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.

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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)




























Three Months Ended December 31, 2021	Total		Eliminations (a)		AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other
Revenues from contracts with customers:
Utility:
Core Market:
Residential	$	234	$	—	$	—	$	—	$	—	$	234	$	—
Commercial & Industrial	94		—		—		—		—		94		—
Large delivery service	43		—		—		—		—		43		—
Off-system sales and capacity releases	19		(22)		—		—		—		41		—
Other	5		(1)		—		—		—		6		—
Total Utility	395		(23)		—		—		—		418		—
Non-Utility:
LPG:
Retail	1,250		—		646		604		—		—		—
Wholesale	140		—		56		84		—		—		—
Energy Marketing	714		(55)		—		333		436		—		—
Midstream:
Pipeline	46		—		—		—		46		—		—
Peaking	6		(39)		—		—		45		—		—
Other	2		—		—		—		2		—		—
Electricity Generation	5		—		—		—		5		—		—
Other	78		—		58		20		—		—		—
Total Non-Utility	2,241		(94)		760		1,041		534		—		—
Total revenues from contracts with customers	2,636		(117)		760		1,041		534		418		—
Other revenues (b)	37		(1)		18		8		1		1		10
Total revenues	$	2,673	$	(118)	$	778	$	1,049	$	535	$	419	$	10

~~Note 5 — Income Tax Reform~~

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

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

~~On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was enacted into law. Among the significant changes resulting~~Contract Balances

The timing of revenue recognition may differ from the ~~law,~~timing of invoicing to customers or cash receipts. Contract assets represent our right to consideration after the ~~TCJA reduces~~performance obligations have been satisfied when such right is conditioned on something other than the ~~U.S. federal income tax rate from 35%~~passage of time. Contract assets were not material for all periods presented. Substantially all of our receivables are unconditional rights to ~~21% effective January 1, 2018, creates a territorial tax system with a one-time mandatory “toll tax” on previously unrepatriated foreign earnings,~~consideration and ~~allows for immediate capital expensing~~are included in “Accounts receivable” and, in the case of ~~certain qualified property. It also applies restrictions~~Utilities, “Accrued utility revenues” on the ~~deductibility~~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 ~~interest expense, eliminates bonus depreciation for regulated utilities~~contract liabilities were $143, $164 and ~~applies a broader application of compensation limitations.~~

~~In accordance with GAAP as determined by ASC 740, “Income Taxes,” we~~$129 at December 31, 2022, September 30, 2022 and December 31, 2021, respectively, and are ~~required to record~~included in “Other current liabilities” and “Other noncurrent liabilities” on the ~~effects of tax law changes in the period enacted. As further discussed below, our results~~Condensed Consolidated Balance Sheets. Revenues recognized 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~~2022 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 months2021, 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 rateamounts 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,contract liabilities at September 30, 2022 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.2021, were $81 and $70, respectively.

~~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

~~- 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)

Remaining Performance Obligations

~~benefit~~The Company excludes disclosures related to the aggregate amount of ~~$17.3 (equal~~the transaction price allocated to ~~$0.10 per basic~~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 ~~diluted share). The estimated annual effective income tax rate used in determining income taxes for the three months ended~~Utilities contain minimum future performance obligations through 2047 and 2053, respectively. At December 31, ~~2017, reflects~~2022, Midstream & Marketing and Utilities expect to record approximately $2.3 billion and $0.2 billion of revenues, respectively, related to the ~~impact~~minimum future performance obligations over the remaining terms of the ~~single year Fiscal 2018 income tax rate as~~related contracts.

Note 5 — UGI International Energy Marketing Businesses

Sale of U.K. Energy Marketing Business. On October 21, 2022, UGI International, through a ~~result~~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 ~~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,sale, during the three months ended December 31, ~~2016,~~2022, the Company ~~reduced its~~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 ~~French deferred income tax liabilities~~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 on the Condensed Consolidated Balance Sheet and ~~recognized an estimated deferred tax benefit~~a net carrying value of ~~$27.4 (equal to $0.15 per basic~~$276. The change in the carrying value of these derivative instruments between September 30, 2022 and ~~diluted share).~~

~~Note 6 — Goodwill and Intangible Assets~~

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

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~~October 21, 2022 resulted from changes in ~~goodwill and intangible assets are primarily due~~their fair values during that period.

Other UGI International Energy Marketing Businesses. In November 2022, the Company announced that it expected to ~~acquisitions~~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 definitive agreement during the first quarter of Fiscal 2023 as extended negotiations with the potential buyer had been discontinued. The Company continues to pursue the sale of its energy marketing business in France, as well as the wind-down of its energy marketing business located in Belgium and the ~~effects~~Netherlands. At December 31, 2022, the sale of ~~currency translation. Amortization expense~~our energy marketing business in France was not considered probable of ~~intangible~~occurring within one year and, as such, assets ~~was $14.8~~ and ~~$12.5~~liabilities associated with this business were not classified as held for sale on the Condensed Consolidated Balance Sheet.

During the three months ended December 31, ~~2017~~2022, the Company recorded a $19 pre-tax ($15 after-tax) impairment charge to reduce the carrying values of certain assets associated with its energy marketing business in the Netherlands, comprising property, plant and ~~2016, respectively. Amortization expense included~~equipment and intangible assets. The impairment charge is reflected in ~~“Cost of sales”~~“Operating and administrative expenses” on the Condensed Consolidated ~~Statements~~Statement of Income ~~was not material. The estimated aggregate amortization expense of intangible assets for~~and included in the ~~remainder of Fiscal 2018 and for~~UGI International segment.

Note 6 — Inventories

Inventories comprise 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.~~following:


	December 31, 2022		September 30, 2022		December 31, 2021
Non-utility LPG and natural gas	$	310	$	335	$	352
Gas Utility natural gas	129		166		65
Energy certificates	78		70		60
Materials, supplies and other	101		94		71
Total inventories	$	618	$	665	$	548

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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)

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:


	December 31, 2022		September 30, 2022		December 31, 2021
Regulatory assets (a):
Income taxes recoverable	$	93	$	83	$	145
Underfunded pension plans	114		114		106
Environmental costs	36		37		57
Deferred fuel and power costs	71		32		29
Removal costs, net	25		22		23
Other	54		52		52
Total regulatory assets	$	393	$	340	$	412
Regulatory liabilities (a):
Postretirement benefit overcollections	$	11	$	11	$	13

Deferred fuel and power refunds	3		3		1
State tax benefits — distribution system repairs	39		38		33

Excess federal deferred income taxes	264		279		285
Other	3		4		14
Total regulatory liabilities	$	320	$	335	$	346

(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 new PGA rate increase to customers, delayed the effective date in 2022 from November 1 to December 1 and deferred $12 in under-recovery of gas cost in determining the rates to be charged to the various customer classes effective December 1, 2022. Additionally, 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 to only 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,~~2022, September 30, ~~2017~~2022 and December 31, ~~2016~~2021 were ~~$(1.7)~~$(17), ~~$0.1~~$5 and ~~$6.9,~~$2, 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,

~~- 12 -~~

~~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

~~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. 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~~28, 2023. However, the ~~PUC~~PAPUC typically suspends the effective date for general base rate proceedings for a period not to exceed nine months after the filing date to allow for the investigation and public ~~hearings. This review process is expected to last up to nine months; however, the~~hearing. The Company cannot predict the timing or the ultimate outcome of the rate case review process.

On August 31, 2017, the PUC approved 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 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.

~~- 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)

On January 28, 2022, PA Gas Utility filed a request with the PAPUC to 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 5-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).

~~Information regarding~~On February 8, 2021, Electric Utility filed a rate request with the ~~trade receivables transferred~~PAPUC to ~~ESFC~~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 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 ~~the three months ended~~Settlement as filed.

Note 8 — Debt

UGI International Credit Facilities Agreement. In October 2018, UGI International entered into a five-year unsecured senior facilities agreement with a consortium of banks (the “UGI International Credit Facilities Agreement”), consisting of (1) a €300 variable-rate term loan facility and (2) a €300 multicurrency revolving credit facility. The UGI International Credit Facilities Agreement is scheduled to mature in October 2023. At December 31, ~~2017~~2022, the €300 ($321) variable-rate term loan is reflected in “Current maturities of long-term debt” on the Condensed Consolidated Balance Sheet.

