UGI 10-Q Quarterly Report March 31, 2018

UGI CORP /PA/

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10-Q 1 ugicorpq2331201810-q.htm 10-Q Document

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended March 31, 2018



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

For the transition period from ________ to ________

Commission file number 1-11071

UGI CORPORATION

(Exact name of registrant as specified in its charter)



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)

(610) 337-1000

(Registrant’s telephone number, including area code)

______________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	ý	Accelerated filer	¨	Non-accelerated filer	¨
Smaller reporting company	¨	Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

At April 30, 2018 , there were 173,118,013 shares of UGI Corporation Common Stock, without par value, outstanding.

Table of Contents

UGI CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS



	Page

Part I Financial Information

Item 1. Financial Statements (unaudited)

Condensed Consolidated Balance Sheets as of March 31, 2018, September 30, 2017 and March 31, 2017	1

Condensed Consolidated Statements of Income for the three and six months ended March 31, 2018 and 2017	2

Condensed Consolidated Statements of Comprehensive Income for the three and six months ended March 31, 2018 and 2017	3

Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 2018 and 2017	4

Condensed Consolidated Statements of Changes in Equity for the six months ended March 31, 2018 and 2017	5

Notes to Condensed Consolidated Financial Statements	6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

Item 3. Quantitative and Qualitative Disclosures About Market Risk	57

Item 4. Controls and Procedures	59

Part II Other Information

Item 1A. Risk Factors	60

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	60

Item 6. Exhibits	61

Signatures	63

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Table of Contents

UGI CORPORATION AND SUBSIDIARIES

PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Millions of dollars)



	March 31, 2018			September 30, 2017			March 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	474.8		$	558.4		$	637.8
Restricted cash	10.6			10.3			0.3
Accounts receivable (less allowances for doubtful accounts of $44.6, $26.9 and $34.7, respectively)	1,272.7			626.8			920.4
Accrued utility revenues	62.3			13.3			36.7
Inventories	228.3			278.6			203.0
Utility regulatory assets	2.9			8.3			2.3
Derivative instruments	36.6			63.1			49.2
Prepaid expenses and other current assets	133.9			138.7			90.6
Total current assets	2,222.1			1,697.5			1,940.3
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $3,141.2, $3,312.9 and $3,221.9, respectively)	5,716.6			5,537.0			5,298.6
Goodwill	3,218.1			3,107.2			2,948.4
Intangible assets, net	627.1			611.7			551.0
Utility regulatory assets	358.7			360.6			392.4
Derivative instruments	12.0			9.2			11.4
Other assets	290.7			259.0			243.4
Total assets	$	12,445.3		$	11,582.2		$	11,385.5
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	86.0		$	177.5		$	170.5
Short-term borrowings	302.8			366.9			50.1
Accounts payable	600.3			439.6			467.6
Derivative instruments	28.9			25.0			5.0
Other current liabilities	799.5			681.1			674.6
Total current liabilities	1,817.5			1,690.1			1,367.8
Long-term debt	4,192.8			3,994.6			4,025.5
Deferred income taxes	905.9			1,357.0			1,267.6
Deferred investment tax credits	2.8			3.0			3.1
Derivative instruments	25.0			21.8			5.9
Other noncurrent liabilities	1,080.3			774.8			778.2
Total liabilities	8,024.3			7,841.3			7,448.1
Commitments and contingencies (Note 10)
Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 174,015,641, 173,987,691 and 173,949,791 shares, respectively)	1,193.4			1,188.6			1,190.4
Retained earnings	2,656.6			2,106.7			2,214.2
Accumulated other comprehensive loss	(34.1		)	(93.4		)	(204.5		)
Treasury stock, at cost	(41.6		)	(38.6		)	(34.9		)
Total UGI Corporation stockholders’ equity	3,774.3			3,163.3			3,165.2
Noncontrolling interests, principally in AmeriGas Partners	646.7			577.6			772.2
Total equity	4,421.0			3,740.9			3,937.4
Total liabilities and equity	$	12,445.3		$	11,582.2		$	11,385.5

See accompanying notes to condensed consolidated financial statements.

