative expenses primarily reflect, among other things, higher overtime and other employee-related costs associated with distribution activity and the effects of continuing inflationary pressures.

UGI International’s adjusted net income attributable to UGI Corporation decreased $2 million in the 2023 three-month period, notwithstanding slightly higher retail LPG gallons sold, ~~during~~principally reflecting lower total margin from our energy marketing business, substantially offset by higher average unit margin from our LPG business attributable to strong margin management efforts and colder weather. This decrease also reflects higher operating and administrative expenses primarily reflecting the ~~2017~~impact of inflationary increases.

Midstream & Marketing’s adjusted net income attributable to UGI Corporation decreased $1 million in the 2023 three-month period ~~were approximately equal~~primarily attributable to lower total margin from natural gas marketing activities, partially offset by the impact of incremental natural gas gathering activities reflecting in large part the Fiscal 2022 acquisition of Pennant.

Utilities’ adjusted net income attributable to UGI Corporation decreased $9 million in the 2023 three-month period compared to the prior-year period. ~~Average~~The decrease was largely attributable to the higher operating expenses, including higher uncollectible accounts expenses and higher contractor labor and personnel-related expenses. This decrease was partially offset by the increase in total margin due in large part to the increase in base rates and the implementation of the weather normalization adjustment at PA Gas Utility, both of which became effective during the first quarter of Fiscal 2023.

2023 nine-month period compared with 2022 nine-month period

Discussion. Net loss attributable to UGI Corporation for the 2023 nine-month period was $1,633 million (equal to $7.78 loss per diluted share) compared to net income attributable to UGI Corporation of $829 million (equal to $3.84 per diluted share) for the 2022 nine-month period. These results include net (losses) gains from changes in unrealized commodity derivative instruments and certain foreign currency derivative instruments of $(1,386) million and $269 million during the 2023 and 2022 nine-month periods, respectively. The higher losses from changes in commodity derivative instruments during the 2023 nine-month period, principally reflects significant declines in commodity energy prices in Europe following unprecedented increases in such prices during Fiscal 2022.

Net loss attributable to UGI Corporation during the 2023 nine-month period also includes (1) a $660 million loss associated with impairment of AmeriGas Propane goodwill; (2) a $151 million loss on the sale of our energy marketing business in the U.K., principally reflecting the impact of the transfer of derivative hedge contracts; (3) an impairment of assets of $19 million; (4) external advisory fees of $14 million associated with AmeriGas operations enhancement for growth project; (5) loss on extinguishment of debt of $7 million at AmeriGas Propane; and (6) business transformation expenses of $4 million associated with corporate support functions.

Net income attributable to UGI Corporation during the 2022 nine-month period also includes (1) impairments of $36 million associated with certain equity method investments; (2) restructuring costs of $17 million largely attributable to a reduction in workforce and related costs; (3) loss on extinguishment of debt of $8 million at UGI International; (4) business transformation expenses of $4 million associated with corporate support functions; and (5) acquisition and integration expenses of $1 million associated with the Mountaineer Acquisition.

Adjusted net income attributable to UGI Corporation for the 2023 nine-month period was $608 million (equal to $2.81 per diluted share) compared to $626 million (equal to $2.90 per diluted share) for the 2022 nine-month period. The decrease in adjusted net income attributable to UGI Corporation for the 2023 nine-month period reflects lower earnings contributions from our AmeriGas Propane and UGI International business segments, partially offset by higher earnings contributions from our Midstream & Marketing and Utilities business segments. During the 2023 nine-month period, temperatures ~~based upon~~in all of our business units, except for our AmeriGas Propane business segment, were warmer than the prior-year period.

AmeriGas Propane’s adjusted net income attributable to UGI Corporation decreased $48 million in the 2023 nine-month period. This decrease principally reflects higher operating and administrative expenses reflecting, among other things, higher overtime and other employee-related costs associated with distribution activity, the effects of continuing inflationary pressures and lower total margin largely attributable to the lower retail propane volumes sold, substantially offset by the benefit of higher average retail propane unit margins in the 2023 nine-month period.

UGI International’s adjusted net income attributable to UGI Corporation decreased $11 million in the 2023 nine-month period, mainly reflecting the translation effects of weaker foreign currencies. UGI International operating results reflect lower total LPG margin principally due to the effects of the lower LPG retail volumes sold attributable to the warmer weather and lower residential LPG consumption resulting from energy conservation measures in Europe due in large part to the war between

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Ukraine and Russia. These decreases were partially offset by higher margin from natural gas energy marketing activities and higher retail LPG average unit margins attributable to strong margin management efforts and lower commodity prices.

Midstream & Marketing’s adjusted net income attributable to UGI Corporation increased $33 million in the 2023 nine-month period. The increase in adjusted net income is primarily attributable to higher margins related to natural gas marketing activities and incremental earnings contributions from UGI Moraine East and Pennant.

Utilities’ adjusted net income attributable to UGI Corporation increased $18 million in the 2023 nine-month period. The increase was largely related to the increase in base rates and the implementation of the weather normalization adjustment at PA Gas Utility, both of which became effective during the first quarter of Fiscal 2023. The increase in total margin was partially offset by higher operating and administrative expenses.

SEGMENT RESULTS OF OPERATIONS

2023 Three-Month Period Compared with the 2022 Three-Month Period

AmeriGas Propane


For the three months ended June 30,	2023			2022			Increase (Decrease)
(Dollars in millions)
Revenues	$	514		$	597		$	(83)	(14)	%
Total margin (a)	$	263		$	227		$	36	16	%
Operating and administrative expenses	$	236		$	204		$	32	16	%
Operating loss/loss before interest expense and income taxes	$	(8)		$	(10)		$	2	(20)	%
Retail gallons sold (millions)	163			173			(10)		(6)	%
Heating degree days—% colder than normal (b)	4.2		%	16.5		%	—		—

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

(b)Deviation from average heating degree days is determined on a rolling 10-year period utilizing volume-weighted weather data based on weather statistics provided by NOAA for 344 regions in the United States, excluding Alaska and Hawaii.

Average temperatures during the ~~2017~~2023 three-month period were ~~1.4% warmer~~4.2% colder than normal ~~but 9.9% colder~~and 9.2% warmer than the prior-year period. ~~Average temperatures~~Total retail gallons sold decreased 6% during the ~~2017~~2023 three-month period were significantly influenced by much colder than normal temperatures that occurred during the last week of December which was nearly 60% colder than the prior year. Excluding the last week of December 2017, average temperatures during the 2017 three-month period were approximately 6.6% warmer than normal and 3.8% colder than the prior-year period.

~~AmeriGas Propane’s retail propane revenues increased $99.2 million during the 2017 three-month period reflecting the~~due to effects of higher average retail selling prices ($100.6 million) partially offset by the lower retail volumes sold ($1.4 million). Wholesale propane revenues increased $8.2 million during the 2017 three-month period reflecting the effects of higher average wholesale selling prices ($5.6 million)continuing customer attrition and ~~higher wholesale volumes sold ($2.6 million).~~ structural conservation.

Average daily wholesale propane commodity prices during the ~~2017~~2023 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately ~~64% higher~~46% lower than such prices during the ~~2016~~2022 three-month period. ~~Other~~Total revenues indecreased $83 million during the ~~2017~~2023 three-month period ~~were slightly higher than in~~largely reflecting lower retail propane revenues ($55 million) on the ~~prior-year period. AmeriGas Propane total~~lower retail volumes sold ($28 million) and the effects of lower average retail propane selling prices ($27 million), and lower wholesale revenues ($24 million).

Total cost of sales ~~increased $105.4~~decreased $119 million ~~principally~~during the 2023 three-month period largely reflecting the ~~effects of higher average~~lower retail propane product costs ($~~103.0~~71 million) ~~and, to a much lesser extent,~~, the ~~effects of the higher wholesale~~lower average retail propane volumes ~~sold.~~

~~AmeriGas Propane total~~sold ($17 million), and lower wholesale cost of sales ($28 million). Total margin increased ~~$4.7~~$36 million in the ~~2017~~2023 three-month period ~~principally reflecting slightly~~largely attributable to higher average retail ~~propane total margin~~unit margins ($~~2.6~~44 million) and slightly higher ~~non-propane total margin~~wholesale margins ($~~2.1~~4 million)~~. The increase in retail propane total margin reflects slightly higher average retail unit margin.~~

Partnership Adjusted EBITDA increased $9.0 million in the 2017 three-month period principally reflecting the effects of the higher total margin ($4.7 million) and higher other operating income ($7.8 million), partially offset by ~~slightly~~the effects on total margin from the lower retail propane volumes sold ($11 million).

Operating loss and loss before interest expense and income taxes decreased $2 million during the 2023 three-month period primarily reflecting the increase in total margin ($36 million), largely offset by higher ~~Partnership~~ operating and administrative expenses ($~~3.5~~32 million)~~. The increase in other operating income reflects the absence of an $8.8 million adjustment recorded in~~ compared to the prior-year ~~period to correct previously recorded gains on sales of fixed assets acquired with the Heritage Propane acquisition in 2012.~~period. The increase in operating and administrative expenses ~~principally~~ reflects, among other things, higher salaries and benefits expenses, higher overtime, higher advertising expenses and higher vehicle ~~($2.9 million), outside services ($2.0 million) and compensation and benefits ($1.9 million) expenses partially offset by lower general insurance and self-insured casualty and liability expense.~~expenses.

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AmeriGas Propane operating income increased $6.0 million in the 2017 three-month period principally reflecting the $9.0 million increase in Adjusted EBITDA partially offset by a $2.8 million increase in depreciation and amortization expense.

During the 2016 three-month period, AmeriGas Partners recognized a pre-tax loss of $33.2 million associated with early repayments of $500 million principal amount of AmeriGas Partners’ 7.0% Senior Notes comprising early redemption premiums and the write-off of unamortized debt issuance costs.

UGI International

For the three months ended December 31, 2017 2016 Increase (Decrease)
(Dollars in millions)
Revenues $ 784.2
$ 539.1
$ 245.1
45.5 %
Total margin (a) $ 299.4
$ 281.1
$ 18.3
6.5 %
Operating and administrative expenses (b) $ 173.9
$ 165.6
$ 8.3
5.0 %
Operating income (b) $ 93.1
$ 88.9
$ 4.2
4.7 %
Income before income taxes (b) (c) $ 82.6
$ 84.0
$ (1.4 ) (1.7 )%
LPG retail gallons sold (millions) 263.6
254.2
$ 9.4
3.7 %
UGI International degree days—% (warmer) colder than normal (d) (0.9 )% 6.6 % —
—


For the three months ended June 30,	2023			2022			(Decrease) Increase
(Dollars in millions)
Revenues	$	611		$	738		$	(127)	(17)	%
Total margin (a)	$	193		$	194		$	(1)	(1)	%
Operating and administrative expenses	$	157		$	143		$	14	10	%
Operating income	$	21		$	22		$	(1)	(5)	%
Earnings before interest expense and income taxes	$	22		$	26		$	(4)	(15)	%
LPG retail gallons sold (millions)	158			155			3		2	%
Heating degree days—% (warmer) than normal (b)	(9.8)		%	(9.1)		%	—		—


~~(a)~~	Total margin represents total revenues less total cost of sales. Total margin for the three months ended December 31, 2017 and 2016 excludes net pre-tax gains of $17.0 million and $15.9 million, respectively, on UGI International commodity derivative instruments not associated with current-period transactions.


~~(b)~~	~~Reflects impacts of Finagaz integration expenses for the three months ended December 31, 2017 and 2016, of $1.9 million and $8.1 million, respectively.~~


~~(c)~~	Income before income taxes for the three months ended December 31, 2017 and 2016 excludes net pre-tax unrealized gains (losses) on certain foreign currency derivative contracts of $(0.1) million and $1.2 million, respectively.


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

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

(b)Deviation from average heating degree days is determined on a rolling 10-year period utilizing volume-weighted weather data at locations in our UGI International service territories.

Average temperatures during the ~~2017~~2023 three-month period were ~~approximately 0.9%~~9.8% warmer than normal and ~~7.0% warmer~~5.1% colder than the prior-year period. Total LPG retail gallons sold during the ~~2017~~2023 three-month period were 2% higher than the prior-year period ~~as incremental retail gallons sold as a result of our October 2017 acquisition of Total’s retail LPG business~~due in ~~Italy (now known as “UniverGas”) were partially offset by~~large part to the ~~effects of the warmer~~colder weather ~~on bulk sales and lower crop-drying volumes. During the 2017 three-month period, average wholesale commodity prices for propane and butane in northwest Europe were approximately 37% and 25% higher~~ than in the prior-year period, ~~respectively.~~substantially offset by lower consumption, principally from residential customers, primarily resulting from the European conservation measures due in large part to high global energy prices and the war between Russia and Ukraine.

UGI International base-currency results are translated into ~~U.S. dollars~~USD based upon exchange rates experienced during the reporting periods. The functional currency of a significant portion of our UGI International results is the euro and, to a much lesser extent, the British pound sterling. During the ~~2017~~2023 and ~~2016~~2022 three-month periods, the average ~~un-weighted euro-to-dollar~~unweighted euro-to-USD translation rates were approximately ~~$1.18~~$1.09 and ~~$1.08,~~$1.06, respectively, and the average ~~un-weighted~~unweighted British pound ~~sterling-to-dollar~~sterling-to-USD translation rates were approximately ~~$1.33~~$1.25 and ~~$1.25,~~$1.26, respectively. ~~Although the euro and British pound sterling were stronger during the 2017 three-month period and impact the comparison of line item amounts presented~~Fluctuations in ~~the table above, the effects of~~ these ~~stronger currencies did not~~foreign currency exchange rates can have a significant impact on ~~UGI International net income due to gains and losses on~~the individual financial statement components discussed below. The Company uses forward foreign currency exchange ~~contracts.~~contracts entered into over multi-year periods to reduce the volatility in earnings that may result from such changes in foreign currency exchange rates. Realized gains (losses) on these foreign exchange contracts did not have a material impact on either of the three-month periods.