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 ~~2016, as well as~~to replace the ~~balance~~use of ~~ESFC trade receivables~~LIBOR with 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 ~~December 31, 2017, September 30, 2017 and December 31, 2016, is as follows:~~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.

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.In December 2017, AmeriGas Partners~~Mountaineer Credit Agreement. On October 20, 2022, Mountaineer entered into the ~~Second Amended and Restated~~Mountaineer 2023 Credit Agreement, ~~(“AmeriGas Credit Agreement”)~~as borrower, with a group of ~~banks.~~lenders. The ~~AmeriGas~~Mountaineer 2023 Credit Agreement amends and restates a previous credit ~~agreement. The AmeriGas Credit Agreement~~agreement and provides for borrowings up to ~~$600 (including~~$150, including a ~~$150~~$20 sublimit for letters of ~~credit)~~credit. Mountaineer may request an increase in the amount of loan commitments to a maximum aggregate amount of $250, subject to certain terms and ~~expires in December 2022. The AmeriGas~~conditions. Borrowings under the Mountaineer 2023 Credit Agreement ~~permits AmeriGas~~can be used to ~~borrow at prevailing interest rates, including~~finance the ~~base rate, defined as the higher~~working capital needs 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%;Mountaineer and ~~the facility fee ranges from 0.30% to 0.50%.~~for general corporate purposes. 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, the Partnership recognized a pre-tax loss of $33.2 in connection with the early repayment of a portion of AmeriGas Partners’ 7.00% Senior Notes. This loss is reflected in “Loss on extinguishments of debt” on the Condensed Consolidated Statements of Income for the three months ended December 31, 2016.

Borrowings under the Mountaineer 2023 Credit Agreement ~~UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will~~ bear interest, subject to our election, at either (i) the ~~associated euribor~~base rate, defined as the highest of (a) the prime rate, (b) the federal funds 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~~0.50% and (c) the ~~outstanding principal amount of its then-existing $59.1 U.S. dollar denominated variable-rate~~adjusted 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~~SOFR rate for a ~~principal balance~~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 SOFR loans from 1.00% to 2.25%, depending on the debt rating of ~~$49.9 and extends the maturity of~~Mountaineer. The adjusted term SOFR rate is defined as the term ~~loan to April 2020 (“Flaga Term Loan”). The outstanding principal bears~~SOFR reference rate for the selected interest ~~at the~~period, plus 0.10% per annum for a one-month ~~LIBOR rate plus~~interest period, 0.15% per annum for a ~~margin of 1.125%. Flaga has effectively fixed the LIBOR component of the~~three-month interest ~~rate, and has effectively fixed the U.S. dollar value of the~~period, or 0.25% per annum for a six-month 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.

~~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

period.

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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 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. 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 from the PUC authorizing the extension of the maturity date to October 30, 2022, the Utilities Term Loan has been reflected in “Current maturities of long-term debt” on the December 31, 2017, Condensed Consolidated Balance Sheet.

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.~~is $5. The COA ~~environmental~~permits the transfer of the specified wells, with related 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~~counted towards the ~~end of 2031, 2018, and 2019, respectively.~~annual minimum expenditure. At December 31, ~~2017,~~2022, September 30, ~~2017~~2022 and December 31, ~~2016,~~2021, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the ~~COAs for UGI Utilities, CPG~~current COA and ~~PNG~~the predecessor agreements totaled ~~$53.4, $54.3~~$54, $53 and ~~$55.3,~~$50, 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 of Pennsylvania ~~was material.~~were material for all periods presented.

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. Based on our evaluation of the available information, during the third quarter of Fiscal 2017, the Partnership accrued an environmental remediation liability of $7.5 related to the site. Our share of the actual remediation costs could be significantly more or less than the accrued amount.

~~Other Matters~~

~~Purported Class Action Lawsuits.~~ Between May and October of 2014, more than 35 purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI and a competitor by certain of their direct and indirect customers. The class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 ~~pounds to~~ 15 pounds and combined to persuade their common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws. The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes.

On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Division of the United States District Court for the Western District of Missouri (“District Court”). In July 2015, the District Court dismissed all 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~~The NYDEC commenced implementation of the ~~Eighth Circuit. In September 2017, we filed a Petition for a Writ~~remediation plan in the spring of ~~Certiorari~~2018. Based on our evaluation of the available information as of December 31, 2022, the Partnership has an undiscounted environmental remediation liability of $8 related to the ~~U.S. Supreme Court appealing the decision~~site. Our share of the ~~Eighth Circuit. The petition was denied in January 2018~~actual remediation costs could be significantly more or less than the accrued amount. Although we cannot predict the final results of these pending claims and ~~as a result, the case was transferred back to the District Court for further proceedings.~~

~~In July 2015, the District Court also dismissed all claims brought by the indirect customers other than those for injunctive relief. The indirect customers filed an amended complaint~~legal actions, we believe, after consultation 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 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 of the direct purchasers’ claims. In light 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 still pending in the Eighth Circuit. Nowcounsel, that the ~~Eighth Circuit has ruled~~final outcome of these matters will not have a material effect on ~~the direct purchasers’ claims, the stay has been lifted for the indirect claims and the parties submitted briefs in October 2017 to the Eighth Circuit and are awaiting the court’s ruling.~~our financial statements.

~~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, 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~~plans and other postretirement plans for ~~employees hired prior to January 1, 2009,~~certain current and former employees. The service cost component 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 benefitour pension and other postretirement ~~plans.~~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 (expense) income, net” on the Condensed Consolidated Statements of Income. Other postretirement benefit cost was not material for all periods presented.

Net periodic pension ~~expense and other postretirement benefit costs include~~cost includes the following components:
















Three Months Ended December 31,	2022		2021
Service cost	$	2	$	4
Interest cost	9		6
Expected return on plan assets	(11)		(12)

Amortization of:

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

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 the three months ended December 31, 2017 and 2016, 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)~~

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, as~~hierarchy:


	Asset (Liability)
	Level 1		Level 2		Level 3		Total
December 31, 2022:
Derivative instruments:
Assets:
Commodity contracts	$	345	$	329	$	—	$	674
Foreign currency contracts	$	—	$	35	$	—	$	35
Interest rate contracts	$	—	$	63	$	—	$	63

Liabilities:
Commodity contracts	$	(297)	$	(152)	$	—	$	(449)
Foreign currency contracts	$	—	$	(4)	$	—	$	(4)


Non-qualified supplemental postretirement grantor trust investments (a)	$	46	$	—	$	—	$	46
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
December 31, 2021:
Derivative instruments:
Assets:
Commodity contracts	$	411	$	711	$	—	$	1,122
Foreign currency contracts	$	—	$	29	$	—	$	29
Interest rate contracts	$	—	$	5	$	—	$	5

Liabilities:
Commodity contracts	$	(160)	$	(18)	$	—	$	(178)
Foreign currency contracts	$	—	$	(7)	$	—	$	(7)
Interest rate contracts	$	—	$	(17)	$	—	$	(17)

Non-qualified supplemental postretirement grantor trust investments (a)	$	52	$	—	$	—	$	52

(a)Consists primarily of ~~December 31, 2017, September 30, 2017~~mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.

(b)Includes derivative assets and ~~December 31, 2016:~~ liabilities held-for-sale associated with the October 2022 sale of the U.K. energy marketing business (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


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

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

designated as Level 2 are based upon indicative price quotations available through brokers, industry price

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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 actual realized value at which these contracts will settle could vary significantly compared to the fair values reflected at September 30, 2022. 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 2 during the periods presented.~~

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:


	December 31, 2022		September 30, 2022		December 31, 2021
Carrying amount	$	6,759	$	6,665	$	6,580
Estimated fair value	$	6,350	$	6,189	$	7,048

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 summarizes the types of derivative instruments used by the Company to manage certain market risks:

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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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)

~~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 December 31, 2022, the amount of pre-tax net gains associated with interest rate hedges expected to be reclassified into earnings during the next twelve months is $39.

Foreign Currency Exchange Rate Risk

Forward Foreign Currency Exchange Contracts

In order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the USD exchange rate to the euro and British pound sterling, we enter into forward foreign currency exchange contracts. We layer in these foreign currency exchange contracts over a multi-year period to eventually equal approximately 90% of anticipated UGI International 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 “Other non-operating (expense) income, net,” on the Condensed Consolidated Statements of Income.