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Table of Contents

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Millions of dollars, except per share amounts)



	Three Months Ended March 31,						Six Months Ended March 31,
	2018			2017			2018			2017
Revenues	$	2,812.0		$	2,173.8		$	4,937.2		$	3,853.3
Costs and expenses:
Cost of sales (excluding depreciation shown below)	1,560.2			1,071.2			2,697.6			1,718.6
Operating and administrative expenses	556.2			491.1			1,046.3			959.6
Depreciation	98.5			84.8			194.0			168.5
Amortization	13.7			14.5			28.5			28.9
Other operating income, net	(6.1		)	(1.0		)	(10.5		)	(1.7		)
	2,222.5			1,660.6			3,955.9			2,873.9
Operating income	589.5			513.2			981.3			979.4
Income from equity investees	0.7			2.3			1.7			2.1
Loss on extinguishments of debt	—			(22.1		)	—			(55.3		)
(Losses) gains on foreign currency contracts, net	(11.0		)	(1.2		)	(15.8		)	0.1
Interest expense	(58.1		)	(55.8		)	(116.3		)	(111.2		)
Income before income taxes	521.1			436.4			850.9			815.1
Income tax expense	(113.4		)	(124.6		)	(9.0		)	(212.4		)
Net income including noncontrolling interests	407.7			311.8			841.9			602.7
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners	(131.7		)	(91.9		)	(200.0		)	(152.1		)
Net income attributable to UGI Corporation	$	276.0		$	219.9		$	641.9		$	450.6
Earnings per common share attributable to UGI Corporation stockholders
Basic	$	1.59		$	1.27		$	3.70		$	2.60
Diluted	$	1.57		$	1.24		$	3.63		$	2.55
Weighted average common shares outstanding (thousands)
Basic	173,570			173,624			173,617			173,567
Diluted	176,350			177,136			176,646			176,976
Dividends declared per common share	$	0.2500		$	0.2375		$	0.5000		$	0.4750

See accompanying notes to condensed consolidated financial statements.

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Table of Contents

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Millions of dollars)



	Three Months Ended March 31,						Six Months Ended March 31,
	2018			2017			2018			2017
Net income including noncontrolling interests	$	407.7		$	311.8		$	841.9		$	602.7
Other comprehensive income (loss):
Net (losses) gains on derivative instruments (net of tax of $0.7, $0.3, $0.9 and $(5.7), respectively)	(1.6		)	(0.5		)	(2.0		)	11.8
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(1.5), $2.5, $(1.4) and $4.6, respectively)	2.8			(5.4		)	2.4			(9.9		)
Foreign currency adjustments	35.9			17.8			58.2			(53.1		)
Benefit plans (net of tax of $(0.1), $(0.3), $(0.3) and $(0.9), respectively)	0.3			0.4			0.7			1.4
Other comprehensive income (loss)	37.4			12.3			59.3			(49.8		)
Comprehensive income including noncontrolling interests	445.1			324.1			901.2			552.9
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	(131.7		)	(91.9		)	(200.0		)	(152.1		)
Comprehensive income attributable to UGI Corporation	$	313.4		$	232.2		$	701.2		$	400.8

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Millions of dollars)



	Six Months Ended March 31,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income including noncontrolling interests	$	841.9		$	602.7
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization	222.5			197.4
Deferred income tax (benefit) expense	(191.5		)	49.4
Provision for uncollectible accounts	24.8			15.3
Change in unrealized losses (gains) on derivative instruments	41.5			(81.6		)
Loss on extinguishments of debt	—			55.3
Other, net	10.0			24.0
Net change in:
Accounts receivable and accrued utility revenues	(676.0		)	(424.3		)
Inventories	57.0			3.9
Utility deferred fuel and power costs, net of changes in unsettled derivatives	31.5			(7.6		)
Accounts payable	136.2			129.4
Other current assets	(18.3		)	(1.3		)
Other current liabilities	99.8			22.4
Net cash provided by operating activities	579.4			585.0
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(266.1		)	(341.8		)
Acquisitions of businesses and assets, net of cash acquired	(174.3		)	(7.3		)
(Increase) decrease in restricted cash	(0.3		)	15.3
Other, net	9.0			(4.3		)
Net cash used by investing activities	(431.7		)	(338.1		)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(86.6		)	(82.3		)
Distributions on AmeriGas Partners publicly held Common Units	(131.5		)	(130.1		)
Issuances of debt, net of issuance costs	124.3			1,307.1
Repayments of debt, including redemption premiums	(64.3		)	(928.6		)
Decrease in short-term borrowings	(38.7		)	(216.1		)
Receivables Facility net repayments	(29.0		)	(25.5		)
Issuances of UGI Common Stock	3.1			5.9
Repurchases of UGI Common Stock	(14.1		)	(25.5		)
Other	(3.4		)	(0.8		)
Net cash used by financing activities	(240.2		)	(95.9		)
EFFECT OF EXCHANGE RATE CHANGES ON CASH	8.9			(16.0		)
Cash and cash equivalents (decrease) increase	$	(83.6	)	$	135.0
CASH AND CASH EQUIVALENTS
End of period	$	474.8		$	637.8
Beginning of period	558.4			502.8
(Decrease) increase	$	(83.6	)	$	135.0