UGI International revenues ~~increased $245.1 million during the 2017 three-month period reflecting approximately $137.0 million of combined incremental revenues from UniverGas~~ and our August 2017 acquisition of an electricity and natural gas marketing business in the Netherlands (“DVEP”), the effects of higher LPG selling prices resulting from the higher LPG product costs, and the translation effects on local currency revenues of the stronger euro and British pound sterling. UGI International cost of sales ~~increased $226.8~~decreased $127 million and $126 million, respectively, during the ~~2017~~2023 three-month period ~~reflecting~~compared to the prior-year period. Average wholesale prices for propane and butane during the 2023 three-month period in northwest Europe were approximately ~~$119.0 million of incremental~~41% and 50% lower, respectively, compared with the prior-year period. The decrease in revenues and cost of sales ~~associated with UniverGas~~principally reflects the impact from lower LPG sales prices and ~~DVEP,~~lower LPG costs, partially offset by slightly higher ~~average~~ LPG ~~commodity costs,~~retail volumes sold and the translation effects of the stronger ~~euro~~foreign currencies (approximately $10 million and ~~British pound sterling.~~$6 million, respectively).

UGI International total margin ~~increased $18.3~~decreased $1 million during the 2023 three-month period primarily reflecting lower total margin from our energy marketing businesses, substantially offset by higher margins from our LPG business attributable to strong unit margin management efforts and colder weather than the prior-year period and the translation effects of stronger foreign currencies (approximately $4 million).

UGI International operating income and earnings before interest expense and income taxes decreased $1 million and $4 million, respectively, during the 2023 three-month period compared to the prior-year period. The decrease in operating income principally reflects higher operating and administrative expenses ($14 million), partially offset by higher other income ($8 million). The higher operating and administrative expenses during the 2023 three-month period primarily reflects the effect of inflationary increases, higher uncollectible accounts expenses from energy marketing businesses and the translation effects of the stronger ~~euro~~foreign currencies (approximately $3 million). The decrease in earnings before interest expense and ~~British pound sterling~~income taxes in the 2023 three-month period largely reflects the decrease in operating income and ~~approximately $18.0~~slightly lower realized gains on foreign currency exchange contracts entered into in order to reduce volatility in UGI International earnings resulting from the effects of changes in foreign currency exchange rates.

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Midstream & Marketing



For the three months ended June 30,	2023		2022		Increase (Decrease)
(Dollars in millions)
Revenues	$	279	$	525	$	(246)	(47)	%
Total margin (a)	$	87	$	89	$	(2)	(2)	%
Operating and administrative expenses	$	31	$	29	$	2	7	%
Operating income	$	40	$	38	$	2	5	%
Earnings before interest expense and income taxes	$	41	$	44	$	(3)	(7)	%

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

Average temperatures across Midstream & Marketing’s energy marketing territory during the 2023 three-month period were 6.8% warmer than normal and 3.0% warmer than the prior-year period.

Midstream & Marketing revenues decreased $246 million during the 2023 three-month period compared to the prior-year period, primarily reflecting lower revenues from natural gas marketing activities ($255 million), including the effects of peaking and capacity management activities, that were primarily impacted by significantly lower natural gas prices and, to a lesser extent, lower volumes from the warmer weather partially offset by higher retail power marketing revenues.

Midstream & Marketing cost of sales decreased $244 million during the 2023 three-month period compared to the prior-year period, largely driven by the lower natural gas costs related to the previously mentioned natural gas marketing activities, partially offset by higher cost of sales related to retail power marketing activities.

Midstream & Marketing total margin decreased $2 million during the 2023 three-month period largely reflecting lower margins from natural gas marketing activities ($10 million), including the effects of peaking and capacity management activities, partially offset by incremental natural gas gathering and processing activities ($7 million), primarily from the prior-year acquisition of Pennant.

Midstream & Marketing operating income during the 2023 three-month period increased $2 million, largely attributable to higher other income, partially offset by the previously mentioned decrease in total margin, higher operating and administrative expenses ($2 million) and higher depreciation and amortization ($2 million). The decrease in earnings before interest expense and income taxes of $3 million principally reflects lower income from ~~UniverGas~~equity investees following the acquisition of the remaining 53% ownership interest in Pennant during the fourth quarter of Fiscal 2022, partially offset by the increase in operating income.

Utilities


For the three months ended June 30,	2023			2022			Increase (Decrease)
(Dollars in millions)
Revenues	$	278		$	274		$	4	1	%
Total margin (a)	$	156		$	151		$	5	3	%
Operating and administrative expenses (a)	$	87		$	79		$	8	10	%
Operating income	$	32		$	38		$	(6)	(16)	%
Earnings before interest expense and income taxes	$	34		$	40		$	(6)	(15)	%
Gas Utility system throughput—bcf
Core market	12			13			(1)		(8)	%
Total	77			74			3		4	%
Electric Utility distribution sales - gwh	209			220			(11)		(5)	%
Natural gas heating degree days—% (warmer) than normal (b)	(11.2)		%	(3.0)		%	—		—

(a)Total margin represents revenues less cost of sales and ~~DVEP.~~revenue-related taxes (i.e., gross receipts and business and occupation taxes) of $4 million and $2 million, respectively, during the 2023 and 2022 three-month periods. 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).

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(b)Deviation from average heating degree days is determined on a 10-year period utilizing volume-weighted weather data based on weather statistics provided by NOAA for airports located within Gas Utility’s service territories.

Temperatures in Gas Utility’s service territories during the 2023 three-month period were 11.2% warmer than normal and 7.9% warmer than the prior-year period. The decrease in Gas Utility core market volumes during the 2023 three-month period is largely related to the significantly warmer weather, partially offset by growth in the core market customers. The decrease in Electric Utility distribution sales volumes is primarily attributable to warmer weather during the current-year period.

Utilities revenues increased $4 million in the 2023 three-month period. The increase in Gas Utility revenues ($4 million) is principally the result of the effects of the increase in base rates and the impact of the weather normalization adjustments for PA Gas Utility that went into effect during the first quarter of Fiscal 2023. These increases were partially offset by the lower core market volumes due to the warmer weather and lower off-system sales. Electric Utility revenues during the 2023 three-month period were comparable to the prior-year period.

Utilities cost of sales during the 2023 three-month period were comparable to the prior-year period for both Gas Utility and Electric Utility.

Utilities total margin increased $5 million during the 2023 three-month period largely reflecting higher Gas Utility total margin ($5 million), mainly reflecting the effects of the increase in ~~margin were~~base rates and weather normalization adjustments for PA Gas Utility that went into effect during the first quarter of Fiscal 2023, partially offset by the effects on ~~legacy business~~core market volumes of the warmer weather. Electric Utility margin was comparable to the prior-year period.

Utilities operating income and earnings before interest expense and income taxes each decreased $6 million during the 2023 three-month period. These decreases largely reflect higher operating and administrative expenses ($8 million) compared to the prior-year period partially offset by the previously mentioned increase in total ~~margin~~margin. The higher operating and administrative expenses reflects, among other things, higher uncollectible accounts expenses, contract labor costs and personnel-related expenses.

Interest Expense and Income Taxes

Our consolidated interest expense during the 2023 three-month period was $96 million compared to $82 million during the 2022 three-month period. This increase largely reflects higher credit agreement interest rates and borrowings and higher long-term debt outstanding principally at Midstream & Marketing and Utilities.

The higher effective income tax rate for the 2023 three-month period reflects the impact of the tax benefit of the goodwill impairment at AmeriGas Propane which includes a gross-up component in the associated deferred tax asset. This benefit was slightly offset by a valuation allowance adjustment and by a lower concentration of pretax loss in higher tax rate jurisdictions resulting from ~~slightly lower average LPG retail bulk~~losses on derivative instruments.

The Company continues to evaluate the elections available under current regulations and pending legislation. Accordingly, the impacts on the Company’s income tax provisions and taxes payable or refundable related to these items are subject to change.

2023 Nine-Month Period Compared with the 2022 Nine-Month Period

AmeriGas Propane


For the nine months ended June 30,	2023			2022			Increase (Decrease)
(Dollars in millions)
Revenues	$	2,147		$	2,423		$	(276)	(11)	%
Total margin (a)	$	1,080		$	1,090		$	(10)	(1)	%
Operating and administrative expenses	$	734		$	684		$	50	7	%
Operating income/earnings before interest expense and income taxes	$	240		$	303		$	(63)	(21)	%
Retail gallons sold (millions)	678			743			(65)		(9)	%
Heating degree days—% colder (warmer) than normal (b)	0.5		%	(0.8)		%	—		—

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

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~~cylinder unit margins,~~

Average temperatures during the 2023 nine-month period were 0.5% colder than normal and 1.9% colder than the prior-year period. Total retail gallons sold decreased 9% during the 2023 nine-month period due to the effects of driver staffing shortages (which also limited growth), continuing customer attrition and structural conservation.

Average daily wholesale propane commodity prices during the 2023 nine-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 40% lower than such prices during the 2022 nine-month period. Total revenues decreased $276 million during the 2023 nine-month period largely reflecting lower retail propane revenues ($220 million) primarily on the lower ~~legacy business LPG~~ retail ~~volume sales~~volumes sold ($178 million) and, to a much lesser extent, ~~slightly~~lower wholesale revenues ($52 million) and the effects of lower average retail propane selling prices ($42 million).

Total cost of sales decreased $266 million during the 2023 nine-month period largely reflecting the lower retail ~~natural gas total~~propane product costs ($112 million), the lower retail propane volumes sold ($95 million) and lower wholesale cost of sales ($53 million). Total margin ondecreased $10 million in the 2023 nine-month period largely attributable to the lower retail propane volumes sold ($83 million), largely offset by higher average retail propane unit ~~margins.~~margins ($70 million).

~~The $4.2~~Operating income and earnings before interest expense and income taxes each decreased $63 million ~~increase in UGI International operating income principally reflects~~during the ~~previously mentioned $18.3 million increase~~2023 nine-month period primarily reflecting the decrease in total margin ~~partially offset by an $8.3 million increase in~~($10 million) and higher operating and administrative ~~costs and a $4.3 million increase in depreciation and amortization expense.~~expenses ($50 million). The increase in operating and administrative expenses reflects, among other things, the higher overtime and other employee-related costs associated with distribution activity, higher vehicle expenses, higher advertising expenses and higher uncollectible accounts expenses, partially offset by lower salaries and benefits expenses, including the carryover impact from the workforce reductions made during Fiscal 2022.

UGI International


For the nine months ended June 30,	2023			2022			Increase (Decrease)
(Dollars in millions)
Revenues	$	2,436		$	3,011		$	(575)	(19)	%
Total margin (a)	$	723		$	744		$	(21)	(3)	%
Operating and administrative expenses	$	471		$	466		$	5	1	%
Operating income	$	197		$	211		$	(14)	(7)	%
Earnings before interest expense and income taxes	$	216		$	228		$	(12)	(5)	%
LPG retail gallons sold (millions)	585			651			(66)		(10)	%
Heating degree days—% (warmer) than normal (b)	(9.1)		%	(2.3)		%	—		—

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

(b)Deviation from average heating degree days is determined on a rolling 10-year period utilizing volume-weighted weather data at locations in our UGI International service territories.

Average temperatures during the 2023 nine-month period were 9.1% warmer than normal and 7.1% warmer than the prior-year period. Total LPG retail gallons sold during the 2023 nine-month period were 10% lower than the prior-year period largely attributable to the significantly warmer weather, lower consumption, principally from residential customers, primarily resulting from the European conservation measures due in large part to high global energy prices and the war between Russia and Ukraine, lower cylinder volumes and reduced crop drying campaigns, partially offset by the growth due to natural gas conversion.

UGI International base-currency results are translated into USD based upon exchange rates experienced during the reporting periods. The functional currency of a significant portion of our UGI International results is the euro and, to a much lesser extent, the British pound sterling. During the 2023 and 2022 nine-month periods, the average unweighted euro-to-USD translation rates were approximately $1.06 and $1.11, respectively, and the average unweighted British pound sterling-to-USD translation rates were approximately $1.21 and $1.32, respectively. Fluctuations in these foreign currency exchange rates can have a significant impact on the individual financial statement components discussed below. The Company uses forward foreign currency exchange contracts entered into over multi-year periods to reduce the volatility in earnings that may result from such changes in foreign currency exchange rates. These forward foreign currency exchange contracts resulted in realized net gains of $16 million and $12 million in the 2023 and 2022 nine-month periods, respectively.

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UGI International revenues and cost of sales decreased $575 million and $554 million, respectively, during the 2023 nine-month period compared to the prior-year period. Average wholesale prices for propane and butane during the 2023 nine-month period in northwest Europe were approximately 25% and 28% lower, respectively, compared with the prior-year period. The decrease in revenues and cost of sales principally reflects the impact from lower LPG retail volumes sold and the translation effects of the ~~stronger euro~~weaker foreign currencies (approximately $153 million and ~~British pound sterling on local currency expenses and approximately $10.0~~$112 million, ~~of incremental expenses from UniverGas and DVEP. These increases in operating and administrative expenses were~~respectively), partially offset by the impact from the LPG price increases. Energy marketing businesses also contributed to the decrease in revenues and cost of sales during the 2023 nine-month period primarily due to lower ~~local currency operating expenses at our legacy~~volumes sold, partially offset by the impact from price increases.