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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)

Net Investment Hedges

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 exchange rate between the euro and British pound sterling, we have entered 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 in the fair value of these foreign currency exchange contracts are recorded in “Losses on foreign currency contracts, net” on the Condensed Consolidated Statements of Income.

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 cumulative translation adjustment component in AOCI of $(64) and $13 during the three months ended December 31, 2022 and 2021, respectively.

Quantitative Disclosures Related to Derivative Instruments

The following table summarizes by derivative type the gross notional amounts related to open derivative contracts at December 31, 2022, September 30, 2022 and December 31, 2021, and the final settlement dates of the Company's open derivative contracts as of December 31, 2022, but excluding those derivatives that qualified for the NPNS exception:


			Notional Amounts (in millions)
Type	Units	Settlements Extending Through	December 31, 2022		September 30, 2022		December 31, 2021
Commodity Price Risk:
Regulated Utility Operations
PA Gas Utility NYMEX natural gas futures and option contracts	Dekatherms	September 2023	15		19		14


Non-utility Operations
LPG swaps	Gallons	September 2025	844		874		732
Natural gas futures, forward, basis swap, options and pipeline contracts (a)	Dekatherms	October 2027	371		363		382




Electricity forward and futures contracts	Kilowatt hours	December 2026	2,270		2,446		4,261

Interest Rate Risk:
Interest rate swaps	Euro	N/A	€	—	€	300	€	300
Interest rate swaps	USD	June 2026	$	1,354	$	1,358	$	1,418

Foreign Currency Exchange Rate Risk:
Forward foreign currency exchange contracts	USD	August 2025	$	390	$	465	$	415
Net investment hedge forward foreign exchange contracts	Euro	December 2026	€	331	€	411	€	486

(a)September 30, 2022 includes amounts held-for-sale associated with the ~~foreign currency and interest rate risk~~October 2022 sale 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 during the next twelve months is not material.~~

U.K. energy marketing business (see Note 5).

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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, September 30, 2017 and December 31, 2016, and the final settlement date of the Company's open derivative transactions as of December 31, 2017, excluding those derivatives that qualified for the NPNS exception:

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 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 December 31, 2022, 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 $772. 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 cash deposits in margin accounts.~~ At December 31, ~~2017, September 30, 2017~~2022, we had received cash collateral from derivative instrument counterparties totaling $108. 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)~~

At December 31, ~~2017,~~2022, 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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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:


	December 31, 2022		September 30, 2022		December 31, 2021
Derivative assets:
Derivatives designated as hedging instruments:

Foreign currency contracts	$	11	$	57	$	10
Interest rate contracts	63		66		5
	74		123		15
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	18		31		10
Derivatives not designated as hedging instruments:
Commodity contracts (a)	656		2,202		1,112
Foreign currency contracts	24		62		19
	680		2,264		1,131
Total derivative assets — gross	772		2,418		1,156
Gross amounts offset in the balance sheet	(239)		(295)		(116)
Cash collateral received	(108)		(398)		(205)
Total derivative assets — net	$	425	$	1,725	$	835
Derivative liabilities:
Derivatives designated as hedging instruments:

Foreign currency contracts	$	—	$	—	$	(3)

Interest rate contracts	—		—		(17)
	—		—		(20)
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	(35)		(26)		(7)
Derivatives not designated as hedging instruments:
Commodity contracts (a)	(414)		(487)		(171)
Foreign currency contracts	(4)		(2)		(4)
	(418)		(489)		(175)
Total derivative liabilities — gross	(453)		(515)		(202)
Gross amounts offset in the balance sheet	239		295		116
Cash collateral pledged	45		7		—
Total derivative liabilities — net	$	(169)	$	(213)	$	(86)

(a)September 30, ~~2017~~2022 includes derivative assets and ~~December 31, 2016:~~liabilities held-for-sale associated with the October 2022 sale of the U.K. energy marketing business (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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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 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:	2022		2021		2022		2021



Interest rate contracts	$	4	$	12	$	7	$	(6)	Interest expense


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

	Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2022		2021		Location of Gain (Loss) Recognized in Income
Commodity contracts	$	4	$	8	Revenues
Commodity contracts	(1,326)		(273)		Cost of sales

Commodity contracts	3		—		Other operating income, net
Foreign currency contracts	(32)		8		Other non-operating (expense) income, net
Total	$	(1,351)	$	(257)

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

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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 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 December 31, 2022	Postretirement Benefit Plans		Derivative Instruments		Foreign Currency		Total
AOCI — September 30, 2022	$	14	$	37	$	(431)	$	(380)
Other comprehensive income before reclassification adjustments	—		3		151		154
Amounts reclassified from AOCI	—		(5)		—		(5)
Other comprehensive (loss) income attributable to UGI	—		(2)		151		149
AOCI — December 31, 2022	$	14	$	35	$	(280)	$	(231)

Three Months Ended December 31, 2021	Postretirement Benefit Plans		Derivative Instruments		Foreign Currency		Total
AOCI — September 30, 2021	$	(17)	$	(33)	$	(90)	$	(140)
Other comprehensive income (loss) before reclassification adjustments	—		10		(32)		(22)
Amounts reclassified from AOCI	2		4		—		6
Other comprehensive income (loss) attributable to UGI	2		14		(32)		(16)
AOCI — December 31, 2021	$	(15)	$	(19)	$	(122)	$	(156)

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~~expense on ~~commodity and certain foreign currency derivative instruments~~UGI debt that is 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.allocated. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company, and UGI corporate headquarters’ assets.

The accounting policies of our reportable segments are the same as those described in Note 2, “Summary of Significant Accounting Policies,” in the Company’s ~~2017~~2022 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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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 December 31, 2022	Total		Eliminations			AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other (a)
Revenues from external customers	$	2,759	$	—		$	766	$	877	$	554	$	559	$	3
Intersegment revenues	$	—	$	(149)	(b)	$	—	$	—	$	115	$	33	$	1
Cost of sales	$	3,106	$	(149)	(b)	$	386	$	662	$	514	$	329	$	1,364
Operating (loss) income	$	(1,204)	$	1		$	110	$	56	$	106	$	126	$	(1,603)
Income from equity investees	1		—			—		—		1		—		—

Other non-operating (loss) income, net	(28)		—			—		10		—		2		(40)
(Loss) earnings before interest expense and income taxes	(1,231)		1			110		66		107		128		(1,643)
Interest expense	(92)		—			(43)		(7)		(11)		(21)		(10)
(Loss) income before income taxes	$	(1,323)	$	1		$	67	$	59	$	96	$	107	$	(1,653)

Depreciation and amortization	$	131	$	—		$	44	$	28	$	21	$	37	$	1
Capital expenditures (including the effects of accruals)	$	178	$	—		$	23	$	27	$	11	$	117	$	—
As of December 31, 2022
Total assets	$	17,128	$	(252)		$	4,331	$	3,889	$	3,298	$	5,680	$	182



















Three Months Ended December 31, 2021	Total		Eliminations			AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corporate & Other (a)
Revenues from external customers	$	2,673	$	—		$	778	$	1,049	$	441	$	396	$	9
Intersegment revenues	$	—	$	(118)	(b)	$	—	$	—	$	94	$	23	$	1
Cost of sales	$	2,120	$	(117)	(b)	$	418	$	793	$	413	$	200	$	413
Operating (loss) income	$	(68)	$	—		$	86	$	78	$	74	$	96	$	(402)
Income from equity investees	8		—			—		—		8		—		—
Loss on extinguishments of debt	(11)		—			—		—		—		—		(11)
Other non-operating income, net	10		—			—		4		—		2		4
(Loss) earnings before interest expense and income taxes	(61)		—			86		82		82		98		(409)
Interest expense	(81)		—			(41)		(7)		(10)		(16)		(7)
(Loss) income before income taxes	$	(142)	$	—		$	45	$	75	$	72	$	82	$	(416)

Depreciation and amortization	$	129	$	—		$	44	$	31	$	19	$	35	$	—
Capital expenditures (including the effects of accruals)	$	175	$	—		$	35	$	23	$	6	$	111	$	—
As of December 31, 2021
Total assets	$	16,800	$	(269)		$	4,614	$	4,197	$	2,999	$	5,071	$	188

(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 ~~financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies. Our CODM evaluates~~allocating resources. The following table presents such pre-tax gains (losses) which have been included in Corporate & Other, and the ~~performance 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, as previously mentioned.to which they relate:

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
$ —

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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)














Three Months Ended December 31, 2022	Location on Income Statement	AmeriGas Propane		UGI International		Midstream & Marketing
Net gains on commodity derivative instruments not associated with current-period transactions	Revenues	$	—	$	2	$	2
Net losses on commodity derivative instruments not associated with current-period transactions	Cost of sales	$	(12)	$	(1,169)	$	(183)
Net gains on commodity derivative instruments not associated with current-period transactions	Other operating income, net	$	—	$	(2)	$	—


Unrealized losses on foreign currency derivative instruments	Other non-operating (expense) income, net	$	—	$	(40)	$	—



AmeriGas operations enhancement for growth project	Operating and administrative expenses	$	(7)	$	—	$	—
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)	$	—

~~(a)The following table provides a reconciliation~~









Three Months Ended December 31, 2021	Location on Income Statement	AmeriGas Propane		UGI International		Midstream & Marketing
Net gains on commodity derivative instruments not associated with current-period transactions	Revenues	$	—	$	3	$	7
Net losses on commodity derivative instruments not associated with current-period transactions	Cost of sales	$	(69)	$	(212)	$	(132)
Unrealized gain on foreign currency derivative instruments	Other non-operating (expense) income, net	$	—	$	6	$	—


Loss on extinguishment of debt	Loss on extinguishment of debt	$	—	$	(11)	$	—

(b)Represents the elimination of ~~Partnership Adjusted EBITDA to~~intersegment transactions principally among Midstream & Marketing, Utilities and AmeriGas ~~Propane income before income taxes:~~ Propane.

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.~~

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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 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 a global pandemic, including the duration and/or impact of the COVID-19 pandemic; (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, 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~~2022 three-month ~~period”)~~period with the ~~three months ended December 31, 2016 (“2016~~2021 three-month ~~period”).~~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

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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.~~

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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 attributable to UGI Corporation, and reconcile diluted ~~earnings~~loss per share, the most directly comparable GAAP measure, to adjusted diluted earnings per ~~share, to reflect the adjustments referred to above:~~share:


Adjusted net income attributable to UGI Corporation	Three Months Ended December 31,
(Dollars in millions)		2022		2021
AmeriGas Propane		$	49	$	34
UGI International		45		57
Midstream & Marketing		77		51
Utilities		81		63
Corporate & Other (a)		(1,206)		(302)
Net loss attributable to UGI Corporation		(954)		(97)
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $(363) and $(111), respectively)		999		292
Unrealized losses (gains) on foreign currency derivative instruments (net of tax of $(11), and $2, respectively)		29		(4)
Loss on extinguishment of debt (net of tax of $0 and $(3), respectively)		—		8
Acquisition and integration expenses associated with the Mountaineer Acquisition (net of tax of $0 and $0, respectively)		—		1
Business transformation expenses (net of tax of $(1) and $(1), respectively)		1		1
AmeriGas operations enhancement for growth project (net of tax of $(2) and $0, respectively)		5		—


Loss on disposal of U.K. energy marketing business (net of tax of $(64) and $0, respectively)		151		—
Impairment of assets (net of tax of $(4) and $0, respectively)		15		—

Total adjustments (a) (b)		1,200		298
Adjusted net income attributable to UGI Corporation		$	246	$	201


	Three Months Ended December 31,
Adjusted diluted earnings per share		2022		2021
AmeriGas Propane		$	0.23	$	0.16
UGI International		0.21		0.26
Midstream & Marketing		0.35		0.24
Utilities		0.38		0.29
Corporate & Other (a)		(5.71)		(1.41)
Loss per share - diluted (c)		(4.54)		(0.46)
Net losses on commodity derivative instruments not associated with current-period transactions (c)		4.73		1.37
Unrealized losses (gains) on foreign currency derivative instruments		0.14		(0.02)
Loss on extinguishment of debt		—		0.03
Acquisition and integration expenses associated with the Mountaineer Acquisition		—		—
Business transformation expenses		—		0.01
AmeriGas operations enhancement for growth project		0.02		—


Loss on disposal of U.K. energy marketing business		0.72		—
Impairment of assets		0.07		—

Total adjustments (a)		5.68		1.39
Adjusted earnings per share - diluted (c)		$	1.14	$	0.93

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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(a)Corporate & Other includes certain adjustments made to our reporting segments in arriving at net income 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.

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

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.~~

~~RESULTS OF OPERATIONS~~

~~2017 three-month period compared~~(c)The loss per share for the three months ended December 31, 2022 and 2021, was determined excluding the effect of 6.43 million and 6.49 million dilutive shares, respectively, as the impact of such shares would have been antidilutive to the ~~2016 three-month period~~

~~Note - Average temperatures~~net loss for the periods.Adjusted earnings per share for the three months ended December 31, 2022 and 2021, was determined based upon ~~heating degree days~~fully dilutive shares of 216.37 million and 216.16 million, respectively.

EXECUTIVE OVERVIEW

Recent Developments

European Energy Marketing Business.

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 three months ended December 31, 2022, 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 definitive agreement during the first quarter of Fiscal 2023 as extended negotiations with the potential buyer had been discontinued. The Company continues to pursue the sale of its energy marketing business in France, as well as the wind-down of its energy marketing business located in Belgium and the Netherlands. At December 31, 2022, the sale of our energy marketing business in France was not considered probable of occurring within one year and, as such, assets and liabilities associated with this business was not classified as held for sale on the Condensed Consolidated Balance Sheet.

During the three months ended December 31, 2022, the Company recorded a $19 million pre-tax ($15 million after-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.

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 increases in inventory and certain operating and distribution expenses across all of our businesses. The commodity prices 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, ~~segments presented below are now based upon recent 15-year periods (rather than recent 30-year periods)~~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 ~~we believe more recent temperatures are a better indication of normal heating degree days. Prior-period weather statistics have been restated, as appropriate,~~these conditions continue to ~~conform to the new periods.~~evolve.

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2022 three-month period compared with 2021 three-month period

Discussion. Net loss attributable to UGI Corporation for the 2022 three-month period was $954 million (equal to $4.54 per diluted share) compared to net loss attributable to UGI Corporation of $97 million (equal to $0.46 loss per diluted share) during the 2021 three-month period. These results include net losses from changes in unrealized commodity derivative instruments and certain foreign currency derivative instruments of $1,028 million and $288 million during the 2022 and 2021 three-month periods, respectively. The higher losses from changes in commodity derivative instruments during the 2022 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 2022 three-month period also includes (1) 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; (2) an impairment of assets of $15 million; (3) external advisory fees of $5 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 2021 three-month period also includes (1) an $8 million loss on extinguishment of debt at UGI International; (2) acquisition and integration expenses of $1 million associated with the Mountaineer Acquisition; and (3) business transformation expenses of $1 million.

Adjusted net income attributable to UGI Corporation for the 2022 three-month period was $246 million (equal to $1.14 per diluted share) compared to $201 million (equal to $0.93 per diluted share) during the 2021 three-month period. The increase in adjusted net income attributable to UGI Corporation during the 2022 three-month period reflects higher earnings contributions from our Midstream & Marketing, Utilities and AmeriGas Propane

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 )% —
—


~~(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.

business segments partially offset by a lower earnings contribution from UGI International. Temperatures in our domestic business segments during the 2022 three-month period were colder than the prior-year period while temperatures in our UGI International segment were significantly warmer than the prior-year period.

AmeriGas Propane’s adjusted net income attributable to UGI Corporation increased $15 million in the 2022 three-month period. This increase principally reflects higher average retail ~~gallons sold~~propane unit margin and slightly lower operating and administrative expenses primarily attributable to a workforce reduction made during Fiscal 2022 partially offset by higher distribution expenses.

UGI International’s adjusted net income attributable to UGI Corporation decreased $12 million in the 2022 three-month period. The lower net income reflects, in part, the weaker euro during the ~~2017~~2022 three-month period ~~were approximately equal~~compared to the prior-year period. ~~Average temperatures based upon~~Operating results reflect lower total margin principally due to the weaker currency and lower LPG volumes attributable to the warmer weather partially offset by the benefits of lower commodity prices and strong margin management. The lower total margin was partially offset by lower operating and administrative expenses principally reflecting the translation effects of the weaker euro.