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(Millions of dollars)



	Six Months Ended March 31,
	2018			2017
Common stock, without par value
Balance, beginning of period	$	1,188.6		$	1,201.6
Common Stock issued in connection with employee and director plans (including losses on treasury stock transactions), net of tax withheld	(3.8		)	(20.7		)
Equity-based compensation expense	8.6			8.1
Gain on sale of treasury stock	—			1.4
Balance, end of period	$	1,193.4		$	1,190.4
Retained earnings
Balance, beginning of period	$	2,106.7		$	1,840.9
Cumulative effect of change in accounting for employee share-based payments	—			5.0
Losses on treasury stock transactions in connection with employee and director plans	(5.4		)	—
Net income attributable to UGI Corporation	641.9			450.6
Cash dividends on Common Stock	(86.6		)	(82.3		)
Balance, end of period	$	2,656.6		$	2,214.2
Accumulated other comprehensive income (loss)
Balance, beginning of period	$	(93.4	)	$	(154.7	)
Net (losses) gains on derivative instruments	(2.0		)	11.8
Reclassification of net losses (gains) on derivative instruments	2.4			(9.9		)
Benefit plans	0.7			1.4
Foreign currency adjustments	58.2			(53.1		)
Balance, end of period	$	(34.1	)	$	(204.5	)
Treasury stock
Balance, beginning of period	$	(38.6	)	$	(36.9	)
Common stock issued in connection with employee and director plans, net of tax withheld	13.0			33.7
Repurchases of Common Stock	(14.1		)	(25.5		)
Reacquired common stock — employee and director plans	(1.9		)	(6.4		)
Sale of treasury stock	—			0.2
Balance, end of period	$	(41.6	)	$	(34.9	)
Total UGI Corporation stockholders’ equity	$	3,774.3		$	3,165.2
Noncontrolling interests
Balance, beginning of period	$	577.6		$	750.9
Net income attributable to noncontrolling interests, principally in AmeriGas Partners	200.0			152.1
Dividends and distributions	(131.8		)	(130.1		)
Other	0.9			(0.7		)
Balance, end of period	$	646.7		$	772.2
Total equity	$	4,421.0		$	3,937.4

See accompanying notes to condensed consolidated financial statements.

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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 1 — Nature of Operations

UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; and (3) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production, electricity generation and energy services business. In Europe, we market and distribute propane and other liquefied petroleum gases (“LPG”) and market energy products and services. We refer to UGI and its consolidated subsidiaries collectively as “the Company,” “we” or “us.”

We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the “Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At March 31, 2018 , the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.0% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances as further described in Note 14 of the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2017 (the “Company’s 2017 Annual Report”). Incentive distributions received by the General Partner during the six months ended March 31, 2018 and 2017 were $22.7 and $20.9 , respectively.

Our wholly owned subsidiary, UGI Enterprises, LLC, (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business throughout Europe, (2) a natural gas marketing business in France, Belgium and the United Kingdom, and (3) a natural gas and electricity marketing business in the Netherlands. These businesses are conducted principally through our subsidiaries, UGI France SAS, Flaga GmbH (“Flaga”), AvantiGas Limited, DVEP Investeringen B.V. (“DVEP”), and UniverGas Italia S.r.l. (“UniverGas”). We refer to our foreign operations collectively as “UGI International.”

UGI Energy Services, LLC (“Energy Services, LLC”), a wholly owned subsidiary of Enterprises, conducts directly and through subsidiaries energy marketing, midstream transmission, liquefied natural gas (“LNG”), storage, natural gas gathering, natural gas production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S. Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. A first-tier subsidiary of Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in portions of eastern and central Pennsylvania (“HVAC”). Energy Services, LLC and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). We refer to the businesses of Energy Services, LLC and its subsidiaries and HVAC as “Midstream & Marketing.”

UGI Utilities, Inc. (“UGI Utilities”) conducts a natural gas distribution utility business (“Gas Utility”) directly and through its wholly owned subsidiaries, UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities in eastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission (“MD PSC”). Electric Utility is subject to regulation by the PUC. UGI Utilities is used herein as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries.

Note 2 — Summary of Significant Accounting Policies

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments that we consider

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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)

necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2017 , condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”).