UGI International total margin decreased $21 million during the 2023 nine-month period primarily reflecting the effects of the lower LPG business reflecting, in large part, expense synergies from Finagaz integration activities and lower repairs and maintenance, LPG distribution and Finagaz integration expenses. Operating and administrative expenses in the 2017 and 2016 three-month periods include $1.9 million and $8.1 million of Finagaz integration costs, respectively. The higher depreciation and amortization reflects UniverGas and DVEPretail volumes sold ($~~2.8~~83 million) and the translation effects of the ~~stronger currencies. UGI International income before income taxes decreased $1.4 million principally reflecting the previously mentioned $4.2 million increase~~weaker foreign currencies (approximately $41 million). These factors were partially offset by higher average unit margins from our LPG business attributable to strong margin management efforts and lower commodity prices. The decrease in UGI International ~~operating income reduced by realized losses on foreign currency exchange contracts ($4.7 million) and slightly higher interest expense ($0.8 million) due to the stronger euro.~~

~~Midstream & Marketing~~

For the three months ended December 31, 2017 2016 Increase
(Dollars in millions)
Revenues $ 328.0
$ 269.8
$ 58.2
21.6 %
Total margin (a) $ 89.0
$ 78.0
$ 11.0
14.1 %
Operating and administrative expenses $ 26.7
$ 23.0
$ 3.7
16.1 %
Operating income $ 52.3
$ 49.7
$ 2.6
5.2 %
Income before income taxes $ 52.6
$ 49.1
$ 3.5
7.1 %


~~(a)~~	Total margin represents total revenues less total cost of sales. Total margin for the three months ended December 31, 2017 and 2016 excludes net pre-tax gains (losses) of $(11.1) million and $62.6 million, respectively, on Midstream & Marketing commodity derivative instruments not associated with current-period transactions.

Temperatures across Midstream & Marketing’s energy marketing territory were approximately 1.1% warmer than normal but 6.2% colder than in the prior-year period. Midstream & Marketing 2017 three-month period revenues were $58.2 million higher reflecting higher natural gas revenues ($42.0 million) and, to a much lesser extent, higher natural gas gathering and peaking revenues. The increase in natural gas revenues principally reflects the effects of higher natural gas volumes, reflecting customer growth and the colder weather, and the effects of slightly higher average natural gas prices. The increase in peaking revenues reflects an increase in the number of contracts and the effects of the colder weather while the increase in natural gas gathering revenues reflects incremental revenues from the Sunbury Pipeline, which serves a natural gas-fired electricity generation facility in central Pennsylvania and began generating revenues in late Fiscal 2017, and, to a much lesser extent, incremental revenues from a north-central Pennsylvania natural gas gathering system acquired on October 31, 2017. Midstream & Marketing cost of sales were $239.0 million in the 2017 three-month period compared to $191.8 million in the 2016 three-month period, an increase of $47.2 million, principally reflecting higher natural gas cost of sales primarily a result of the higher natural gas volumes and prices.

~~Midstream & Marketing~~ total margin ~~increased $11.0 million in the 2017 three-month period reflecting~~was partially offset by higher total margin from our ~~midstream assets~~energy marketing businesses ($~~8.0~~42 million)~~, principally~~ during the result of higher natural gas gathering and peaking total margin, and higher electricity generation total margin ($3.2 million). The increase in natural gas gathering total margin reflects incremental margin from the Sunbury Pipeline and, to a much lesser extent, margin from the recently acquired natural gas gathering assets, while the increase in peaking total margin reflects an increase in the number of contracts and the effects of the colder weather. The higher electricity generation total margin reflects higher electricity unit margins and higher electric generation volumes principally at our Hunlock Station generating facility.2023 nine-month period.

~~Midstream & Marketing~~UGI International operating income and ~~income~~earnings before interest expense and income taxes decreased $14 million and $12 million, respectively, during the ~~2017 three-month period increased $2.6 million and $3.5 million, respectively.~~2023 nine-month period. The ~~increase~~decrease in operating income principally reflects the previously mentioned $21 million decrease in total margin, lower gains associated with sales of assets ($11 million) and higher operating and administrative expenses ($5 million). These decreases were partially offset by higher foreign currency transaction gains ($11 million), higher other operating income ($7 million) and lower depreciation and amortization expenses ($3 million). The higher operating and administrative expenses in the 2023 nine-month period primarily reflects the effects of inflationary increases, largely offset by the translation effects of the weaker foreign currencies (approximately $25 million). The decrease in earnings before interest expense and income taxes in the 2023 nine-month period largely reflects the $14 million decrease in operating income partially offset by higher realized gains on foreign currency exchange contracts entered into in order to reduce volatility in UGI International earnings resulting from the effects of changes in foreign currency exchange rates ($4 million).

Midstream & Marketing


For the nine months ended June 30,	2023		2022		Increase (Decrease)
(Dollars in millions)
Revenues	$	1,586	$	1,731	$	(145)	(8)	%
Total margin (a)	$	401	$	342	$	59	17	%
Operating and administrative expenses	$	95	$	88	$	7	8	%
Operating income	$	249	$	197	$	52	26	%
Earnings before interest expense and income taxes	$	253	$	216	$	37	17	%

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

Average temperatures across Midstream & Marketing’s energy marketing territory during the 2023 nine-month period were 11.0% warmer than normal and 5.8% warmer than the prior-year period.

Midstream & Marketing revenues decreased $145 million compared to the prior-year period, primarily reflecting lower revenues from natural gas marketing activities ($213 million), including the effects of peaking and capacity management activities, that were primarily impacted by lower natural gas prices and lower volumes from the warmer weather. This decrease was partially offset by higher natural gas gathering and processing activities ($40 million), primarily due to the impact on revenues from the prior-year acquisitions of UGI Moraine East and Pennant and higher retail power marketing revenues ($26 million).

Midstream & Marketing cost of sales decreased $204 million compared to the prior-year period, primarily reflecting the lower natural gas costs ($233 million) related to the previously mentioned natural gas marketing activities partially offset by higher cost of sales related to retail power marketing activities.

Midstream & Marketing total margin increased $59 million in the 2023 nine-month period reflecting incremental natural gas gathering and processing activities ($43 million), primarily from the prior year acquisitions of UGI Moraine East and Pennant; and higher margins from natural gas marketing activities ($20 million), including the effects of peaking and capacity management activities that benefited from extremely cold weather in late December.

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Midstream & Marketing operating income and earnings before interest expense and income taxes during the 2023 nine-month period increased $52 million and $37 million, respectively, compared to the prior-year period. The increase in operating income is largely attributable to the previously mentioned $59 million increase in total margin and higher other income ($~~11.0~~7 million), partially offset by higher operating and administrative expense ($7 million) and higher depreciation and amortization ($8 million). The increase in earnings before interest expense and income taxes principally reflects the increase in operating income, partially offset by lower income from equity investees following the acquisition of the remaining 53% ownership interest in Pennant during the fourth quarter of Fiscal 2022.

Utilities


For the nine months ended June 30,	2023			2022			Increase (Decrease)
(Dollars in millions)
Revenues	$	1,644		$	1,400		$	244	17	%
Total margin (a)	$	750		$	681		$	69	10	%
Operating and administrative expenses (a)	$	275		$	250		$	25	10	%
Operating income	$	361		$	325		$	36	11	%
Earnings before interest expense and income taxes	$	367		$	332		$	35	11	%
Gas Utility system throughput—bcf
Core market	90			94			(4)		(4)	%
Total	296			290			6		2	%
Electric Utility distribution sales - gwh	712			746			(34)		(5)	%
Gas Utility heating degree days—% (warmer) than normal (b)	(11.6)		%	(7.6)		%	—		—

(a)Total margin represents revenues less cost of sales and revenue-related taxes (i.e., gross receipts and business and occupation taxes) of $21 million and $18 million, respectively, during the 2023 and 2022 nine-month periods. 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).

Temperatures in Gas Utility’s service territories during the 2023 nine-month period were 11.6% warmer than normal and 4.6% warmer than the prior-year period. The decrease in Gas Utility core market volumes during the 2023 nine-month period is largely related to the warmer weather partially offset by growth in the core market customers. The decrease in Electric Utility distribution sales volumes is primarily attributable to warmer weather during the 2023 nine-month period.

Utilities revenues increased $244 million in the 2023 nine-month period reflecting a $230 million increase in Gas Utility revenues and a $14 million increase in Electric Utility revenues. The increase in Gas Utility revenues was largely driven by higher PGC and PGA rates reflecting higher natural gas costs; the effects of the increase in base rates and weather normalization adjustments for PA Gas Utility that went into effect during the first quarter of Fiscal 2023; higher off-system sales; and higher other revenues. These increases were partially offset by the effects on core market volumes of the warmer weather. The increase in Electric Utility revenues was largely driven by higher DS rates reflecting higher power costs.

Utilities cost of sales increased $175 million in the 2023 nine-month period primarily attributable to Gas Utility ($159 million) mainly reflecting higher PGC and PGA rates, higher cost of sales associated with off-system sales and higher other cost of sales. Electric Utility cost of sales increased $16 million during the 2023 nine-month period largely reflecting the higher DS rates.

Utilities total margin increased $69 million during the 2023 nine-month period primarily attributable to higher Gas Utility total margin ($71 million) mainly reflecting the effects of the increase in base rates and weather normalization adjustments for PA Gas Utility that went into effect during the first quarter of Fiscal 2023 and, to a much lesser extent, impacts from growth in the core market customers and higher other revenues. Electric Utility margin was comparable to the prior-year period.

Utilities operating income and earnings before interest expense and income taxes increased $36 million and $35 million, respectively, during the 2023 nine-month period. These increases largely reflect the previously mentioned increase in total margin partially offset by higher operating and administrative expenses ($~~3.7~~25 million), and higher depreciation expense ($2.1 million), and a $2.7 million decrease in other operating income primarily from the absence of AFUDC income associated with the Sunbury Pipeline project recorded in the prior-year period. The $3.7 million increase in operating and administrative expenses reflects higher wage and benefits expense and higher expenses associated with greater peaking and gas gathering activities, while the increase in depreciation expense principally reflects incremental depreciation from the expansion

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UGI CORPORATION AND SUBSIDIARIES

of our natural gas pipeline and peaking assets. The increase in income before income taxes in the 2017 three-month period reflects the higher operating income and $1.2 million of income from our PennEast pipeline equity investment reflecting AFUDC income.

~~UGI Utilities~~

For the three months ended December 31, 2017 2016 Increase
(Dollars in millions)
Revenues $ 323.1
$ 261.4
$ 61.7
23.6 %
Total margin (a) $ 170.0
$ 150.6
$ 19.4
12.9 %
Operating and administrative expenses $ 54.7
$ 52.3
$ 2.4
4.6 %
Operating income $ 96.3
$ 82.2
$ 14.1
17.2 %
Income before income taxes $ 85.4
$ 72.2
$ 13.2
18.3 %
Gas Utility system throughput—billions of cubic feet (“bcf”)
Core market 25.5
23.0
2.5
10.9 %
Total 69.2
66.2
3.0
4.5 %
Electric Utility distribution sales - millions of kilowatt hours (“gwh”) 246.6
240.6
6.0
2.5 %
Gas Utility heating degree days—% (warmer) than normal (b) (1.9 )% (6.3 )% —
—


~~(a)~~	Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e., Electric Utility gross receipts taxes, of $1.3 million during each of the three months ended December 31, 2017 and 2016, respectively. For financial statement purposes, revenue-related taxes are included in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income.


~~(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.~~

Temperatures in Gas Utility’s service territory during the three months ended December 31, 2017, were 1.9% warmer than normal but 6.0% colder than during the three months ended December 31, 2016. Gas Utility core market volumes increased 2.5 bcf (10.9%) principally reflecting the effects of the colder 2017 three-month period weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 3.0 bcf principally reflecting the higher core market volumes and slightly higher large firm delivery service volumes. These increases were partially offset by lower interruptible delivery service volumes. Electric Utility kilowatt-hour sales were 2.5% higher than the prior-year period, principally reflecting the impact of the colder weather on Electric Utility heating-related sales.

UGI Utilities revenues increased $61.7 million reflecting a $62.9 million increase in Gas Utility revenues partially offset by slightly lower Electric Utility revenues. The higher Gas Utility revenues principally reflect an increase in core market revenues ($48.1 million), higher off-system sales revenues ($11.5 million), and higher large firm delivery service revenues ($4.4 million). The $48.1 million increase in Gas Utility core market revenues reflects the effects of the higher core market throughput ($18.8 million), higher average retail core market PGC rates ($25.3 million) and the increase in PNG base rates effective October 20, 2017 ($4.0 million). The decrease in Electric Utility revenues principally reflects slightly lower average DS rates ($1.3 million) and lower transmission revenue ($0.4 million) partially offset by the higher Electric Utility volumes. UGI Utilities cost of sales was $151.8 million in the three months ended December 31, 2017 compared with $109.5 million in the three months ended December 31, 2016, principally reflecting higher Gas Utility cost of sales ($43.3 million) partially offset by lower Electric Utility cost of sales ($1.0 million) from lower DS rates. The higher Gas Utility cost of sales reflects higher average retail core market PGC rates ($22.6 million), higher cost of sales associated with Gas Utility off-system sales ($11.5 million), and higher retail core-market volumes ($9.2 million).

UGI Utilities total margin increased $19.4 million principally reflecting higher total margin from Gas Utility core market customers ($16.4 million) and higher large firm delivery service total margin ($3.8 million). The increase in Gas Utility core market margin principally reflects the higher core market throughput ($12.3 million) and the increase in PNG base rates effective October 20, 2017 ($4.0 million). Electric Utility total margin decreased slightly principally reflecting the lower transmission revenue.

~~UGI Utilities operating income increased $14.1 million, principally reflecting the increase in total margin ($19.4 million) partially offset by~~ higher operating and administrative expenses ~~($2.4 million)~~reflect, among other things, higher uncollectible accounts expenses, contract labor costs and ~~greater~~personnel-related expenses. The higher depreciation ~~and amortization~~ expense ~~($3.0 million) associated with increased~~compared to the prior-year period reflects the effects of continued distribution system capital expenditure activity. The increase in UGI Utilities operating and administrative expenses reflects higher distribution expenses ($1.8 million), higher uncollectible accounts expense ($1.0 million) and higher information technology expenses ($0.7 million) partially offset by a favorable payroll tax adjustment related to prior periods ($2.1 million).