Midstream & Marketing’s adjusted net income attributable to UGI Corporation increased $26 million in the 2022 three-month period on colder temperatures. The increase in adjusted net income is primarily attributable to higher margins related to natural gas marketing activities and incremental contributions from UGI Moraine East and Pennant.

Utilities’ adjusted net income attributable to UGI Corporation increased $18 million in the 2022 three-month period. The increase was largely related to the weather that was colder than the prior-year period, growth in the core market customers and the impacts of the PA Gas Utility base rate increase which became effective in October 2022. The increase in total margin was partially offset by higher operating and administrative expenses.

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SEGMENT RESULTS OF OPERATIONS

2022 Three-Month Period Compared with the 2021 Three-Month Period

AmeriGas Propane


For the three months ended December 31,	2022			2021			(Decrease) Increase
(Dollars in millions)
Revenues	$	766		$	778		$	(12)	(2)	%
Total margin (a)	$	380		$	360		$	20	6	%
Operating and administrative expenses	$	235		$	240		$	(5)	(2)	%
Operating income/earnings before interest expense and income taxes	$	110		$	86		$	24	28	%
Retail gallons sold (millions)	236			241			(5)		(2)	%
Heating degree days—% colder (warmer) than normal (b)	6.2		%	(9.9)		%	—		—

(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 U.S., excluding Alaska and Hawaii.

Average temperatures during the ~~2017~~2022 three-month period were ~~1.4% warmer~~6.2% colder than normal ~~but 9.9%~~and 17.9% colder than the prior-year period. ~~Average temperatures~~Notwithstanding the colder weather, total retail gallons sold decreased 2% during the ~~2017~~2022 three-month period ~~were significantly influenced by much colder than normal temperatures that occurred during the last week~~due to staffing shortages in key delivery-related positions, which also limited growth, as well as continuation 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.customer attrition, along with structural conservation.

AmeriGas Propane’s retail propane revenues increased $99.2 million during the 2017 three-month period reflecting the 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) and higher wholesale volumes sold ($2.6 million). Average daily wholesale propane commodity prices during the ~~2017~~2022 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately ~~64% higher~~36% lower than such prices during the ~~2016~~2021 three-month period. ~~Other~~Total revenues indecreased $12 million during the ~~2017~~2022 three-month period ~~were slightly~~largely reflecting the lower retail propane revenues ($11 million) primarily on the lower volumes sold and lower wholesale revenues ($5 million) partially offset by higher ~~than in the prior-year period. AmeriGas Propane total~~revenues from ancillary sales and services ($5 million).

Total cost of sales ~~increased $105.4~~decreased $32 million ~~principally~~during the 2022 three-month period largely reflecting the ~~effects of higher~~lower average propane product costs ($~~103.0~~36 million) and ~~to a much lesser extent,~~ the ~~effects of the higher wholesale~~lower retail propane volumes ~~sold.~~

~~AmeriGas Propane total margin increased $4.7 million in the 2017 three-month period principally reflecting slightly higher retail propane total margin~~sold ($~~2.6 million) and slightly higher non-propane total margin ($2.1 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 ($7.8~~7 million) partially offset by ~~slightly higher Partnership operating and administrative expenses~~the increase in wholesale volumes sold ($~~3.5~~9 million). The increase in other operating income reflects the absence of an $8.8 million adjustment recorded in the prior-year period to correct previously recorded gains on sales of fixed assets acquired with the Heritage Propane acquisition in 2012. The increase in operating and administrative expenses principally reflects 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.

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~~UGI CORPORATION AND SUBSIDIARIES~~

~~AmeriGas Propane operating income~~Total margin increased ~~$6.0~~$20 million in the ~~2017~~2022 three-month period ~~principally reflecting~~largely attributable to 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 % —
—


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

~~Average temperatures during the 2017 three-month period were approximately 0.9% warmer than normal and 7.0% warmer than the prior-year period. Total~~ retail gallons sold during the 2017 three-month period were 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 in Italy (now known as “UniverGas”) werepropane unit margins ($26 million) partially offset by the effects of the ~~warmer weather on bulk sales~~lower retail propane volumes sold ($6 million).

Operating income and earnings before interest expense and income taxes each increased $24 million during the 2022 three-month period primarily reflecting the previously mentioned increase in total margin and lower ~~crop-drying volumes. During~~operating and administrative expenses ($5 million). The decrease in operating and administrative expenses reflects lower salaries and benefits expenses, including the ~~2017~~carryover impact from the workforce reductions made during Fiscal 2022, partially offset by higher overtime and contractor costs associated with distribution activity and higher vehicle expenses.

UGI International


For the three months ended December 31,	2022			2021			Decrease
(Dollars in millions)
Revenues	$	877		$	1,049		$	(172)	(16)	%
Total margin (a)	$	215		$	256		$	(41)	(16)	%
Operating and administrative expenses	$	143		$	161		$	(18)	(11)	%
Operating income	$	56		$	78		$	(22)	(28)	%
Earnings before interest expense and income taxes	$	66		$	82		$	(16)	(20)	%
LPG retail gallons sold (millions)	205			249			(44)		(18)	%
Heating degree days—% (warmer) colder than normal (b)	(12.3)		%	5.0		%	—		—

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

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UGI CORPORATION AND SUBSIDIARIES

(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 2022 three-month period ~~average wholesale commodity prices for propane~~were 12.3% warmer than normal and ~~butane in northwest Europe~~18.8% warmer than the prior-year period. Total LPG retail gallons sold during the 2022 three-month period were ~~approximately 37% and 25% higher~~18% lower than in the prior-year period ~~respectively.~~largely attributable to reduced crop drying campaigns, significantly warmer weather and lower consumption, principally from residential customers, primarily resulting from conservation measures due in large part to high energy prices and 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~~2022 and ~~2016~~2021 three-month periods, the average ~~un-weighted euro-to-dollar~~unweighted euro-to-USD translation rates were approximately ~~$1.18~~$1.02 and ~~$1.08,~~$1.14, respectively, and the average ~~un-weighted~~unweighted British pound ~~sterling-to-dollar~~sterling-to-USD translation rates were approximately ~~$1.33~~$1.17 and ~~$1.25,~~$1.35, 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 in earnings. These forward foreign currency exchange contracts resulted in realized net gains of $8 million and $4 million in the 2022 and 2021 three-month periods, respectively.

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 $172 million and $131 million, respectively, during the ~~2017~~2022 three-month period ~~reflecting~~compared to the prior-year period. Average wholesale prices for propane and butane during the 2022 three-month period in northwest Europe were approximately ~~$119.0 million of incremental~~16% and 6% lower, respectively, compared with the prior-year period. The decrease in revenues and cost of sales ~~associated with UniverGas and DVEP, higher average LPG commodity costs,~~principally reflects the lower retail volumes sold and the translation effects of the ~~stronger euro~~weaker foreign currencies (approximately $100 million and ~~British pound sterling.~~$73 million, respectively).

UGI International total margin ~~increased $18.3~~decreased $41 million during the 2022 three-month period primarily reflecting the ~~translation~~ effects of the stronger euro and British pound sterling and approximately $18.0 million of incremental margin from UniverGas and DVEP. These increases in margin were partially offset by the effects on legacy business total margin resulting from slightly lower average LPG retail bulk and

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~~cylinder unit margins, the lower legacy business LPG retail volume sales and, to a much lesser extent, slightly~~ lower retail ~~natural gas total margin on lower average unit margins.~~

The $4.2 million increase in UGI International operating income principally reflects the previously mentioned $18.3 million increase in total margin partially offset by an $8.3 million increase in operating and administrative costs and a $4.3 million increase in depreciation and amortization expense. The increase in operating and administrative costs principally reflects the translation effects of the stronger euro and British pound sterling on local currency expenses and approximately $10.0 million of incremental expenses from UniverGas and DVEP. These increases in operating and administrative expenses were partially offset by lower local currency operating expenses at our legacy 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 DVEP ($2.8 million)volumes sold and the translation effects of the ~~stronger currencies. UGI International income before income taxes decreased $1.4 million principally reflecting~~weaker foreign currencies (approximately $27 million). These factors were partially offset by higher average unit margins from our LPG business attributable to strong margin management efforts. Total margin from energy marketing activities were comparable to the ~~previously mentioned $4.2 million increase in~~ prior-year period as higher total margin from natural gas marketing activities was offset by lower total margin from electricity marketing activities.