These financial statements should be read in conjunction with the financial statements and related notes included in the Company’s 2017 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

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

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



	Three Months Ended March 31,		Six Months Ended March 31,
	2018	2017	2018	2017
Denominator (thousands of shares):
Weighted-average common shares outstanding — basic	173,570	173,624	173,617	173,567
Incremental shares issuable for stock options and awards (a)	2,780	3,512	3,029	3,409
Weighted-average common shares outstanding — diluted	176,350	177,136	176,646	176,976


(a)	For the three and six months ended March 31, 2018 , there were 2,486 shares associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive. For the three and six months ended March 31, 2017 , there were no such antidilutive shares.

Derivative Instruments. Derivative instruments are reported on the condensed consolidated balance sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.

Certain of our derivative instruments are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. From time to time, we also enter into net investment hedges. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated.

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. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “ (Losses) gains on foreign currency contracts, net ” on the Condensed Consolidated Statements of Income.

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

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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)

For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 13 .

Impairment of Cost Basis Investments . We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary. In March 2017, we recorded a pre-tax loss of $7.0 associated with an other-than-temporary impairment of our investment in a private equity partnership that invests in renewable energy companies. This loss is reflected in “ Other operating income, net ” on the Condensed Consolidated Statements of Income for the three and six months ended March 31, 2017.

Income Taxes. UGI’s consolidated effective income tax rate, defined as total income taxes as a percentage of income (loss) before income taxes, includes amounts associated with noncontrolling interests in the Partnership, which principally comprises AmeriGas Partners and AmeriGas OLP. AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. As a result, UGI’s consolidated effective income tax rate is affected by the amount of income (loss) before income taxes attributable to noncontrolling interests in the Partnership not subject to income taxes.

See Note 5 for discussions regarding the December 22, 2017, enactment of the Tax Cuts and Jobs Act (the “TCJA”) in the U.S. and changes in French tax laws.

Use of Estimates. The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

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

Note 3 — Accounting Changes

Accounting Standards Not Yet Adopted

Other Comprehensive Income. In February 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded tax effects in AOCI resulting from the TCJA may be reclassified to retained earnings, at the election of the entity, in the period of adoption. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.

Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required only prospectively. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. For entities subject to rate regulation, however, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) with a retrospective adoption for income statement presentation and a prospective adoption for capitalization. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.

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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)

Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in the ASU are required to be adopted on a retrospective basis. The ASU is effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. We currently expect to adopt this ASU effective October 1, 2018. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.

Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” (“ASU 2014-09”) The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption.

The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue by UGI Utilities.

The Company anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018.

Note 4 — Inventories

Inventories comprise the following:



	March 31, 2018		September 30, 2017		March 31, 2017
Non-utility LPG and natural gas	$	163.0	$	188.4	$	143.1
Gas Utility natural gas	3.5		39.5		2.4
Materials, supplies and other	61.8		50.7		57.5
Total inventories	$	228.3	$	278.6	$	203.0

At March 31, 2018 , 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.

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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)

As of March 31, 2018 , UGI Utilities had SCAAs with Energy Services, LLC, the effects of which are eliminated in consolidation, and with a non-affiliate. There were no gas storage inventories released under SCAAs with the non-affiliate at March 31, 2018 and 2017. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at September 30, 2017 , comprising 2.3 billion cubic feet (“bcf”) of natural gas was $6.7 .

Note 5 — Income Tax Reform

U.S. Tax Reform

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 un-repatriated foreign earnings, and allows for immediate capital expensing of certain qualified property. It also applies restrictions on the deductibility of interest expense, eliminates bonus depreciation for regulated utilities and applies a broader application of compensation limitations.

In accordance with GAAP as determined by ASC 740, “Income Taxes,” we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three and six months ended March 31, 2018 , contain provisional estimates of the impact of the TCJA. These amounts are considered provisional because they use estimates for which tax returns have not yet been filed and because estimated amounts may be impacted by future regulatory and accounting guidance if and when issued. In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 118, we will adjust these provisional amounts as further information becomes available and as we refine our calculations. As permitted by the guidance issued by the SEC, these adjustments may occur during a reasonable “measurement period” not to exceed twelve months from the date of enactment.