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~~UGI CORPORATION AND SUBSIDIARIES~~

~~UGI Utilities income before income taxes increased $13.2 million reflecting the increase in UGI Utilities operating income ($14.1 million) partially offset by slightly higher interest expense.~~

Interest Expense and Income Taxes

Our consolidated interest expense during the ~~2017 three-month~~2023 nine-month period was ~~$58.2~~$281 million ~~$2.8~~compared to $245 million ~~higher than the $55.4 million of interest expense recorded~~ during the ~~2016 three-month~~2022 nine-month period. ~~The~~This increase largely reflects higher credit agreement interest ~~expense principally reflects the effects of~~rates and borrowings and higher long-term debt outstanding principally at ~~AmeriGas Propane~~Midstream & Marketing and ~~UGI~~ Utilities. ~~These increases were partially offset by lower average interest rates on long-term debt at AmeriGas Propane.~~

As previously mentioned, our consolidated income taxes for the three months ended December 31, 2017, were significantly impacted by the enactment of the TCJA and the December 2017 French Finance Bills. Accordingly, the effective tax rate as calculated based upon amounts on our condensed consolidated statement of income for the 2017 three-month period includes the effects of one-time discrete adjustments to deferred income tax assets and liabilities, accrued income taxes and deferred tax valuation allowances which reduced income tax expense by $183.3 million.

The effective income tax rate in the 2016 three-month period reflects the impact of a December 2016 change in the French corporate income tax rate for future years which reduced consolidated income tax expense by $27.4 million and, to a much lesser extent, the effects of an income tax settlement refund of $6.7 million, plus interest, in France.

~~Excluding the impacts of the one-time discrete adjustments from the TCJA and French tax rate changes in both periods as noted above, our~~lower effective income tax rate for the ~~2017 three-month~~2023 nine-month period ~~was lower than~~reflects the impact of the tax benefit of the goodwill impairment at AmeriGas Propane which includes a gross-up component in the ~~prior-year period principally reflecting the lower blended U.S.~~associated deferred tax asset. The current year income tax rate also includes the projected availability of ~~24.5%~~investment tax credits in Fiscal ~~2018 resulting from the~~2023 following enactment of the ~~TCJA.~~Inflation Reduction Act in August 2022. These benefits were slightly offset by a greater concentration of pretax loss in higher tax rate jurisdictions resulting from losses on derivative instruments and adjustments to deferred tax valuation allowances.

FINANCIAL CONDITION AND LIQUIDITY

The Company expects to have sufficient liquidity, including cash on hand and available borrowing capacity, to continue to support long-term commitments and ongoing operations despite uncertainties associated with ongoing global macroeconomic conditions including, among others, changes in consumer behavior resulting from the COVID-19 pandemic, the inflationary cost environment and ongoing energy commodity price volatility. Our total available liquidity balance, comprising cash and cash equivalents and available borrowing capacity on our revolving credit facilities, totaled approximately $1.8 billion and $1.7 billion at June 30, 2023 and September 30, 2022, respectively. Our total available liquidity at June 30, 2023 increased due to higher available borrowing capacity on our revolving credit facilities, partially offset by the impact of cash collateral payments associated with a significant decline in commodity prices during the 2023 nine-month period and increases in restricted cash margin requirements in commodity futures brokerage accounts, principally at UGI International. The Company does not have any senior note or term loan maturities in the next twelve months. The Company cannot predict the duration or total magnitude of the uncertain economic factors mentioned above and the total effects they will have on its liquidity, debt covenants, financial condition or the timing of capital expenditures. UGI and its subsidiaries were in compliance with all debt covenants as of June 30, 2023. See Note 8 to the Condensed Consolidated Financial Statements for additional information on the equity cure provision.

We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities and, in the case of Midstream & Marketing, also from a Receivables Facility. Long-term cash requirements are generally met through the issuance of long-term debt or equity securities. We believe that each of our business units has sufficient liquidity in the forms of cash and cash equivalents on hand; cash expected to be generated from operations; credit facility and ~~Receivable~~Receivables Facility ~~borrowings;~~borrowing capacity; and the ability to obtain long-term financing to meet anticipated contractual and projected cash commitments. Issuances of debt and equity securities in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.

The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business units. Our cash and cash equivalents totaled ~~$446.4~~$260 million at ~~December 31, 2017,~~June 30, 2023, compared with ~~$558.4~~$405 million at September 30, ~~2017.~~2022. The decrease in cash and cash equivalents since September 30, 2022 is primarily attributable to commodity price volatility experienced in the 2023 nine-month period and the seasonality of our business as further described in “Cash Flows” below. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at ~~December 31, 2017~~June 30, 2023 and September 30, ~~2017,~~2022, UGI had ~~$162.0~~$35 million and ~~$291.1~~$140 million of cash and cash equivalents, ~~respectively, most of which are located in the U.S.~~respectively. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.

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UGI CORPORATION AND SUBSIDIARIES

Long-term Debt and ~~Short-term Borrowings~~Credit Facilities

Long-term Debt

The Company’s debt outstanding at ~~December 31, 2017~~June 30, 2023 and September 30, ~~2017,~~2022, comprises the following:


	June 30, 2023												September 30, 2022
(Millions of dollars)	AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corp & Other		Total		Total
Short-term borrowings	$	—	$	245	$	70	$	166	$	—	$	481	$	368

Long-term debt (including current maturities):
Senior notes	$	2,400	$	437	$	—	$	1,505	$	—	$	4,342	$	4,472
Term loans	—		327		796		130		738		1,991		1,871
Other long-term debt	—		4		41		21		283		349		322
Unamortized debt issuance costs	(16)		(8)		(15)		(6)		(2)		(47)		(33)
Total long-term debt	$	2,384	$	760	$	822	$	1,650	$	1,019	$	6,635	$	6,632
Total debt	$	2,384	$	1,005	$	892	$	1,816	$	1,019	$	7,116	$	7,000

December 31, 2017 September 30, 2017
(Currency in millions) AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Other Total Total
Short-term borrowings (a) $ 263.5
$ 41.1
$ 100.0
$ 181.5
$ —
$ 586.1
$ 366.9

Long-term debt (including current maturities):
Senior notes $ 2,575.0
$ —
$ —
$ 675.0
$ —
$ 3,250.0
$ 3,250.0
Term loans and notes —
825.1
—
185.0
—
1,010.1
902.1
Other long-term debt 27.3
22.2
0.5
—
9.2
59.2
59.8
Unamortized debt issuance costs (30.4 ) (4.0 ) —
(4.4 ) —
(38.8 ) (39.8 )
Total long-term debt $ 2,571.9
$ 843.3
$ 0.5
$ 855.6
$ 9.2
$ 4,280.5
$ 4,172.1
Total debt $ 2,835.4
$ 884.4
$ 100.5
$ 1,037.1
$ 9.2
$ 4,866.6
$ 4,539.0


~~(a)~~	~~Short-term borrowings at UGI International as of December 31, 2017, primarily comprise bank overdrafts at UGI France SAS.~~

~~UGI International.~~ In December 2017, Flaga repaid $9.2 million of the outstanding principal amount of its then-existing $59.1 million U.S. dollar denominated variable-rate term loan due September 2018. Concurrently, Flaga entered into an amendment to the aforementioned term loan, which amends and restates the previous agreement to provide for a principal balance of $49.9 million and extends the maturity of the term loan to April 2020 (“Flaga Term Loan”). The outstanding principal bears interest at the one-month LIBOR rate plus a margin of 1.125%. Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the Flaga Term Loan, by entering into a cross-currency swap arrangement with a bank.

~~UGI Utilities.~~ In October 2017, UGI Utilities entered into a $125 million unsecured variable-rate term loan agreement (the “Utilities Term Loan”) with a group of banks which initially matures on October 30, 2018. Such maturity will be automatically extended to October 30, 2022, after UGI Utilities receives a securities certificate from the PUC authorizing issuance of the security and upon delivery of such certificate to the agent. Proceeds from the Utilities Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Utilities Term Loan is payable in equal quarterly installments of $1.6 million with the balance of the principal being due and payable in full on the maturity date. Under the Utilities Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities.

Credit Facilities

Additional information related to the Company’s credit agreements can be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Note 58 to ~~the~~ Consolidated Financial Statements in the Company’s ~~2017~~2022 Annual Report.

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~~UGI CORPORATION AND SUBSIDIARIES~~

Information about the Company’s principal credit agreements (excluding the ~~Energy Services~~ Receivables Facility discussed below) as of ~~December 31, 2017~~June 30, 2023 and ~~2016,~~2022, is presented in the table below.


(Currency in millions)	Total Capacity		Borrowings Outstanding		Letters of Credit and Guarantees Outstanding		Available Borrowing Capacity
As of June 30, 2023
AmeriGas OLP	$	600	$	—	$	2	$	598
UGI International, LLC (a)	€	500	€	225	€	—	€	275
Energy Services	$	260	$	25	$	—	$	235
UGI Utilities	$	425	$	108	$	—	$	317
Mountaineer	$	150	$	58	$	—	$	92
UGI Corporation (b)	$	300	$	283	$	—	$	17
As of June 30, 2022
AmeriGas OLP	$	600	$	50	$	3	$	547
UGI International, LLC (a)	€	300	€	—	€	—	€	300
Energy Services	$	260	$	—	$	—	$	260
UGI Utilities	$	350	$	170	$	—	$	180
Mountaineer	$	100	$	55	$	—	$	45
UGI Corporation (b)	$	300	$	230	$	—	$	70

(a)Permits UGI International, LLC to borrow in euros or USD. At June 30, 2023, the amount borrowed consisted of euro-denominated borrowings equivalent to $245 million.

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

(Currency in millions) Total Capacity Borrowings Outstanding Letters of Credit and Guarantees Outstanding Available Borrowing Capacity
As of December 31, 2017
AmeriGas OLP $ 600.0
$ 263.5
$ 67.2
$ 269.3
UGI International, LLC € 300.0
€ —
€ —
€ 300.0
UGI France SAS € 60.0
€ —
€ —
€ 60.0
Flaga (a) € 55.0
€ —
€ 1.0
€ 54.0
Energy Services, LLC $ 240.0
$ 55.0
$ —
$ 185.0
UGI Utilities $ 300.0
$ 181.5
$ 2.0
$ 116.5
As of December 31, 2016
AmeriGas OLP $ 525.0
$ 77.5
$ 67.2
$ 380.3
UGI France SAS € 60.0
€ —
€ —
€ 60.0
Flaga (a) € 55.0
€ —
€ 8.0
€ 47.0
Energy Services, LLC $ 240.0
$ 20.0
$ —
$ 220.0
UGI Utilities $ 300.0
$ 98.4
$ 2.0
$ 199.6

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~~(a)~~	Total capacity comprises a €25 million multi-currency revolving credit facility, a €5 million overdraft facility and a €25 million guarantee facility. Guarantees outstanding reduce the available capacity on the €25 million guarantee facility.

UGI CORPORATION AND SUBSIDIARIES

The average daily and peak short-term borrowings under the Company’s principal credit agreements ~~during the three months ended December 31, 2017 and 2016~~ are as follows:


	For the nine months ended				For the nine months ended
	June 30, 2023				June 30, 2022
(Millions of dollars or euros)	Average		Peak		Average		Peak
AmeriGas OLP	$	105	$	242	$	203	$	388
UGI International, LLC	€	194	€	300	€	100	€	250
Energy Services	$	9	$	82	$	—	$	—
UGI Utilities	$	202	$	340	$	178	$	270
Mountaineer	$	74	$	101	$	49	$	80
UGI Corporation	$	239	$	292	$	181	$	288

For the three months ended
December 31, 2017 For the three months ended
December 31, 2016
(Currency in millions) Average Peak Average Peak
AmeriGas OLP $ 199.0
$ 286.0
$ 191.6
$ 292.5
UGI International, LLC € —
€ —
€ —
€ —
UGI France SAS € —
€ —
€ —
€ —
Flaga € —
€ —
€ —
€ —
Energy Services, LLC $ 44.7
$ 79.0
$ 18.3
$ 28.0
UGI Utilities $ 168.1
$ 205.0
$ 96.6
$ 137.0

~~AmeriGas Partners.~~ In December 2017, AmeriGas Partners entered into the Second Amended and Restated Credit Agreement (“AmeriGas Credit Agreement”) with a group of banks. The AmeriGas Credit Agreement amends and restates a previous credit agreement. The AmeriGas Credit Agreement provides for borrowings up to $600 million (including a $150 million sublimit for letters of credit) and expires in December 2022. The AmeriGas Credit Agreement permits AmeriGas to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin. Under the AmeriGas Credit Agreement, the applicable margin on base rate borrowings ranges from 0.50% to 1.75%; the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.75%; and the facility fee ranges from 0.30% to 0.50%.

~~UGI International.~~ In December 2017, UGI International, LLC, a wholly owned subsidiary of UGI, entered into a secured multicurrency revolving facility agreement (the "UGI International Credit Agreement") with a group of banks providing for borrowings up to €300 million. The UGI International Credit Agreement is scheduled to expire in April 2020. Under the UGI International Credit Agreement, UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus a margin ranging from 1.45% to 2.35%. Loans made in U.S. dollars will bear interest at LIBOR plus a margin ranging from 1.70% to 2.60%.