UGI International operating income ~~reduced by realized losses on foreign currency exchange contracts ($4.7 million)~~ and ~~slightly higher~~earnings before 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 higher total margin from our midstream assets ($8.0 million), principally 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.

~~Midstream & Marketing operating income~~ and income ~~before income~~ taxes ~~during the 2017 three-month period increased $2.6~~decreased $22 million and ~~$3.5~~$16 million, respectively. The ~~increase~~decrease in operating income principally reflects the previously mentioned $41 million decrease in total margin and lower gains associated with sales of assets ($10 million), partially offset by lower operating and administrative expenses ($18 million), higher foreign currency transaction gains ($7 million) and lower depreciation and amortization expenses ($3 million). The lower operating and administrative expenses in the 2022 three-month period primarily reflects the translation effects of the weaker foreign currencies. The decrease in earnings before interest expense and income taxes in the 2022 three-month period largely reflects the $22 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 three months ended December 31,	2022		2021		Increase
(Dollars in millions)
Revenues	$	669	$	535	$	134	25	%
Total margin (a)	$	155	$	122	$	33	27	%
Operating and administrative expenses	$	29	$	29	$	—	—	%
Operating income	$	106	$	74	$	32	43	%
Earnings before interest expense and income taxes	$	107	$	82	$	25	30	%

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

Average temperatures across Midstream & Marketing’s energy marketing territory during the 2022 three-month period were 1% warmer than normal and 13% colder than the prior-year period.

Midstream & Marketing revenues increased $134 million compared to the prior-year period, principally reflecting increased revenues from natural gas and power marketing activities ($119 million), including the effects of peaking and capacity

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management activities, that were impacted by higher natural gas prices. The increase in revenues also includes higher natural gas gathering activities ($14 million), primarily due to the prior year acquisitions of UGI Moraine East and Pennant, and power generation, partially offset by reduced RNG credit sales.

Midstream & Marketing cost of sales increased $101 million compared to the prior-year period, primarily reflecting the higher natural gas costs related to the previously mentioned natural gas and power marketing activities ($97 million).

Midstream & Marketing total margin increased $33 million in the 2022 three-month period reflecting increased margins from natural gas marketing activities ($18 million), including the effects of peaking and capacity management activities from particularly cold weather at the end of December. The increase in total margin also includes incremental natural gas gathering activities ($~~11.0~~14 million), primarily from the prior year acquisitions of UGI Moraine East and Pennant.

Midstream & Marketing operating income and earnings before interest expense and income taxes during the 2022 three-month period increased $32 million and $25 million, respectively, compared to the prior-year period. The increase in operating income is largely attributable to the previously mentioned increase in total margin. The increase in earnings before interest expense and income taxes principally reflects the increase in operating income, partially offset by lower income from equity method investments following the acquisition of the remaining 53% ownership interest in Pennant during the fourth quarter of Fiscal 2022.

Utilities


For the three months ended December 31,	2022			2021			Increase
(Dollars in millions)
Revenues	$	592		$	419		$	173	41	%
Total margin (a)	$	256		$	213		$	43	20	%
Operating and administrative expenses (a)	$	91		$	80		$	11	14	%
Operating income	$	126		$	96		$	30	31	%
Earnings before interest expense and income taxes	$	128		$	98		$	30	31	%
Gas Utility system throughput—bcf
Core market	34			29			5		17	%
Total	94			93			1		1	%
Electric Utility distribution sales - gwh	246			242			4		2	%
Gas Utility heating degree days—% colder (warmer) than normal (b)	0.2		%	(15.1)		%	—		—

(a)Total margin represents revenues less cost of sales and revenue-related taxes (i.e., gross receipts and business and occupation taxes) of $7 million and $6 million, respectively, during the 2022 and 2021 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).

(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 2022 three-month period were slightly colder than normal and 17.3% colder than the prior-year period. The increase in Gas Utility core market volumes (5 bcf or a 17% increase) during the 2022 three-month period is largely related to the weather that was colder than the prior-year period and growth in the core market customers.

Utilities revenues increased $173 million in the 2022 three-month period reflecting a $163 million increase in Gas Utility revenues and a $10 million increase in Electric Utility revenues. The increase in Gas Utility revenues was largely driven by higher PGC rates reflecting higher natural gas costs, higher core market volumes, higher pricing on off-system sales, and the effects of the increase in base rates for PA Gas Utility that went into effect in October 2022. The increase in Electric Utility revenues was largely driven by higher DS rates reflecting higher power costs.

Utilities cost of sales (including revenue-related taxes) increased $130 million in the 2022 three-month period primarily attributable to Gas Utility ($122 million) mainly reflecting higher PGC rates and, to a much lesser extent, increased cost of sales associated with off-system sales. Electric Utility cost of sales increased $8 million during the 2022 three-month period largely reflecting the higher DS rates.

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Utilities total margin increased $43 million during the 2022 three-month period primarily attributable to higher Gas Utility total margin ($41 million) mainly reflecting weather that was colder than the prior-year period and the effects of the increase in base rates for PA Gas Utility that went into effect in October 2022. Electric Utility margin was relatively flat compared to the prior-year period.

Utilities operating income and earnings before interest expense and income taxes each increased $30 million during the 2022 three-month period. These increases largely reflect the previously mentioned increase in total margin partially offset by higher operating and administrative expenses ($~~3.7~~11 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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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 ($4.42 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, taxes other than income taxes and ~~greater~~salary 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 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~~2022 three-month period was ~~$58.2~~$92 million ~~$2.8~~compared to $81 million ~~higher than the $55.4 million of interest expense recorded~~ during the ~~2016~~2021 three-month period. The ~~higher~~increase in interest expense principally reflects the effects of higher credit agreement interest rates and borrowings, and higher long-term debt outstanding primarily at ~~AmeriGas Propane 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~~decrease 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~~Company’s effective income tax rate for the ~~2017~~2022 three-month period ~~was lower than in~~principally reflects the ~~prior-year period principally reflecting~~effects on the ~~lower blended U.S.~~estimated annual effective income tax rate from a greater concentration of ~~24.5%~~pre-tax results in ~~Fiscal 2018~~higher tax rate jurisdictions primarily resulting from the significant current-period losses on commodity derivative instruments at our UGI International segment, an expected increase in deferred tax valuation allowances, and the availability of investment tax credits in Fiscal 2023 following enactment of the ~~TCJA.~~Inflation Reduction Act.

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.

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 $1.2 billion and $1.7 billion at December 31, 2022 and September 30, 2022, respectively. Our total available liquidity at December 31, 2022 was affected, in part, by the impact of cash collateral payments associated with a significant decline in commodity prices during the 2022 three-month period and increases in restricted cash margin requirements in commodity futures brokerage accounts, principally at UGI International. The Company does not have any scheduled near-term maturities of long-term debt, other than the UGI International Credit Facilities Agreement. The UGI International Credit Facilities Agreement, consists of (1) a €300 million variable-rate term loan facility and (2) a €300 million multicurrency revolving credit facility, which is scheduled to mature in October 2023. At December 31, 2022, the €300 million ($321 million) variable-rate term loan is reflected in “Current maturities of long-term debt” on the Condensed Consolidated Balance Sheet. The Company expects to refinance the UGI International Credit Facilities Agreement during the first half of Fiscal 2023. In the absence of a refinance, the Company expects to have sufficient liquidity to satisfy its obligations as they become due over 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 December 31, 2022.

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.

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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~~$317 million at December 31, ~~2017,~~2022, 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 2022 three-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~~2022 and September 30, ~~2017,~~2022, UGI had ~~$162.0~~$120 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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Long-term Debt and ~~Short-term Borrowings~~Credit Facilities

Long-term Debt

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


	December 31, 2022												September 30, 2022
(Millions of dollars)	AmeriGas Propane		UGI International		Midstream & Marketing		Utilities		Corp & Other		Total		Total
Short-term borrowings	$	148	$	327	$	121	$	395	$	—	$	991	$	368

Long-term debt (including current maturities):
Senior notes	$	2,575	$	429	$	—	$	1,505	$	—	$	4,509	$	4,472
Term loans	—		321		676		134		756		1,887		1,871
Other long-term debt	—		2		40		23		298		363		322
Unamortized debt issuance costs	(11)		(6)		(7)		(6)		(4)		(34)		(33)
Total long-term debt	$	2,564	$	746	$	709	$	1,656	$	1,050	$	6,725	$	6,632
Total debt	$	2,712	$	1,073	$	830	$	2,051	$	1,050	$	7,716	$	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 56 to ~~the~~ Consolidated Financial Statements in the Company’s ~~2017~~2022 Annual Report.