As a result, during the three and six months ended March 31, 2018 , we reduced our net deferred income tax liabilities by $5.0 and $388.8 , respectively, due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of the enactment in December 2017, and as a result of adjusting our original provisional amounts during the quarter ended March 31, 2018. 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 each of the three month periods ended December 31, 2017 and March 31, 2018, and the six months ended March 31, 2018, which reduced (increased) income tax expense consisted primarily of the following items:



	Provisional amounts - Three months ended December 31, 2017			Changes to provisional amounts - Three months ended March 31, 2018		Provisional amounts - Six months ended March 31, 2018
Reduction in net deferred tax liabilities in the U.S. from the reduction of the U.S. tax rate	$	180.3		$	—	$	180.3
Establishment of valuation allowances related to deferred tax assets impacted by TCJA	(12.6		)	5.0		(7.6		)
Toll-tax on un-repatriated earnings	(1.7		)	0.3		(1.4		)
Total discrete deferred income tax adjustments	$	166.0		$	5.3	$	171.3
Impact on earnings per share:
Basic earnings per share	$	0.96		$	0.03	$	0.99
Diluted earnings per share	$	0.94		$	0.03	$	0.97

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,

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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)

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. This regulatory liability is being amortized to income tax expense over the remaining lives of the assets that gave rise to the excess deferred income taxes. For further information on this regulatory liability, see Note 7 .

For the three and six months ended March 31, 2018 , we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rate. We are subject to a blended federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contains the effective date of the rate change from 35% to 21% . As a result, the U.S. federal income tax rate included in our estimated annual effective tax rate is based on this 24.5% blended rate for Fiscal 2018. For the three and six months ended March 31, 2018 , the effects of the tax law changes on current-period results (excluding the one-time impacts described above) decreased income tax expense, and increased net income attributable to UGI, by approximately $34.0 and $54.5 , respectively.

As a result of the TCJA tax law changes, in January 2018, the PUC opened a proceeding to consider whether existing rates charged by Pennsylvania utilities are no longer “just and reasonable,” as required by Pennsylvania law. On February 12, 2018, the PUC issued a Secretarial Letter requesting detailed information from large public utilities, including UGI Utilities, and inviting interested parties to submit comments on the impacts of the TCJA. On March 15, 2018, the PUC entered a temporary rates Order that converted commission-approved rates of most large Pennsylvania public utilities, including Gas Utility, into “temporary rates” for a period of six months, with a possible extension for an additional six months. It ordered each affected public utility to file a tariff supplement designating its existing rates and riders as temporary, effective March 15, 2018. In its comments on March 9, 2018, UGI Utilities expressed the view that, as a matter of law, reducing base rates by the tax impact of the TCJA would be unlawful if the result did not permit the utility to earn a reasonable rate of return and proposed to give approximately half of the benefits from the TCJA to customers through a reduction in rates and increased funding for low income and gas operations programs.

The PUC is in the process of reviewing the data and comments submitted in response to the Secretarial Letter. Due to the complexity of the tax law changes and the numerous public utilities involved, the PUC has stated that it is unable to determine when it will complete its review and resolve the issues presented.

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 benefit of $17.3 . During the three months ended March 31, 2018, this estimated deferred tax benefit was adjusted downward by $3.7 to $13.6 (equal to $0.08 per basic and diluted share) for the six months ended March 31, 2018. The estimated annual effective income tax rate used in determining income taxes for the six months ended March 31, 2018, reflects the impact of the single year Fiscal 2018 income tax rate increase 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 and six months ended March 31, 2018, by approximately $1.1 and $5.0 , respectively.

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

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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 6 — Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following:



	March 31, 2018			September 30, 2017			March 31, 2017
Goodwill (not subject to amortization)	$	3,218.1		$	3,107.2		$	2,948.4
Intangible assets:
Customer relationships, noncompete agreements and other	$	867.0		$	817.8		$	764.3
Accumulated amortization	(376.2		)	(340.2		)	(342.4		)
Intangible assets, net (definite-lived)	490.8			477.6			421.9
Trademarks and tradenames (indefinite-lived)	136.3			134.1			129.1
Total intangible assets, net	$	627.1		$	611.7		$	551.0

The changes in goodwill and intangible assets are primarily due to acquisitions and the effects of currency translation. Amortization expense of intangible assets was $13.7 and $12.4 for the three months ended March 31, 2018 and 2017 , respectively. Amortization expense of intangible assets was $28.5 and $24.9 for the six months ended March 31, 2018 and 2017 , respectively. Amortization expense included in “Cost of sales” on the Condensed Consolidated Statements of Income was not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2018 and for the next four fiscal years is as follows: remainder of Fiscal 2018 — $28.3 ; Fiscal 2019 — $54.7 ; Fiscal 2020 — $53.3 ; Fiscal 2021 — $51.4 ; Fiscal 2022 — $49.7 .