~~Midstream & Marketing.~~ Receivables Facility. Energy Services ~~LLC~~ has a ~~receivables purchase facility (“~~Receivables ~~Facility”)~~Facility with an issuer of receivables-backed commercial paper currently scheduled to expire in October ~~2018. At December 31, 2017,~~2023. The Receivables Facility provides Energy Services with the ~~outstanding balance of ESFC trade receivables was $101.0~~ability to borrow up to $150 million of eligible receivables during the period October 21, 2022 to April 30, 2023, and up to $75 million of eligible receivables during the period May 1, 2023 to October 20, 2023. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.

Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, ESFC, which ~~$45.0 million was~~is consolidated for financial statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time sell, an undivided interest in some or all of the ~~bank. At December 31, 2016, the~~

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~~outstanding balance of ESFC trade~~ receivables ~~was $81.4 million and there were $35.0 million amounts sold~~ to ~~the~~a major bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable.

At June 30, 2023, the outstanding balance of ESFC trade receivables was $62 million, $45 million of which were sold to the bank. At June 30, 2022, the outstanding balance of ESFC trade receivables was $88 million, none of which was sold to the bank. During the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2023 and ~~2016,~~2022, peak sales of receivables were ~~$45.0~~$150 million and ~~$36.5~~$98 million, respectively, and average daily amounts sold were ~~$28.6~~$44 million and ~~$23.7~~$2 million, respectively. ~~For additional information regarding~~

Significant Financing Activities

The following significant financing activities occurred during the ~~Receivables Facility, see~~2023 nine-month period. See Note 8 to Condensed Consolidated Financial Statements for additional information on these transactions.

AmeriGas Partners Senior Notes. On May 31, 2023, AmeriGas Partners and AmeriGas Finance Corp. issued $500 million principal amount of 9.375% Senior Notes due May 2028. The 9.375% Senior Notes rank equally with AmeriGas Partners’ existing and future outstanding senior notes. The net proceeds from the ~~condensed consolidated~~issuance of the 9.375% Senior Notes, together with cash on hand, a $150 million cash contribution from the Company and other sources of liquidity, were used for the early repayment, pursuant to a tender offer and notice of redemption, of all AmeriGas Partners 5.625% Senior Notes having an aggregate principal balance of $675 million, plus tender premiums and accrued and unpaid interest. In conjunction with the early repayment of the 5.625% Senior Notes, in June 2023 the Partnership recognized a pre-tax loss of $9 million primarily comprising tender premiums and the write-off of unamortized debt issuance costs, which is reflected in “Loss on extinguishments of debt” on the Condensed Consolidated Statements of Income.

2022 AmeriGas OLP Credit Agreement. Under the 2022 AmeriGas OLP Credit Agreement, AmeriGas OLP, as borrower, is required to comply with financial ~~statements.~~covenants related to leverage and interest coverage measured at the Partnership and at AmeriGas OLP. The 2022 AmeriGas OLP Credit Agreement contains an equity cure provision, which allows AmeriGas OLP’s direct or indirect parent, including UGI and its other subsidiaries, to fund capital contributions to eliminate any EBITDA (as defined in the 2022 AmeriGas OLP Credit Agreement) shortfalls that would otherwise result in non-compliance with these financial covenants. Each equity cure is eligible to eliminate such EBITDA shortfalls up to four quarters after contribution. We are permitted to use the equity cure provision five times over the course of the Credit Agreement, twice during any rolling four-quarter period, and not in consecutive quarters.

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UGI CORPORATION AND SUBSIDIARIES

As of March 31, 2023, AmeriGas OLP was in breach of the leverage ratio debt covenant and interest coverage ratio, which it cured with the funds received from UGI. UGI made capital contributions to AmeriGas OLP of $20 million and $11 million on March 31, 2023 and April 24, 2023, respectively, which in aggregate represented one equity cure in accordance with the 2022 AmeriGas OLP Credit Agreement. As a result of these capital contributions, AmeriGas OLP and the Partnership were in compliance with all financial covenants after consideration of the equity cure provision as of June 30, 2023 and March 31, 2023.

UGI also provided an irrevocable letter of support whereby UGI has committed to fund any such EBITDA shortfalls and debt service, if any. Based on the support and the projected EBITDA, AmeriGas OLP is expected to remain in compliance with its financial debt covenants for the succeeding twelve-month period. In addition, in May 2023, the Company contributed $52 million in an equity contribution principally to fund debt service on the senior notes.

UGI International 2023 Credit Facilities Agreement. On March 7, 2023, UGI International, LLC and its indirect wholly-owned subsidiary, UGI International Holdings B.V., entered into the UGI International 2023 Credit Facilities Agreement, a five-year unsecured senior facilities agreement, maturing March 7, 2028, with a consortium of banks. The UGI International 2023 Credit Facilities Agreement consists of (1) a €300 million variable-rate term loan facility ("Facility A") and (2) a €500 million multicurrency revolving credit facility, including a €100 million sublimit for swingline loans ("Facility B"). We have designated borrowings under Facility A as a net investment hedge. In connection with the entering into of the UGI International 2023 Credit Facilities Agreement, UGI International, LLC paid off in full and terminated the UGI International Credit Facilities Agreement, dated as of October 18, 2018. The net proceeds from the UGI International 2023 Credit Facilities Agreement were used to refinance the UGI International Credit Facilities Agreement. Borrowings under the multicurrency revolving credit facility may be used to finance the working capital needs of UGI International, LLC and its subsidiaries and for general corporate purposes.

UGI Energy Services Credit Agreement. On May 12, 2023, Energy Services entered into the second amendment to the UGI Energy Services Credit Agreement, which provides that the Term SOFR rate (as defined in the UGI Energy Services Credit Agreement) shall replace LIBOR as a reference rate. After giving effect to the second amendment, the UGI Energy Services Credit Agreement shall bear interest at a floating rate of, at Energy Services’ option, either (i) Term SOFR plus the Applicable Rate (as defined in the UGI Energy Services Credit Agreement) plus a credit spread adjustment of 0.10%, or (ii) the base rate plus the Applicable Rate. The Applicable Rate will be based on the leverage of Energy Services.

UGI Utilities Credit Agreement. On December 13, 2022, UGI Utilities entered into an amendment to the UGI Utilities Credit Agreement, providing for borrowings up to $425 million and to replace the use of LIBOR with Term SOFR. Borrowings under the amended UGI Utilities Credit Agreement can be used to finance the working capital needs of UGI Utilities and for general corporate purposes. The UGI Utilities Credit Agreement is scheduled to expire June 2024.

Mountaineer Credit Agreement. On October 20, 2022, Mountaineer entered into the Mountaineer 2023 Credit Agreement, with a group of lenders. The Mountaineer 2023 Credit Agreement amends and restates a previous credit agreement and provides for borrowings up to $150 million, including a $20 million sublimit for letters of credit. Mountaineer may request an increase in the amount of loan commitments to a maximum aggregate amount of $250 million, subject to certain terms and conditions. Borrowings under the Mountaineer 2023 Credit Agreement can be used to finance the working capital needs of Mountaineer and for general corporate purposes. The Mountaineer 2023 Credit Agreement is scheduled to expire in November 2024, with an option to extend the maturity date.

UGI Corporation Credit Agreement. On May 12, 2023, the Company entered into the second amendment to the UGI Corporation Credit Agreement, which provides that the Term SOFR rate (as defined in the UGI Corporation Credit Agreement) shall replace LIBOR as a reference rate. After giving effect to the second amendment, the UGI Corporation Credit Agreement shall bear interest at a floating rate of, at the Company’s option, either (i) Term SOFR plus the Applicable Rate (as defined in the UGI Corporation Credit Agreement) plus a credit spread adjustment of 0.10%, or (ii) the base rate plus the applicable margin that will be based on the leverage of the Company or credit ratings assigned to certain indebtedness of the Company.

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The Company is pursuing the refinancing of the UGI Corporation revolving credit facility, which matures August 1, 2024. The UGI Corporation revolving credit facility contains a leverage ratio debt covenant which the Company was in compliance with as of June 30, 2023, and expects to maintain compliance through the August 1, 2024 maturity date. The Company has other sources of liquidity currently available which would be sufficient to repay the maturing credit facility should a refinancing not be successful.

Dividends and ~~Distributions~~Repurchases of Common Stock

On November ~~29, 2017,~~17, 2022, UGI’s Board of Directors declared a cash dividend equal to ~~$0.25~~$0.36 per common share. The dividend was paid on January 1, ~~2018,~~2023, to shareholders of record on December 15, ~~2017.~~2022. On ~~January 25, 2018,~~February 1, 2023, UGI’s Board of Directors declared a quarterly dividend of ~~$0.25~~$0.36 per common share. The dividend was paid on April 1, 2023, to shareholders of record on March 15, 2023. On May 3, 2023, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.375 per common share, or $1.50 on an annual basis. The new dividend rate reflects an approximate 4.2% increase from the previous quarterly rate of $0.36. The dividend was paid on July 1, 2023, to shareholders of record on June 15, 2023. On August 2, 2023, UGI’s Board of Directors declared a quarterly dividend of $0.375 per common share. The dividend is payable ~~April~~October 1, ~~2018,~~2023, to shareholders of record on ~~March~~September 15, ~~2018.~~2023.

During the three months ended December 31, 2017, the General Partner’s Board of Directors declared and the Partnership paid a quarterly distribution on all limited partner units at a rate of $0.95 per Common Unit for the quarter ended September 30, 2017. On January 24, 2018, the General Partner’s Board of Directors approved a quarterly distribution of $0.95 per limited partner unit for the quarter ended December 31, 2017. The distribution will be paid on February ~~20, 2018, to unitholders of record on February 9, 2018.~~

~~Repurchase of Common Stock~~

In January 2014, UGI’s Board of Directors authorized a share repurchase program for up to 15 million shares of UGI Corporation Common Stock. The authorization permitted the execution of the share repurchase program over a four-year period, expiring in January 2018. On January 25, 2018,2, 2022, UGI’s Board of Directors authorized an extension of ~~the~~an existing share repurchase program for up to 8 million shares of UGI ~~Corporation~~ Common Stock for an additional four-year ~~period.~~period, expiring in February 2026. Pursuant to such authorization, during the nine months ended June 30, 2023, the Company purchased 0.6 million shares on the open market at a total purchase price of approximately $22 million. The Company did not repurchase any shares during the third quarter of Fiscal 2023.

Cash Flows

Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the fourth and first fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest.

Operating Activities.Year-to-year variations in our cash flows from operating activities can be significantly affected by changes in operating working capital, especially during periods with significant changes in energy commodity prices. Cash flow provided by operating activities was ~~$31.4~~$857 million in the ~~2017 three-month~~2023 nine-month period compared to ~~$126.6~~$848 million in the ~~2016 three-month~~2022 nine-month period. Cash flow from operating activities before changes in operating working capital was ~~$384.6~~$1,209 million in the ~~2017 three-month~~2023 nine-month period compared to ~~$333.9~~$1,114 million in the ~~prior-year~~2022 nine-month period. The higher cash flow from operating activities before changes in operating working capital reflects the positive effects on cash flow of higher net income (after adjusting net income for the previously mentioned one-time impacts of the enactment of the TCJA and changes in French tax laws on tax-related accounts in 2017 ($183.3 million) and in 2016 ($27.4 million); the non-cash effects of changes in unrealized gains and losses on derivative instruments; and the loss on extinguishments of debt at AmeriGas Partners, the cash flow effects of which are reflected in cash flows from financing activities). Cash used to fund changes in operating working capital totaled ~~$353.2~~$352 million in the ~~2017 three-month~~2023 nine-month period compared to ~~$207.3~~$266 million in the ~~prior-year~~2022 nine-month period. The ~~higher~~increase in cash used to fund operating working capital changes in the 2023 nine-month period principally reflects a significant increase in collateral payments on derivative instruments during the 2023 nine-month period and greater cash required to fund changes in accounts ~~receivable and inventories reflects,~~payable. These increases in cash used to fund changes in operating working capital were offset in large part by greater 2023 nine-month period cash from changes in accounts receivable and inventories. These changes in working capital items largely reflect the ~~impact~~impacts of ~~higher LPG and natural gas costs~~the previously mentioned significant decrease in commodity energy prices during the ~~current-year period.~~2023 nine-month period, principally at our UGI International operations.

Investing Activities.~~Cash flow used by investing activities was $327.5 million in the 2017 three-month period compared with $192.4 million in the prior-year period.~~ Investing activity cash flow is principally affected by cash expenditures for property, plant and equipment; cash paid for acquisitions of ~~businesses; changes in restricted cash balances;~~businesses and assets; investments in equity method investees; and cash proceeds from sales and retirements of ~~assets~~property, plant and ~~businesses.~~equipment. Cash ~~payments~~flow used by investing activities was $761 million in the 2023 nine-month period compared to $717 million in the 2022 nine-month period. Cash expenditures for property, plant and equipment were ~~$147.5~~$670 million in the ~~2017 three-month~~2023 nine-month period compared with $551 million in the 2022 nine-month period principally reflecting higher cash capital expenditures in our Utilities segment and, to a lesser extent, Midstream & Marketing. Cash flows from investing activities include cash received from the settlement of certain forward foreign currency contracts previously designated as net investment hedges of $22 million in the 2023 nine-month period compared to ~~$197.1~~$26 million in the ~~prior-year~~2022 nine-month period. ~~Cash payments~~Investments in equity method investments during the ~~prior-year included capital expenditures associated with the Sunbury Pipeline project~~2023 nine-month period include our continuing investments in renewable energy projects principally at Midstream & Marketing. ~~Cash~~Prior-year cash flows from investing activities include cash used for ~~acquisitions of businesses and assets in~~ the ~~2017 three-month period principally reflects the acquisition of UniverGas at UGI International and the acquisition of a natural gas gathering system in northern Pennsylvania at Midstream & Marketing.~~Stonehenge Acquisition.