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Information about the Company’s principal credit agreements (excluding the ~~Energy Services~~ Receivables Facility discussed below) as of December 31, ~~2017~~2022 and ~~2016,~~2021, is presented in the table below.


(Currency in millions)	Total Capacity		Borrowings Outstanding		Letters of Credit and Guarantees Outstanding		Available Borrowing Capacity
As of December 31, 2022
AmeriGas OLP	$	600	$	148	$	2	$	450
UGI International, LLC (a)	€	300	€	300	€	—	€	—
Energy Services	$	260	$	—	$	—	$	260
UGI Utilities	$	425	$	294	$	—	$	131
Mountaineer	$	150	$	101	$	—	$	49
UGI Corporation (b)	$	300	$	292	$	—	$	8
As of December 31, 2021
AmeriGas OLP	$	600	$	205	$	3	$	392
UGI International, LLC (a)	€	300	€	—	€	—	€	300
Energy Services	$	260	$	—	$	—	$	260
UGI Utilities	$	350	$	253	$	—	$	97
Mountaineer	$	100	$	66	$	—	$	34
UGI Corporation (b)	$	300	$	255	$	—	$	45

(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
(a)Permits UGI International, LLC to borrow in euros or USD. At December 31, 2022, the amount borrowed consisted of euro-denominated borrowings equivalent to $321 million.


~~(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.

(b)Borrowings outstanding have been classified as “Long-term debt” on the Condensed Consolidated Balance Sheets. Subsequent to December 31, 2022, the Company repaid $20 million of such borrowings and classified these repayments as “Current maturities of long-term debt” on the December 31, 2022 Condensed Consolidated Balance Sheet.

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 three months ended				For the three months ended
	December 31, 2022				December 31, 2021
(Millions of dollars or euros)	Average		Peak		Average		Peak
AmeriGas OLP	$	199	$	242	$	275	$	388
UGI International, LLC	€	168	€	300	€	13	€	40
Energy Services	$	1	$	25	$	—	$	—
UGI Utilities	$	229	$	307	$	190	$	258
Mountaineer	$	89	$	101	$	61	$	80
UGI Corporation	$	199	$	292	$	125	$	255

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.

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At December 31, 2022, the outstanding balance of ESFC trade receivables was $128 million, $121 million of which were sold to the bank. At December 31, 2021, the outstanding balance of ESFC trade receivables was $115 million, none of which were sold to the bank. During the three months ended December 31, ~~2017 and 2016,~~2022, peak sales of receivables ~~were $45.0 million and $36.5 million, respectively,~~ and average daily amounts sold were ~~$28.6~~$121 million and ~~$23.7~~$30 million, respectively. ~~For additional information regarding~~There were no sales of receivables under the Receivables Facility ~~see Note 8~~during the three months ended December 31, 2021.

Significant Financing Activities

UGI Utilities Credit Agreement. On December 13, 2022, UGI Utilities entered into an amendment to the ~~condensed consolidated financial statements.~~UGI Utilities Credit Agreement, providing for borrowings up to $425 million and to replace the use of LIBOR with 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, as borrower, 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.

Borrowings under the Mountaineer 2023 Credit Agreement bear interest, subject to our election, at either (i) the 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 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.

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~~Director’s declared a quarterly dividend of ~~$0.25~~$0.36 per common share. The dividend is payable April 1, ~~2018,~~2023, to shareholders of record on March 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 three months ended December 31, 2022, the Company purchased 0.3 million shares on the open market at a total purchase price of approximately $12 million.

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~~used by operating activities was ~~$31.4~~$240 million in the ~~2017~~2022 three-month period compared to ~~$126.6~~$594 million in the ~~2016~~2021 three-month period. Cash flow from operating activities before changes in operating working capital was ~~$384.6~~$491 million in the ~~2017~~2022 three-month period compared to ~~$333.9~~$330 million in the ~~prior-year~~2021 three-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~~$731 million in the ~~2017~~2022 three-month period compared to ~~$207.3~~$924 million in the ~~prior-year~~2021 three-month period. The ~~higher~~

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decrease in cash used to fund operating working capital changes in the 2022 three-month period principally reflects lower cash required to fund changes in accounts receivable and inventories ~~reflects,~~reflecting in large part the ~~impact~~effects of ~~higher LPG~~lower commodity prices and ~~natural gas costs during~~lower volumes in the current-year period. Partially offsetting these lower cash requirements were higher cash collateral payments associated with commodity derivative instruments principally reflecting repayments of collateral received in prior periods as a result of the changes in commodity prices.

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 $271 million in the 2022 three-month period compared to $154 million in the 2021 three-month period. Cash expenditures for property, plant and equipment were ~~$147.5~~$210 million in the 2017 three-month period compared to $197.1 million in the prior-year period. Cash payments in the prior-year included capital expenditures associated with the Sunbury Pipeline project at Midstream & Marketing. 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.

~~Financing Activities.~~ ~~Cash flow provided by financing activities was $181.1 million in the 2017~~2022 three-month period compared with ~~$98.6~~$186 million in the ~~prior-year period.~~2021 three-month period principally reflecting higher cash capital expenditures in our Utilities segment. Investments in equity method investments during the 2022 three-month period include our continuing investments in renewable energy projects. Cash inflows associated with investing activities during the 2021 three-month period includes cash received from the settlement of certain forward foreign currency contracts.

Financing Activities. 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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~~UGI Utilities issued $125~~Cash flow provided by financing activities was $548 million ~~of unsecured notes and used~~in the ~~proceeds principally~~2022 three-month period compared to ~~reduce~~$234 million in the 2021 three-month period. The higher cash flow from financing activities in the 2022 three-month period is due to higher short-term borrowings ~~and for general corporate purposes.~~

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

~~On November 7, 2017, UGI entered into~~of which 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~~large portion of the ~~Class B Units they own into Common Units on a one-for-one basis,~~proceeds were used to fund derivative commodity instrument collateral repayments and ~~at any time after six years~~restricted cash margin requirements in commodity futures brokerage accounts. Cash flow 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.

~~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 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 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,~~prior-year period includes 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~~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.

~~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~~28, 2023. However, the ~~PUC~~PAPUC typically suspends the effective date for general base rate proceedings for a period not to exceed nine months after the filing date to allow for the investigation and public ~~hearings. This review process is expected to last up to nine months; however, the~~hearing. 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 5-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 rate 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 ~~effective~~by $6 million.

Mountaineer. On February 1, 2023, Mountaineer filed a Notice of Intent to File a General Rate Case with the WVPSC.

On July ~~1, 2017,~~29, 2022, Mountaineer submitted its 2022 IREP filing to the WVPSC requesting recovery of costs associated with capital investments totaling $354 million over the 2023 - 2027 five-year period, including $64 million in calendar year 2023. On November 16, 2022, Mountaineer and the intervening parties submitted a Joint Stipulation and Agreement for ~~PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018. PNG’s DSIC has been reset~~Settlement to ~~zero as a result~~the WVPSC requesting approval of ~~its most recent rate case. The DSIC rate for PNG will resume upon exceeding the threshold amount~~2023 IREP revenue 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~~$22 million to ~~establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers,~~be charged effective January 1, ~~2017. UGI Gas will be permitted to recover revenue under~~2023, which includes the ~~mechanism~~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 ~~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.~~

Settlement as filed.

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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,~~2022, 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 all or 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,~~2022, 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~~$1,774 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,~~2022, by approximately ~~$135.0~~$105 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.

~~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 the euro and British pound sterling, we ~~have entered~~enter into forward foreign currency exchange contracts.

~~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 December 31, 2022, 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~~$772 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 December 31, ~~2017.~~2022, we had received cash collateral from derivative instrument counterparties totaling $108 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,~~2022, 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 December 31, 2022 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
December 31, 2022
Commodity price risk (1)	$	242	$	(214)
Interest rate risk (2)	$	63	$	(9)
Foreign currency exchange rate risk (3)	$	31	$	(43)

(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 U.S. dollar.