During the quarter ended March 31, 2018, the Partnership performed a formal business review of the current and planned use of its indefinite-lived tradenames and trademarks, primarily associated with its January 2012 acquisition of Heritage Propane. This review included obtaining an understanding of the costs and benefits of continuing to utilize these tradenames and trademarks in the operations of the Partnership’s business. At March 31, 2018, these indefinite-lived tradenames and trademarks had a carrying amount of $82.9 .

In April 2018, a plan to discontinue the use of these tradenames and trademarks was presented to the Partnership’s senior management. After considering the merits of the plan, the Partnership’s senior management approved, and the General Partner’s Board of Directors endorsed, a plan to discontinue the use of these tradenames and trademarks which is expected to occur over a period of approximately four years. As a result, during the three months ending June 30, 2018, the Partnership will adjust the carrying amounts of these tradenames and trademarks to their fair values and will reclassify the remaining fair value of these tradenames and trademarks from indefinite-lived intangible assets to definite-lived intangible assets having a remaining estimated period of benefit of approximately four years. The Partnership estimates that it will record a pre-tax non-cash impairment charge of approximately $70 which will decrease net income attributable to UGI by approximately $13 .

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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 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 8 in the Company’s 2017 Annual Report. Other than removal costs, UGI Utilities currently does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with UGI Utilities are included in our accompanying condensed consolidated balance sheets:



	March 31, 2018		September 30, 2017		March 31, 2017
Regulatory assets:
Income taxes recoverable	$	128.3	$	121.4	$	120.3
Underfunded pension and postretirement plans	135.3		141.3		175.6
Environmental costs	59.8		61.6		62.2
Deferred fuel and power costs	0.7		7.7		1.3
Removal costs, net	30.5		31.0		28.8
Other	7.0		5.9		6.5
Total regulatory assets	$	361.6	$	368.9	$	394.7
Regulatory liabilities (a):
Postretirement benefits	$	17.1	$	17.5	$	17.0
Deferred fuel and power refunds	35.3		10.6		13.8
State tax benefits — distribution system repairs	19.9		18.4		16.1
Excess federal deferred income taxes (b)	301.2		—		—
Other	7.2		2.7		3.6
Total regulatory liabilities	$	380.7	$	49.2	$	50.5


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


(b)	Balance at March 31, 2018 , 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 and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains on such contracts at March 31, 2018 , September 30, 2017 and March 31, 2017 were $0.3 , $0.1 and $2.0 , 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 March 31, 2018 , September 30, 2017 and March 31, 2017 , were not material.

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

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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 and will be amortized and credited to tax expense.

Other Regulatory Matters

Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PUC to increase its annual base distribution revenues by $9.2 . 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. The PUC entered an Order dated March 1, 2018, suspending the effective date for the rate increase to allow for investigation and public hearings. Unless a settlement is reached sooner, this review process is expected to last up to nine months from the date of filing; however, 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.

Utilities Merger Request. On March 8, 2018 and March 13, 2018, the Company filed merger authorization requests with the PUC and MD PSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. There are no expected changes to annual base distribution rates for the combined utilities or to existing regulatory assets and liabilities as a result of the proposed merger. The Company cannot predict the timing or the ultimate outcome of the PUC or MD PSC review of the merger request. CPG, PNG, and UGI Utilities also filed, in May 2018, related applications to transfer certain FERC authorizations from PNG and CPG to UGI Utilities to ensure continuity of certain interstate gas transportation services now conducted by CPG and PNG upon the effective date of the proposed merger.

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 and six months ended March 31, 2018 and 2017 , which are included in “Interest expense” on the Condensed Consolidated Statements of Income, were not material.

Information regarding the trade receivables transferred to ESFC and the amounts sold to the bank for the six months ended March 31, 2018 and 2017 , as well as the balance of ESFC trade receivables at March 31, 2018 , September 30, 2017 and March 31, 2017 , is as follows:



	Six Months Ended March 31,
	2018		2017
Trade receivables transferred to ESFC during the period	$	806.9	$	633.7
ESFC trade receivables sold to the bank during the period	$	128.0	$	151.0



	March 31, 2018		September 30, 2017		March 31, 2017
ESFC trade receivables — end of period (a)	$	99.6	$	44.8	$	85.3


(a)	At March 31, 2018 and September 30, 2017 , the amounts of ESFC trade receivables sold to the bank were $10.0 and $39.0 , respectively. At March 31, 2017 , there were no ESFC trade receivables sold to the bank. Amounts sold to the bank are reflected as “ Short-term borrowings ” on the Condensed Consolidated Balance Sheets.