Financing Activities. ~~Cash flow provided by financing activities was $181.1 million in the 2017 three-month period compared with $98.6 million in the prior-year period.~~ Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; net short-term borrowings; dividends ~~and distributions~~ on UGI Common ~~Stock~~Stock; quarterly payments on outstanding Purchase Contracts; and ~~AmeriGas Partners Common Units;~~issuances and ~~from time to time, issuances~~repurchases of ~~UGI and AmeriGas Partners~~ equity instruments. ~~In October 2017,~~

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Cash flow used by financing activities was $244 million in the 2023 nine-month period compared to $290 million in the 2022 nine-month period. The 2023 nine-month period includes the cash flow effects from entering into the previously mentioned UGI ~~Utilities issued $125 million~~International 2023 Credit Facilities Agreement and the concurrent repayment of ~~unsecured notes~~borrowings under the UGI International Credit Facilities Agreement (a predecessor agreement). The 2023 nine-month period cash flows from financing activities also includes the cash proceeds from the previously mentioned Energy Services Amended Term Loan Agreement entered into in February 2023 and ~~used~~ the ~~proceeds principally to reduce short-term borrowings~~concurrent repayment of amounts outstanding under the Energy Services variable rate term loan, and ~~for general corporate purposes.~~

~~UGI Standby Commitment to Purchase~~the May 2023 AmeriGas Partners ~~Class B Common Units~~

On November 7, 2017, UGI entered into a Standby Equity Commitment Agreement (the “Commitment Agreement”) with AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make up to $225 million of capital contributions to the Partnership through July 1, 2019 (the “Commitment Period”). UGI’s capital contributions may be made from time to time during the Commitment Period upon request of the Partnership. There have been no capital contributions made to the Partnership under the Commitment Agreement.

~~At any time after five years from the initial~~ issuance of the ~~Class B Units, holders may elect to convert all or any portion~~$500 million principal amount of 9.375% Senior Notes and the repayment of the ~~Class B Units they own into Common Units on a one-for-one basis, and at any time after six years from the initial issuance~~$675 million aggregate principal balance of the Class B Units, the Partnership may elect to convert all or any portion of the Class B Units into Common Units if (i) the closing trading price of the Common Units is greater than 110% of the applicable purchase price for the Class B Units and (ii) the Common Units are listed or admitted for trading on a National Securities Exchange. Upon certain events involving a change of control and immediately prior to a liquidation or winding up of the Partnership, the Class B Units will automatically convert into Common Units on a one-for-one basis.

~~IMPACT OF TAX REFORM~~

~~On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was enacted into law. Among the significant changes resulting~~5.625% Senior Notes. Cash flow from the law, the TCJA reduces the U.S. federal income tax rate from 35% to 21% effective January 1, 2018, creates a territorial tax system with a one-time mandatory “toll tax” on previously unrepatriated foreign earnings, and allows for immediate capital expensing of certain qualified property. It also applies restrictions on the deductibility of interest expense, eliminates bonus depreciation for regulated utilities, and applies a broader application of compensation limitations.

As a result, during the three months ended December 31, 2017, we reduced our net deferred income tax liabilities by $383.8 million due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of the enactment. Because part of the reduction to our net deferred income taxes relates to UGI Utilities’ regulated utility plant assets as further described below, most of UGI Utilities’ reduction in deferred income taxes is not being recognized immediately in income tax expense.

Discrete deferred income tax adjustments recorded during the three months ended December 31, 2017, which reduced income tax expense, totaled $166.0 million ($0.94 per diluted share) and consisted primarily of the following items:


~~(1)~~	~~a $180.3 million reduction in net deferred tax liabilities in the U.S from the reduction of the U.S. tax rate;~~


~~(2)~~	~~the establishment of $12.6 million of valuation allowances related to deferred tax assets impacted by U.S. tax law changes; and~~


~~(3)~~	~~a $1.7 million “toll tax” on un-repatriated foreign earnings.~~

In order for UGI Utilities’ regulated utility plant assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred income taxes be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. At December 31, 2017, UGI Utilities has recorded a regulatory liability of $216.1 million associated with the excess deferred federal income taxes related to its regulated utility plant assets. This regulatory liability has been increased, and a federal deferred income tax asset has been recorded,financing activities in the ~~amount of $87.8 million to reflect~~prior-year period includes the ~~tax benefit generated by the amortization of the excess deferred federal income taxes. For further information on this regulatory liability, see Note 7 to condensed consolidated financial statements.~~

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~~estimated annual effective tax rate is based on this 24.5% blended rate for fiscal year 2018. For the three months ended December 31, 2017, the~~cash flow effects of the ~~tax law changes on current period results (excluding the one-time impacts described above) decreased income tax expense, and increased net income attributable to~~refinancing of senior notes at UGI by approximately $20.4 million. Regarding UGI Utilities, the PUC has not issued any orders with respect to the lower income tax rate. Our estimated annual effective tax rate for Fiscal 2018 does not reflect the impact of any regulatory action that may be taken by the PUC with respect to the TCJA.International.

In addition, in December 2017, the French Parliament approved the Finance Bill for 2018 and the second Amended Finance Bill for 2017 (collectively, the “December 2017 French Finance Bills”). One impact of the December 2017 French Finance Bills is an increase in the Fiscal 2018 corporate income tax rate in France to 39.4% from 34.4% previously. The December 2017 French Finance Bills also include measures to reduce the corporate income tax rate to 25.8% effective for fiscal years starting after January 1, 2022 (Fiscal 2023). As a result of the future corporate income tax rate reduction effective in Fiscal 2023, during the three months ended December 31, 2017, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $17.3 million ($0.10 per diluted share). The estimated annual effective income tax rate used in determining income taxes for the three months ended December 31, 2017 reflects the impact of the single year Fiscal 2018 income tax rate as a result of the December 2017 French Finance Bills. The impact of the single year rate change increased income tax expense for the three months ended December 31, 2017, by $3.9 million.

In December 2016, the French Parliament approved the Finance Bill for 2017 and amended the Finance Bill for 2016 (collectively, the “December 2016 French Finance Bills”). The December 2016 French Finance Bills, among other things, will reduce UGI France’s corporate income tax rate from the then-current 34.4% to 28.9%, effective for fiscal years starting after January 1, 2020 (Fiscal 2021). As a result of this future income tax rate reduction, during the three months ended December 31, 2017, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $27.4 million ($0.15 per diluted share).

~~For more detailed information on the TCJA and the changes in French tax laws, see Note 5 to condensed consolidated financial statements.~~

UTILITY REGULATORY MATTERS

~~Base Rate Filings.~~ UGI Utilities.On January ~~26, 2018,~~27, 2023, Electric Utility filed a ~~rate~~ request with the ~~PUC~~PAPUC to increase its annual base distribution revenues by ~~$9.2~~$11 million. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. Electric Utility requested that the new electric rates become effective March ~~27, 2018, although the PUC typically suspends~~28, 2023. The PAPUC issued an order on March 2, 2023, suspending the effective date for ~~general base~~the rate ~~proceedings~~increase to allow for investigation and public hearings. ~~This review process~~On July 14, 2023, a Joint Petition for Approval of Settlement of all issues supported by all active parties was filed with the PAPUC providing for a $9 million annual base distribution rate increase for Electric Utility. The Joint Petition is ~~expected~~subject to ~~last up to nine months; however,~~receipt of a recommended decision and a final order of the PAPUC approving the settlement. In accordance with the terms of the Joint Petition, the proposed rate increase will become effective on or before October 1, 2023, or as directed by the PAPUC in the final order. The Company cannot predict the timing or the ultimate outcome of the rate case review process.

On ~~August 31, 2017,~~January 28, 2022, PA Gas Utility filed a request with the ~~PUC approved~~PAPUC to increase its base operating revenues for residential, commercial and industrial customers by $83 million annually. On September 15, 2022, the PAPUC issued a ~~previously filed Joint Petition for Approval of Settlement of all issues~~final order approving a settlement providing for ~~an $11.3~~a $49 million annual base distribution rate increase for ~~PNG. The increase became effective~~PA Gas Utility, through a phased approach, with $38 million beginning October 29, 2022 and an additional $11 million beginning October 1, 2023. In accordance with the terms of the final order, PA Gas Utility will not be permitted to file a rate case prior to January 1, 2024. Also in accordance with the terms of the final order, PA Gas Utility was authorized to implement a weather normalization adjustment rider as a five-year pilot program beginning on ~~October 20, 2017.~~November 1, 2022. Under this rider, when weather deviates from normal by more than 3%, residential and small commercial customer billings for distribution services are adjusted monthly for weather related impacts exceeding the 3% threshold. Additionally, under the terms of the final order, PA Gas Utility was authorized to implement a DSIC once its total property, plant and equipment less accumulated depreciation reached $3,368 million (which threshold was achieved in September 2022).

On ~~October 14, 2016,~~February 8, 2021, Electric Utility filed a request with the ~~PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27.0 million~~PAPUC to increase its annual base distribution ~~rate increase for UGI Gas. The increase became effective on~~revenues by $9 million. On October ~~19, 2016.~~

PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In May 2017,28, 2021, the ~~PUC~~PAPUC issued a final Order approving a settlement that permitted Electric Utility, effective November 9, 2021, to ~~approve an~~ increase ~~of the maximum allowable DSIC to 7.5% of billed~~its base distribution revenues by $6 million.

Mountaineer. On July 31, 2023, Mountaineer submitted its 2023 IREP filing to the WVPSC requesting recovery of $10 million for costs associated with capital investments after December 31, 2022, that total $131 million, including $67 million in calendar year 2024. With new base rates expected to be effective January 1, 2024, revenues from IREP rates would decrease by $12 million. The filing included capital investments totaling $383 million over the 2024 - 2028 period.

On July ~~1, 2017, for PNG~~28, 2023, Mountaineer submitted its annual PGA filing with the WVPSC. This filing allows the WVPSC to review the prudence of Mountaineer’s incurred gas costs, to review the computation of any over or under collection of gas costs, and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018. PNG’s DSIC has been reset to zero as a result of its most recent rate case. The DSIC rate for PNG will resume upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its recent base rate case.

~~In November 2016, UGI Gas received PUC approval~~ to establish a ~~DSIC tariff mechanism, capped at 5%~~PGA billing rate for the upcoming year. The new PGA billing rate is intended to settle past over or under collections and allows Mountaineer to recover its projected gas costs for the upcoming year.

On March 6, 2023, Mountaineer submitted a base rate case filing with the WVPSC seeking a net revenue increase of ~~distribution charges billed~~$20 million, which consists of an increase in base rates of $38 million and a decrease in the IREP rates of $18 million annually to ~~customers,~~be effective on April 5, 2023. On March 31, 2023 the WVPSC suspended the effective date of the requested rate change increase until January 1, ~~2017. UGI Gas will be permitted~~2024 to ~~recover revenue under the mechanism~~allow for ~~the amount of DSIC-eligible plant placed into service in excess~~a full review of the ~~threshold amount~~filing.

On July 29, 2022, Mountaineer submitted its 2022 IREP filing to the WVPSC requesting recovery of ~~DSIC-eligible plant agreed upon~~costs associated with capital investments totaling $354 million over the 2023 - 2027 period, including $64 million in calendar year 2023. On November 16, 2022, Mountaineer and the ~~settlement of its recent base rate case.~~

intervening parties submitted a Joint Stipulation and Agreement for Settlement to the

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WVPSC requesting approval of 2023 IREP revenue of $22 million to be charged effective January 1, 2023, which includes the recovery of a $1 million under-recovery of 2021 IREP revenue. On December 21, 2022, the WVPSC issued an order approving the Joint Stipulation and Agreement for Settlement as filed.

OTHER MATTERS

West Reading, Pennsylvania Explosion. On March 24, 2023, an explosion occurred in West Reading, Pennsylvania which resulted in seven fatalities, significant injuries to eleven others, and extensive property damage to buildings owned by R.M. Palmer, a local chocolate manufacturer, and other neighboring structures. The NTSB, OSHA and the PAPUC are investigating the West Reading incident. On July 18, 2023, the NTSB issued an Investigative Update in its ongoing investigation. The report identifies a fracture in a retired UGI gas service tee and a fracture in a nearby steam system, but it does not address causation of the fractures or the explosion. The NTSB investigative team includes representatives from the Company, the PAPUC, the local fire department and the Pipeline and Hazardous Materials Safety Administration. The Company is cooperating with the investigation. The NTSB may invite other parties to participate.

While the investigation into this incident is still underway and the cause of the explosion has not been determined, the Company has received claims as a result of the explosion and is involved in lawsuits relative to the incident. The Company maintains liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of the Company’s deductible, are recoverable through the Company’s insurance. The Company cannot predict the result of these pending or future claims and legal actions at this time.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk exposures 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 price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.

Commodity Price Risk

The risk associated with fluctuations in the prices the Partnership and our UGI International operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for LPG and other energy commodities. Their profitability is sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. The Partnership and UGI International may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements and over-the-counter derivative commodity instruments including price swap and option contracts. Our UGI International operations use over-the-counter derivative commodity instruments and may from time to time enter into other derivative contracts, similar to those used by the Partnership, to reduce market risk associated with a portion of their LPG purchases. Over-the-counter derivative commodity instruments used to economically hedge forecasted purchases of LPG are generally settled at expiration of the contract. In addition, certain of our UGI International businesses hedge a portion of their anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts as further described below.

~~Gas Utility's~~Utilities’ tariffs contain clauses that permit recovery of all ~~of the~~ prudently incurred costs of natural gas it sells to its retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually ~~collected from~~billed to customers through PGC and PGA rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our ~~Gas Utility~~Utilities operations. PA Gas Utility uses derivative financial instruments, including natural gas futures and option contracts traded on the NYMEX, to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in PA Gas Utility's PGC recovery mechanism. ~~At December 31, 2017, the fair values of Gas Utility’s natural gas futures and option contracts were net losses of $1.7 million.~~

Electric Utility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of FTRs and forward electricity purchase contracts, associated with our Electric Utility operations. At December 31, 2017, all of our Electric Utility’s forward electricity purchase contracts were subject to the NPNS exception. At December 31, 2017, the fair values of Electric Utility’s FTRs were not material.