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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, 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.

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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,~~Report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2022 Annual Report, ~~on Form 10-K for the fiscal year ended~~ ~~September 30, 2017~~, which could materially affect our business, financial condition or future results. The risks described below and in our 2022 Annual Report ~~on Form 10-K~~ 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 dramatically 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 stable price and availability conditions. The European energy markets have entered in an unprecedented state of volatility. In addition to the pre-existing natural gas supply shortages, the war between Russia and Ukraine and the resulting substantial reduction of natural gas imports from Russia to Europe have led to significant volatility in the costs of both wholesale gas and power, and have created new risks that we have experienced and expect to continue to experience in Fiscal 2023 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 purchase incremental additional volumes consumed in excess of 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 costs, including balancing costs, onto customers due, among other things, to timing, regulatory and contractual constraints, and (iv) the ability to maintain hedging services to customers due to the margining and liquidity constraints as well as maximum trading limits implemented by clearing banks on supplier counterparties. 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. On October 25, 2022, UGI announced the sale of its energy marketing business in the United Kingdom and in November 2022, UGI announced its intent to sell its energy marketing business located in France, with a definitive agreement expected to be signed in the first quarter of Fiscal 2023, which did not occur. In December 2022, the Company announced that the negotiations with the potential buyer for the French energy marketing business had ceased and the exit of that business would be delayed. Further, in November 2022, the Company announced its intent to wind down its energy marketing businesses in Belgium and 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.~~2022.


Period	(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 Plans or Programs (1)
October 1, 2022 to October 31, 2022	—	$0.00	—	7.10 million
November 1, 2022 to November 30, 2022	—	$0.00	—	7.10 million
December 1, 2022 to December 31, 2022	300,000	$38.85	300,000	6.80 million
Total	300,000		300,000

(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.

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)~~

In January 2014, the UGI 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, the UGI Board of Directors authorized an extension of the share repurchase program for up to 8 million shares of UGI Corporation Common Stock for an additional four-year period.

~~- 49 -~~

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UGI CORPORATION AND SUBSIDIARIES

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

10.1

Form of Confidentiality, Non-Competition and Non-Solicitation Agreement between UGI Corporation and Mr. Robert F. Beard.

10.2

First Amendment to Credit Agreement, dated December 13, 2022, by and among UGI Utilities, Inc., the lenders party thereto and PNC Bank, National Association, as administrative agent.

UGI

Form 8-K (12/13/22)

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 , 2022, 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 , 2022, 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 December 31 , 2022, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

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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



10.1
~~10.1~~	~~Multicurrency Revolving Credit~~Form of Confidentiality, Non-Competition and Non-Solicitation Agreement ~~dated December 19, 2017, by~~between UGI Corporation 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.Mr. Robert F. Beard.

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,~~, 2022, 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,~~, 2022, 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,~~, 2022, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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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:			February 2, 2023	By:	/s/ Ted J. Jastrzebski
					Ted J. Jastrzebski
					Chief Financial Officer


Date:			February 2, 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 -~~49



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,~~, 2022, September 30, ~~2017~~202 2 and December ~~31, 2016~~ 3 1 , 2021			15

Condensed Consolidated Statements of Income for the three months ended December 31 ~~2017~~, 2022 and ~~2016~~2021			26

Condensed Consolidated Statements of Comprehensive Income for the three months ended December ~~31, 2017~~ 3 1 , 2022 and ~~2016~~2021			37

Condensed Consolidated Statements of Cash Flows for the three months ended December 31, ~~2017~~2022 and ~~2016~~2021			48

Condensed Consolidated Statements of Changes in Equity for the three months ended December 31, ~~2017~~2022 and ~~2016~~2021			59

Notes to Condensed Consolidated Financial Statements			610

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			30

Item 3. Quantitative and Qualitative Disclosures About Market Risk			4643

Item 4. Controls and Procedures			4845

Part II Other Information

Item 1. Legal Proceedings			46

Item 1A. Risk Factors			4946

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			4946

Item 6. Exhibits			5047

Signatures			5249


	December 31, 2017			September 30, 2017			December 31, 2016				December 31, 2022		September 30, 2022		December 31, 2021
ASSETS										ASSETS
Current assets:										Current assets:
Cash and cash equivalents	$	446.4		$	558.4		$	515.2		Cash and cash equivalents	$	317	$	405	$	334
Restricted cash	19.8			10.3			7.9			Restricted cash	227		64		24
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 $69, $64 and $57, respectively)										Accounts receivable (less allowances for doubtful accounts of $69, $64 and $57, respectively)	1,578		1,127		1,461
Accrued utility revenues	95.9			13.3			55.6			Accrued utility revenues	147		23		95
Income taxes receivable										Income taxes receivable	51		128		128
Inventories	307.3			278.6			228.2			Inventories	618		665		548
Utility regulatory assets	0.6			8.3			1.6

Derivative instruments	73.4			63.1			87.0			Derivative instruments	238		865		578
Held for sale assets (Note 5)										Held for sale assets (Note 5)	—		295		—
Prepaid expenses and other current assets	135.4			138.7			97.1			Prepaid expenses and other current assets	280		230		263
Total current assets	2,180.6			1,697.5			1,909.9			Total current assets	3,456		3,802		3,431
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 $4,344, $4,166 and $4,047, respectively)										Property, plant and equipment, (less accumulated depreciation of $4,344, $4,166 and $4,047, respectively)	8,176		8,040		7,597
Goodwill	3,185.5			3,107.2			2,935.8			Goodwill	3,697		3,612		3,748
Intangible assets, net	641.9			611.7			558.9			Intangible assets, net	488		500		565
Utility regulatory assets	362.2			360.6			391.3			Utility regulatory assets	314		301		372
Derivative instruments	13.3			9.2			24.2			Derivative instruments	187		565		257

Other assets	269.9			259.0			236.1			Other assets	810		755		830
Total assets	$	12,343.9		$	11,582.2		$	11,300.5		Total assets	$	17,128	$	17,575	$	16,800
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	$	402	$	149	$	123

Short-term borrowings	586.1			366.9			234.4			Short-term borrowings	991		368		579
Accounts payable	680.8			439.6			573.6			Accounts payable	1,014		891		973

Derivative instruments	32.7			25.0			16.2			Derivative instruments	133		144		53
Held for sale liabilities (Note 5)										Held for sale liabilities (Note 5)	—		19		—
Other current liabilities	692.3			681.1			702.2			Other current liabilities	840		873		853
Total current liabilities	2,216.0			1,690.1			1,574.9			Total current liabilities	3,380		2,444		2,581
Long-term debt	4,056.4			3,994.6			3,994.2			Long-term debt	6,323		6,483		6,416

Deferred income taxes	890.7			1,357.0			1,204.7			Deferred income taxes	958		1,305		1,060
Deferred investment tax credits	2.9			3.0			3.2

Derivative instruments	22.2			21.8			16.6			Derivative instruments	36		50		33
Other noncurrent liabilities	1,073.6			774.8			773.8			Other noncurrent liabilities	1,243		1,219		1,351
Total liabilities	8,261.8			7,841.3			7,567.4			Total liabilities	11,940		11,501		11,441
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		214
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 210,621,970, 210,560,494 and 210,045,726 shares, respectively)										UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 210,621,970, 210,560,494 and 210,045,726 shares, respectively)	1,482		1,483		1,402
Retained earnings	2,429.3			2,106.7			2,035.4			Retained earnings	3,808		4,841		3,908
Accumulated other comprehensive loss	(71.5		)	(93.4		)	(216.8		)	Accumulated other comprehensive loss	(231)		(380)		(156)
Treasury stock, at cost	(45.4		)	(38.6		)	(34.3		)	Treasury stock, at cost	(46)		(40)		(19)
Total UGI Corporation stockholders’ equity	3,501.7			3,163.3			2,987.7			Total UGI Corporation stockholders’ equity	5,180		6,066		5,349
Noncontrolling interests, principally in AmeriGas Partners	580.4			577.6			745.4
Noncontrolling interests										Noncontrolling interests	8		8		10
Total equity	4,082.1			3,740.9			3,733.1			Total equity	5,188		6,074		5,359
Total liabilities and equity	$	12,343.9		$	11,582.2		$	11,300.5		Total liabilities and equity	$	17,128	$	17,575	$	16,800



	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



	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, 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	)



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