Note 9 — Debt

AmeriGas Propane. 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 (including a $150 sublimit for letters of credit) and expires in December 2022. The AmeriGas Credit Agreement permits AmeriGas to borrow at prevailing interest rates, including

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

the 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% . 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).

During the three and six months ended March 31, 2017 , the Partnership recognized pre-tax losses of $22.1 and $55.3 , respectively, in connection with the early repayments of a portion of AmeriGas Partners’ 7.00% Senior Notes. These losses are reflected in “ Loss on extinguishments of debt ” on the Condensed Consolidated Statements of Income for the three and six months ended March 31, 2017 .

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

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

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. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement borrowings and for general corporate purposes. The outstanding principal amount of the Utilities Term Loan is payable in equal quarterly installments of $1.6 , which commenced March 2018, with the balance of the principal being due and payable in full on October 30, 2022. 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 that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.

Note 10 — 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.

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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”) 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 and Electric Utility. UGI Utilities also has 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 a consent order and agreement (“COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG and PNG are each 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. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2.5 , $1.8 , and $1.1 , for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively. At March 31, 2018 , September 30, 2017 and March 31, 2017 , our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $51.9 , $54.3 and $55.7 , 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 ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.

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 March 31, 2018 , September 30, 2017 and March 31, 2017 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was 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)

AmeriGas Propane

AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that the DEC 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 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 to the DEC in early 2009, AmeriGas OLP disputed DEC’s contention it was a potentially responsible party (“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 communicated to AmeriGas OLP that the DEC had previously issued three Records of Decision (“RODs”) related to the site and requested additional information regarding AmeriGas OLP’s purported ownership. The selected remedies identified in the RODs total approximately $27.7 . Based on public reports, the DEC has commenced implementation of the remediation plan. AmeriGas OLP responded to the DEC’s March 2017 request for ownership information, renewing its challenge to designation as a PRP and identifying potential defenses. In October 2017, the DEC 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 affirmed by a panel of the Eighth Circuit. In September 2017, we filed a Petition for a Writ of Certiorari to the U.S. Supreme Court appealing the decision of the Eighth Circuit. The petition was denied in January 2018 and, as a result, 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 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. 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. The parties submitted briefs in October 2017 to the Eighth Circuit and held oral argument in February 2018. The parties are now awaiting the court’s ruling.

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 11 — Defined Benefit Pension and Other Postretirement Plans

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

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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 periodic pension expense and other postretirement benefit costs include the following components:



	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31,	2018			2017			2018			2017
Service cost	$	2.8		$	3.0		$	0.2		$	0.3
Interest cost	6.5			6.1			0.2			0.2
Expected return on assets	(8.6		)	(8.3		)	(0.2		)	(0.1		)
Amortization of:
Prior service cost (benefit)	0.1			—			—			(0.2		)
Actuarial loss	3.3			4.2			—			—
Net benefit cost	4.1			5.0			0.2			0.2
Change in associated regulatory liabilities	—			—			(0.1		)	(0.1		)
Net benefit cost after change in regulatory liabilities	$	4.1		$	5.0		$	0.1		$	0.1

	Pension Benefits						Other Postretirement Benefits
Six Months Ended March 31,	2018			2017			2018			2017
Service cost	$	5.6		$	6.0		$	0.4		$	0.5
Interest cost	13.0			12.3			0.4			0.4
Expected return on assets	(17.2		)	(16.6		)	(0.4		)	(0.3		)
Amortization of:
Prior service cost (benefit)	0.2			0.1			(0.1		)	(0.3		)
Actuarial loss	6.6			8.3			—			0.1
Net benefit cost	8.2			10.1			0.3			0.4
Change in associated regulatory liabilities	—			—			(0.2		)	(0.2		)
Net benefit cost after change in regulatory liabilities	$	8.2		$	10.1		$	0.1		$	0.2

The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. During the six months ended March 31, 2018 and 2017 , the Company made cash contributions to the U.S. Pension Plan of $6.7 and $5.7 , respectively. The Company expects to make additional discretionary cash contributions of approximately $6.7 to the U.S. Pension Plan during the remainder of Fiscal 2018 .

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 cash deposits or expense recorded 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 six months ended March 31, 2018 and 2017 .