In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures contracts are recorded at fair value with changes in fair value reflected in “Operating and administrative expenses” on the Condensed Consolidated Statements of Income.

In order to manage market price risk relating to substantially all of Midstream & Marketing’s fixed-price ~~sales~~sale contracts for physical natural gas and electricity, Midstream & Marketing enters into NYMEX, ICE and over-the-counter natural gas and electricity futures and option contracts, and natural gas basis swap contracts or enters into fixed-price supply arrangements. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge a portion of its anticipated sales of electricity from its electricity generation facilities. Although Midstream & Marketing’s fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas or electricity would adversely impact Midstream & Marketing’s results. In order to reduce this risk of supplier nonperformance, Midstream & Marketing has diversified its purchases across a number of suppliers. UGI International’s natural gas and electricity marketing businesses also use natural gas and electricity futures and forward contracts to economically hedge market risk associated with a substantial portion of anticipated volumes under fixed-price sales and purchase contracts.

From time to time, Midstream & Marketing purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. Midstream & Marketing from time to time also enters into NYISO capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Midstream & Marketing also uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas or propane.

Midstream & Marketing has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to

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supply electricity under these agreements, Midstream & Marketing would be required to purchase electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact Midstream & Marketing’s results.

The fair value of unsettled commodity price risk sensitive derivative instruments held at December 31, 2017 (excluding those Gas Utility and Electric Utility commodity derivative instruments that are refundable to, or recoverable from, customers) was a gain of $77.0 million. A hypothetical 10% adverse change in the market price of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges would result in a decrease in fair value of approximately $77.3 million at December 31, 2017.

Interest Rate Risk

We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact their fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.

Our variable-rate debt at ~~December 31, 2017,~~June 30, 2023, includes ~~short-term~~revolving credit facility borrowings and variable-rate term loans at UGI ~~France SAS’s, Flaga’s~~International, Utilities, Energy Services and UGI ~~Utilities’ variable-rate term loans.~~Corporation. These debt agreements have interest rates that are generally indexed to short-term market interest rates. ~~UGI France SAS and Flaga, through the use of~~We have entered into pay-fixed, receive-variable interest rate ~~swaps, have fixed the underlying euribor interest rates~~swap agreements on ~~their euro-denominated term loans through all, or~~ a ~~substantial~~significant portion of the ~~periods such debt is outstanding. In addition, Flaga’s U.S. dollar-denominated loan has been swapped from~~term loans’ principal balances and a ~~floating-rate U.S. dollar-denominated~~significant portion of the term loans’ tenor. We have designated these interest rate ~~to a fixed-rate euro-denominated interest rate through a cross-currency swap, removing interest rate risk (and foreign currency exchange risk~~swaps as ~~further described below under Foreign Currency Exchange Rate Risk) associated with the underlying interest payments.~~cash flow hedges. At ~~December 31, 2017,~~June 30, 2023, combined borrowings outstanding under variable-rate debt agreements, excluding ~~UGI France SAS’s and Flaga’s~~the previously mentioned effectively fixed-rate debt, totaled ~~$711.1~~$1,115 million.

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UGI CORPORATION AND SUBSIDIARIES

Long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt with similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce interest rate risk associated with near- to medium-term forecasted issuances of fixed rate debt, from time to time we enter into IRPAs.

The fair value of unsettled interest rate risk sensitive derivative instruments held at December 31, 2017 (including pay-fixed, receive-variable interest rate swaps) was a loss of $2.1 million. A 50 basis point adverse change in the three-month euribor rate and three-month LIBOR would result in a decrease in fair value of approximately $1.7 million.

Foreign Currency Exchange Rate Risk

Our primary currency exchange rate risk is associated with the ~~U.S. dollar~~USD versus the euro and, to a lesser extent, the ~~U.S. dollar~~USD versus the British pound sterling. The ~~U.S. dollar~~USD value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. From time to time, we use derivative instruments to hedge portions of our net investments in foreign subsidiaries, including anticipated foreign currency denominated dividends. Gains or losses on these net investment hedges remain in AOCI until such foreign operations are sold or liquidated. With respect to our net investments in our UGI International operations, a 10% decline in the value of the associated foreign currencies versus the ~~U.S. dollar~~USD would reduce their aggregate net book value at ~~December 31, 2017,~~June 30, 2023, by approximately ~~$135.0~~$70 million, which amount would be reflected in other comprehensive income. ~~From time to time, we use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“~~We have designated certain euro-denominated borrowings as net investment hedges”). Gains or losses on net investment hedges remain in accumulated other comprehensive income until such foreign operations are sold or liquidated. At December 31, 2017, there were no unsettled net investment hedges outstanding.

hedges.

In addition, in order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we 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.

~~As previously mentioned, Flaga has a cross-currency swap to hedge its exposure to the variability~~ We layer in expected future cash flows associated with the foreign currency and interest rate risk of U.S. dollar-denominated debt. This cross-currency hedge includes initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance.

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~~UGI CORPORATION AND SUBSIDIARIES~~

~~The fair value of unsettled~~these foreign currency exchange ~~rate risk sensitive derivative instruments held at December 31, 2017, including the fair value~~contracts over a multi-year period to eventually equal approximately 90% of Flaga’s cross-currency swap, was a loss of $29.2 million. A hypothetical 10% adverse change in the value of the euro and the British pound sterling versus the U.S. dollar would result in a decrease in fair value of approximately $56.6 million.

anticipated UGI International foreign currency earnings before income taxes.

Derivative Instrument Credit Risk

Certain of these derivative instrument 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. At December 31, 2017, restricted cash in brokerage accounts totaled $19.8 million. Although weWe have concentrations of credit risk associated with derivative instruments and we evaluate the creditworthiness of our derivative counterparties on an ongoing basis. As of June 30, 2023, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was ~~not material at December 31, 2017.~~$305 million. In general, many of our over-the-counter derivative instruments and all exchange contracts call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. At June 30, 2023, we had received cash collateral from derivative instrument counterparties totaling $36 million. In addition, we may have offsetting derivative liabilities and certain accounts payable balances with certain of these counterparties, which further mitigates the previously mentioned maximum amount of losses. 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 ~~December 31, 2017,~~June 30, 2023, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

The following table summarizes the fair values of unsettled market risk sensitive derivative instrument assets (liabilities) held at June 30, 2023 and changes in their fair values due to market risks. Certain of UGI Utilities’ commodity derivative instruments are excluded from the table below because any associated net gains or losses are refundable to or recoverable from customers in accordance with UGI Utilities ratemaking.


	Asset (Liability)
(Millions of dollars)	Fair Value		Change in Fair Value
June 30, 2023
Commodity price risk (1)	$	(202)	$	(161)
Interest rate risk (2)	$	26	$	(18)
Foreign currency exchange rate risk (3)	$	14	$	(49)

(1) Change in fair value represents a 10% adverse change in the market prices of certain commodities.

(2) Change in fair value represents a 50 basis point adverse change in prevailing market interest rates.

(3) Change in fair value represents a 10% adverse change in the value of the Euro and the British pound sterling versus the USD.

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UGI CORPORATION AND SUBSIDIARIES

ITEM 4. CONTROLS AND PROCEDURES


~~(a)~~	~~Evaluation of Disclosure Controls and Procedures~~

(a)Evaluation of Disclosure Controls and Procedures

The Company's disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed or submitted under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company's management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures, as of the end of the period covered by this ~~Report,~~report, were effective at the reasonable assurance level.


~~(b)~~	~~Change in Internal Control over Financial Reporting~~

(b)Change in Internal Control over Financial Reporting

No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

~~- 48 -~~

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UGI CORPORATION AND SUBSIDIARIES

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The information set forth in Note 9, Commitments and Contingencies to our Condensed Consolidated Financial Statements included in Item 1 of Part I of this report, is incorporated herein by reference.

ITEM 1A. RISK FACTORS

In addition to the information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2022 Annual Report and the Quarterly Report on Form ~~10-K~~10-Q for the fiscal ~~year~~quarter ended ~~September 30, 2017~~,December 31, 2022, which could materially affect our business, financial condition or future results. The risks described below and in our 2022 Annual Report and the Quarterly Report on Form ~~10-K~~10-Q for the fiscal quarter ended December 31, 2022, are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

Our energy marketing business in Europe may continue to be disrupted by extreme prices and volatility in the natural gas and power markets in Europe, which have resulted in, and may continue to result in, a material negative impact on our financial results. Our natural gas and power marketing businesses have traditionally relied upon relative pricing and periods of market stability. Since the end of 2021, the European energy markets have been in an unprecedented state of volatility. The war between Russia and Ukraine and the resulting substantial reduction of natural gas imports from Russia to Europe have led to significant uncertainty in supply, including price volatility of both wholesale gas and power, and have created new risks that we have experienced and expect to continue to experience within our European energy marketing business. These risks include: (i) the ability to economically support the traditional fixed price and full requirement contracts of customers due to the significant increased cost to adjust for shifting volumes due to excess or shortage of consumption expectations; (ii) the ability to service typical portfolio needs with standard trading activities due to the limitations on purchasing cost effective services in the market; (iii) the ability to pass increased and volume deviation costs, including balancing costs, onto customers due, among other things, to timing, regulatory and contractual constraints, and (iv) the ability to maintain sourcing services to customers due to the margining and liquidity constraints as well as maximum trading limits implemented by both clearing banks and wholesale counterparties on energy suppliers, and (v) the ability to economically support fixed and variable price products while offering competitive services in the market. As a result, UGI is considering all scenarios with respect to the future of its energy marketing business in Europe, including exit and wind down. In Fiscal 2023, UGI announced the sale of its energy marketing business in the United Kingdom and that UGI has entered into definitive agreements to divest of substantially all of its energy marketing businesses in France and Belgium. Further, UGI continues to make progress on the wind-down of its energy marketing business in the Netherlands. The risks identified with respect to our energy marketing business in Europe have resulted in and may continue to have a material negative impact on our financial results.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth information with respect to the Company’s repurchases of its common stock during the quarter ended ~~December 31, 2017.~~June 30, 2023.

Period (a) Total Number of Shares Purchased (b) Average Price Paid per Share (or Unit) (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (1) (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
October 1, 2017 to October 31, 2017 — — — 10.62 million
November 1, 2017 to November 30, 2017 — — — 10.62 million
December 1, 2017 to December 31, 2017 202,500 $46.82 202,500 10.42 million
Total 202,500 202,500


~~(1)~~Period	~~In January 2014,~~	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the ~~UGI Board of Directors authorized a share repurchase program for up~~Plans or Programs (1)




April 1, 2023 to 15April 30, 2023		—	$0.00	—	6.50 million shares of UGI Corporation Common Stock. The authorization permitted the execution of the share repurchase program over a four-year period, expiring in January 2018. On January 25, 2018, the UGI Board of Directors authorized an extension of the share repurchase program for up
May 1, 2023 to 8May 31, 2023		—	$0.00	—	6.50 million ~~shares of UGI Corporation Common Stock for an additional four-year period.~~
June 1, 2023 to June 30, 2023		—	$0.00	—	6.50 million
Total		—		—

(1) Shares of UGI Common Stock are repurchased through an extension of a previous share repurchase program announced by the Company on February 2, 2022. The UGI Board of Directors authorized the repurchase of up to 8 million shares of UGI Common Stock over a four-year period expiring in February 2026.

~~- 49 -~~

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UGI CORPORATION AND SUBSIDIARIES

ITEM 5. OTHER INFORMATION

Insider Trading Arrangements

During the three months ended June 30, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation-S-K.

ITEM 6. EXHIBITS

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and last date of the period for which it was filed, and the exhibit number in such filing):

Incorporation by Reference

Exhibit
No.

Exhibit

Registrant

Filing

Exhibit

3.1

Amended and Restated Bylaws of UGI Corporation, effective as of May 3, 2023.

UGI

Form 8-K (5/3/23)

3.1

4.1

Indenture, dated as of May 31, 2023, between the Issuers and U.S. Bank Trust Company, National Association, as trustee (including the form of 2028 Notes).

UGI

Form 8-K (5/31/23)

4.1

10.1

Second Amendment to the Amended and Restated Credit Agreement, dated as of May 12, 2023, by and among UGI Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent.

UGI

Form 8-K (5/12/23)

10.1

10.2

Second Amendment to the Third Amended and Restated Credit Agreement, dated as of May 12, 2023, by and among UGI Energy Services, LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent.

UGI

Form 8-K (5/12/23)

10.2

31.1

Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2023, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2023, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2023, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

Inline XBRL Instance - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

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Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

Exhibit
No.
   Exhibit    Registrant    Filing    Exhibit

10.1
Multicurrency Revolving Credit Agreement dated December 19, 2017, by and among UGI International, LLC, as Borrower, Natixis, as Agent, Security Agent, Mandated Lead Arranger, Bookrunner and Coordinator, BNP Paribas, Credit Agricole Corporate and Investment Bank, HSBC France, ING Bank N.V. and Mediobanca International (Luxembourg) S.A., as Mandated Lead Arrangers and certain other lenders.

10.2
Second Amended and Restated Credit Agreement dated as of December 15, 2017 by and among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as a Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender, and Issuing Lender, Wells Fargo Securities, LLC, as Sole Lead Arranger and Sole Bookrunner, and the other financial institutions from time to time party thereto.
AmeriGas Partners, L.P. Form 8-K (12/15/2017) 10.1

31.1
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2017, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2
Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2017, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32
Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2017, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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UGI CORPORATION AND SUBSIDIARIES

EXHIBIT INDEX



31.1
~~10.1~~	Multicurrency Revolving Credit Agreement dated December 19, 2017, by and among UGI International, LLC, as Borrower, Natixis, as Agent, Security Agent, Mandated Lead Arranger, Bookrunner and Coordinator, BNP Paribas, Credit Agricole Corporate and Investment Bank, HSBC France, ING Bank N.V. and Mediobanca International (Luxembourg) S.A., as Mandated Lead Arrangers and certain other lenders.

~~31.1~~	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended ~~December 31, 2017,~~June 30, 2023, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended ~~December 31, 2017,~~June 30, 2023, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32		Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended ~~December 31, 2017,~~June 30, 2023, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		Inline XBRL Instance - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

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104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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UGI CORPORATION AND SUBSIDIARIES

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


				UGI Corporation
				(Registrant)

Date:			August 8, 2023	By:	/s/ Sean P. O’Brien
					Sean P. O’Brien
					Chief Financial Officer


Date:			August 8, 2023	~~UGI Corporation~~By:	/s/ Jean Felix Tematio Dontsop
				~~(Registrant)~~	Jean Felix Tematio Dontsop

~~Date:~~	~~February 6, 2018~~	~~By:~~	~~/s/ Kirk R. Oliver~~
			~~Kirk R. Oliver~~
			~~Chief Financial Officer~~


~~Date:~~	~~February 6, 2018~~	~~By:~~	~~/s/ Marie-Dominique Ortiz-Landazabal~~
			~~Marie-Dominique Ortiz-Landazabal~~
			Vice President, ~~- Accounting and Financial Control~~
			~~and~~ Chief Accounting Officer
					and Corporate Controller

~~- 52 -~~68



Pennsylvania		23-2668356
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

~~460 North Gulph Road, King of Prussia, PA~~	~~19406~~
~~(Address of principal executive offices)~~	~~(Zip Code)~~


Title of each class:	Trading Symbol(s):	Name of each exchange on which registered:
Common Stock, without par value	UGI	New York Stock Exchange
Corporate Units	UGIC	New York Stock Exchange


			Page

Glossary of Terms and Abbreviations			1

Part I Financial Information

			~~Page~~

~~Part I Financial Information~~

Item 1. Financial Statements (unaudited)

Condensed Consolidated Balance Sheets as of ~~December 31, 2017,~~June 30, 2023, September 30, ~~2017~~2022 and ~~December 31, 2016~~June 30, 2022			16

Condensed Consolidated Statements of Income for the three and nine months ended ~~December 31, 2017~~June 30, 2023 and ~~2016~~2022			27

Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended ~~December 31, 2017~~June 30, 2023 and ~~2016~~2022			38

Condensed Consolidated Statements of Cash Flows for the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2023 and ~~2016~~2022			49

Condensed Consolidated Statements of Changes in Equity for the three and nine months ended ~~December 31, 2017~~June 30, 2023 and ~~2016~~2022			510

Notes to Condensed Consolidated Financial Statements			611

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			3041

Item 3. Quantitative and Qualitative Disclosures About Market Risk			4662

Item 4. Controls and Procedures			4864

Part II Other Information

Item 1. Legal Proceedings			65

Item 1A. Risk Factors			4965

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			4965

Item 5. Other Information			66

Item 6. Exhibits			5066

Signatures			5268


	December 31, 2017			September 30, 2017			December 31, 2016				June 30, 2023		September 30, 2022		June 30, 2022
ASSETS										ASSETS
Current assets:										Current assets:
Cash and cash equivalents	$	446.4		$	558.4		$	515.2		Cash and cash equivalents	$	260	$	405	$	670
Restricted cash	19.8			10.3			7.9			Restricted cash	78		64		14
Accounts receivable (less allowances for doubtful accounts of $35.1, $26.9 and $29.2, respectively)	1,101.8			626.8			917.3
Accounts receivable (less allowances for doubtful accounts of $87, $64 and $66, respectively)										Accounts receivable (less allowances for doubtful accounts of $87, $64 and $66, respectively)	955		1,127		1,234
Accrued utility revenues	95.9			13.3			55.6			Accrued utility revenues	29		23		19
Income taxes receivable										Income taxes receivable	36		128		127
Inventories	307.3			278.6			228.2			Inventories	410		665		496
Utility regulatory assets	0.6			8.3			1.6

Derivative instruments	73.4			63.1			87.0			Derivative instruments	31		865		773
Held for sale assets										Held for sale assets	64		295		—
Prepaid expenses and other current assets	135.4			138.7			97.1			Prepaid expenses and other current assets	172		230		176
Total current assets	2,180.6			1,697.5			1,909.9			Total current assets	2,035		3,802		3,509
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $3,393.1, $3,312.9 and $3,139.8, respectively)	5,690.5			5,537.0			5,244.3
Property, plant and equipment, (less accumulated depreciation of $4,536, $4,166 and $4,160, respectively)										Property, plant and equipment, (less accumulated depreciation of $4,536, $4,166 and $4,160, respectively)	8,394		8,040		7,839
Goodwill	3,185.5			3,107.2			2,935.8			Goodwill	3,060		3,612		3,671
Intangible assets, net	641.9			611.7			558.9			Intangible assets, net	460		500		523
Utility regulatory assets	362.2			360.6			391.3			Utility regulatory assets	310		301		352
Derivative instruments	13.3			9.2			24.2			Derivative instruments	59		565		410

Other assets	269.9			259.0			236.1			Other assets	925		755		807
Total assets	$	12,343.9		$	11,582.2		$	11,300.5		Total assets	$	15,243	$	17,575	$	17,111
LIABILITIES AND EQUITY										LIABILITIES AND EQUITY
Current liabilities:										Current liabilities:
Current maturities of long-term debt	$	224.1		$	177.5		$	48.5		Current maturities of long-term debt	$	56	$	149	$	47

Short-term borrowings	586.1			366.9			234.4			Short-term borrowings	481		368		276
Accounts payable	680.8			439.6			573.6			Accounts payable	541		891		843

Derivative instruments	32.7			25.0			16.2			Derivative instruments	120		144		70
Held for sale liabilities										Held for sale liabilities	37		19		—
Other current liabilities	692.3			681.1			702.2			Other current liabilities	848		873		832
Total current liabilities	2,216.0			1,690.1			1,574.9			Total current liabilities	2,083		2,444		2,068
Long-term debt	4,056.4			3,994.6			3,994.2			Long-term debt	6,579		6,483		6,399

Deferred income taxes	890.7			1,357.0			1,204.7			Deferred income taxes	905		1,305		1,291
Deferred investment tax credits	2.9			3.0			3.2

Derivative instruments	22.2			21.8			16.6			Derivative instruments	47		50		54
Other noncurrent liabilities	1,073.6			774.8			773.8			Other noncurrent liabilities	1,256		1,219		1,294
Total liabilities	8,261.8			7,841.3			7,567.4			Total liabilities	10,870		11,501		11,106
Commitments and contingencies (Note 10)
Commitments and contingencies (Note 9)										Commitments and contingencies (Note 9)
Equity:										Equity:
UGI Corporation stockholders’ equity:										UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 173,997,441, 173,987,691 and 173,903,191 shares, respectively)	1,189.3			1,188.6			1,203.4
Preferred stock, without par value (authorized – 5,000,000 shares; issued – 220,000, 220,000 and 220,000 Series A shares, respectively)										Preferred stock, without par value (authorized – 5,000,000 shares; issued – 220,000, 220,000 and 220,000 Series A shares, respectively)	167		162		162
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 210,882,552, 210,560,494 and 210,378,881 shares, respectively)										UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 210,882,552, 210,560,494 and 210,378,881 shares, respectively)	1,500		1,483		1,474
Retained earnings	2,429.3			2,106.7			2,035.4			Retained earnings	2,974		4,841		4,674
Accumulated other comprehensive loss	(71.5		)	(93.4		)	(216.8		)	Accumulated other comprehensive loss	(222)		(380)		(273)
Treasury stock, at cost	(45.4		)	(38.6		)	(34.3		)	Treasury stock, at cost	(55)		(40)		(41)
Total UGI Corporation stockholders’ equity	3,501.7			3,163.3			2,987.7			Total UGI Corporation stockholders’ equity	4,364		6,066		5,996
Noncontrolling interests, principally in AmeriGas Partners	580.4			577.6			745.4
Noncontrolling interests										Noncontrolling interests	9		8		9
Total equity	4,082.1			3,740.9			3,733.1			Total equity	4,373		6,074		6,005
Total liabilities and equity	$	12,343.9		$	11,582.2		$	11,300.5		Total liabilities and equity	$	15,243	$	17,575	$	17,111



	Three Months Ended December 31,
	2017			2016
Net income including noncontrolling interests	$	434.2		$	290.9
Other comprehensive income (loss):
Net (losses) gains on derivative instruments (net of tax of $0.2 and $(6.0), respectively)	(0.4		)	12.3
Reclassifications of net gains on derivative instruments (net of tax of $0.1 and $2.1, respectively)	(0.4		)	(4.5		)
Foreign currency adjustments	22.3			(70.9		)
Benefit plans (net of tax of $(0.2) and $(0.6), respectively)	0.4			1.0
Other comprehensive income (loss)	21.9			(62.1		)
Comprehensive income including noncontrolling interests	456.1			228.8
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	(68.3		)	(60.2		)
Comprehensive income attributable to UGI Corporation	$	387.8		$	168.6



ý☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



¨☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



	Three Months Ended December 31,
	2017		2016
Trade receivables transferred to ESFC during the period	$	270.6	$	246.4
ESFC trade receivables sold to the bank during the period	$	48.0	$	66.0



	December 31, 2017		September 30, 2017		December 31, 2016
ESFC trade receivables — end of period (a)	$	101.0	$	44.8	$	81.4



	Pension Benefits						Other Postretirement Benefits
Three Months Ended December 31,	2017			2016			2017			2016
Service cost	$	2.8		$	3.0		$	0.2		$	0.2
Interest cost	6.5			6.2			0.2			0.2
Expected return on assets	(8.6		)	(8.3		)	(0.2		)	(0.2		)
Amortization of:
Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
Actuarial loss	3.3			4.1			0.1			0.1
Net benefit cost	4.1			5.1			0.2			0.2
Change in associated regulatory liabilities	—			—			(0.1		)	(0.1		)
Net benefit cost after change in regulatory liabilities	$	4.1		$	5.1		$	0.1		$	0.1



Three Months Ended December 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:	2017			2016			2017			2016			Location of Gain (Loss) Reclassified from AOCI into Income
Foreign currency contracts	$	(1.4	)	$	17.2		$	0.8		$	7.9		Cost of sales
Cross-currency contracts	0.1			(0.1		)	0.2			(0.3		)	Interest expense/other operating income, net
Interest rate contracts	0.7			1.2			(0.5		)	(1.0		)	Interest expense
Total	$	(0.6	)	$	18.3		$	0.5		$	6.6

	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2017			2016			Location of Gain (Loss) Recognized in Income
Commodity contracts	$	24.4		$	108.5		Cost of sales
Commodity contracts	(1.3		)	0.1			Revenues
Commodity contracts	0.1			(0.1		)	Operating and administrative expenses
Foreign currency contracts	(4.8		)	1.3			(Losses) gains on foreign currency contracts, net
Total	$	18.4		$	109.8



Three Months Ended December 31, 2017	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI — September 30, 2017	$	(19.2	)	$	(21.4	)	$	(52.8	)	$	(93.4	)
Other comprehensive (loss) income before reclassification adjustments (after-tax)	—			(0.4		)	22.3			21.9
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0.6			(0.5		)	—			0.1
Reclassification adjustments tax (benefit) expense	(0.2		)	0.1			—			(0.1		)
Reclassification adjustments (after-tax)	0.4			(0.4		)	—			—
Other comprehensive income (loss) attributable to UGI	0.4			(0.8		)	22.3			21.9
AOCI — December 31, 2017	$	(18.8	)	$	(22.2	)	$	(30.5	)	$	(71.5	)

Three Months Ended December 31, 2016	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI — September 30, 2016	$	(29.1	)	$	(13.4	)	$	(112.2	)	$	(154.7	)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			12.3			(70.9		)	(58.6		)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	1.6			(6.6		)	—			(5.0		)
Reclassification adjustments tax (benefit) expense	(0.6		)	2.1			—			1.5
Reclassification adjustments (after-tax)	1.0			(4.5		)	—			(3.5		)
Other comprehensive income (loss) attributable to UGI	1.0			7.8			(70.9		)	(62.1		)
AOCI — December 31, 2016	$	(28.1	)	$	(5.6	)	$	(183.1	)	$	(216.8	)



For the three months ended December 31,	2017					2016				Variance - Favorable (Unfavorable)
(Dollars in millions)	Amount (a)			% of Total		Amount		% of Total		Amount			% Change
AmeriGas Propane (b)	$	141.6		38.7	%	$	16.6	7.2	%	$	125.0		753.0	%
UGI International (c)(d)	61.1			16.7	%	88.3		38.3	%	(27.2		)	(30.8	)%
Midstream & Marketing	112.0			30.6	%	29.9		13.0	%	82.1			274.6	%
UGI Utilities	68.3			18.7	%	44.3		19.2	%	24.0			54.2	%
Corporate & Other (e)	(17.1		)	(4.7	)%	51.6		22.3	%	(68.7		)	N.M.
Net income attributable to UGI Corporation	$	365.9		100.0	%	$	230.7	100.0	%	$	135.2		58.6	%



AmeriGas Propane	$	113.1
UGI International	(9.3		)
Midstream & Marketing	74.3
UGI Utilities	8.1
Corporate & Other	(20.2		)
Net income attributable to UGI Corporation	$	166.0



Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share (or Unit)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (1)	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
October 1, 2017 to October 31, 2017	—	—	—	10.62 million
November 1, 2017 to November 30, 2017	—	—	—	10.62 million
December 1, 2017 to December 31, 2017	202,500	$46.82	202,500	10.42 million
Total	202,500		202,500