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net periodic costs associated with these plans for the three and six months ended March 31, 2018 and 2017 , 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 12 — 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 of March 31, 2018 , September 30, 2017 and March 31, 2017 :



	Asset (Liability)
	Level 1			Level 2			Level 3		Total
March 31, 2018:
Derivative instruments:
Assets:
Commodity contracts	$	39.6		$	27.0		$	—	$	66.6
Foreign currency contracts	$	—		$	13.9		$	—	$	13.9
Liabilities:
Commodity contracts	$	(24.3	)	$	(13.5	)	$	—	$	(37.8	)
Foreign currency contracts	$	—		$	(43.5	)	$	—	$	(43.5	)
Interest rate contracts	$	—		$	(1.9	)	$	—	$	(1.9	)
Cross-currency contracts	$	—		$	(2.2	)	$	—	$	(2.2	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	37.9		$	—		$	—	$	37.9
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
March 31, 2017:
Derivative instruments:
Assets:
Commodity contracts	$	56.0		$	18.0		$	—	$	74.0
Foreign currency contracts	$	—		$	15.6		$	—	$	15.6
Cross-currency contracts	$	—		$	3.0		$	—	$	3.0
Liabilities:
Commodity contracts	$	(28.0	)	$	(11.0	)	$	—	$	(39.0	)
Foreign currency contracts	$	—		$	(1.5	)	$	—	$	(1.5	)
Interest rate contracts	$	—		$	(2.2	)	$	—	$	(2.2	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	35.2		$	—		$	—	$	35.2


(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 of our derivative instruments are designated as Level 2. The fair values of certain non-exchange-traded commodity derivatives

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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, 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 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 and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at March 31, 2018 , September 30, 2017 and March 31, 2017 were as follows:



	March 31, 2018		September 30, 2017		March 31, 2017
Carrying amount	$	4,316.4	$	4,211.9	$	4,238.9
Estimated fair value	$	4,287.3	$	4,346.8	$	4,255.0

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. See Note 2 for additional information on this cost method investment.

Note 13 — Derivative Instruments and Hedging Activities

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

Commodity Price Risk

Regulated Utility Operations

Natural Gas

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. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. Gains and losses on Gas Utility’s natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the condensed consolidated balance sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 7 ).

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Electricity

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At March 31, 2018 , September 30, 2017 and March 31, 2017 , 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 Partnership’s fixed-price programs, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, AmeriGas Partners, certain other domestic businesses 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, from time to time, uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of propane.

Natural Gas

In order to manage market price risk relating to fixed-price sales contracts for natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and forward contracts and Intercontinental Exchange (“ICE”) natural gas basis swap contracts. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas. UGI International also uses natural gas futures and forward contracts to economically hedge market price risk associated with fixed-price sales contracts with its customers.

Electricity

In order to manage market price risk relating to fixed-price sales contracts for electricity, Midstream & Marketing enters into electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. 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 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 into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rates and LIBOR rates of interest on their variable-rate term loans.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for interest rate swaps and IRPAs as cash flow hedges.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

At March 31, 2018 , 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 March 31, 2018 , 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 $3.7 .

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 forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our UGI International euro-denominated net investments. We account for these foreign currency exchange contracts as net investment hedges. At March 31, 2018 and 2017 , there were no unsettled net investment hedges outstanding.

Cross-currency Swaps

From time to time, Flaga enters into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of U.S. dollar-denominated debt. These cross-currency hedges include initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also include interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designate these cross-currency swaps as cash flow hedges.

At March 31, 2018 , 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.

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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)

Quantitative Disclosures Related to Derivative Instruments

The following table summarizes, by derivative type, the gross notional amounts related to open derivative contracts as of March 31, 2018 , September 30, 2017 and March 31, 2017 , and the final settlement date of the Company's open derivative transactions as of March 31, 2018 , excluding those derivatives that qualified for the NPNS exception:



			Notional Amounts (in millions)
Type	Units	Settlements Extending Through	March 31, 2018		September 30, 2017		March 31, 2017
Commodity Price Risk:
Regulated Utility Operations
Gas Utility NYMEX natural gas futures and option contracts	Dekatherms	March 2019	12.7		14.8		9.0
FTRs contracts	Kilowatt hours	May 2018	25.5		101.2		14.6
Non-utility Operations
LPG swaps & options	Gallons	March 2020	229.2		325.5		241.6
Natural gas futures, forward and pipeline contracts (a)	Dekatherms	March 2022	128.9		75.9		56.5
Natural gas basis swap contracts	Dekatherms	March 2022	74.1		104.2		107.2
NYMEX natural gas storage	Dekatherms	March 2019	0.9		1.9		1.4
NYMEX propane storage	Gallons	N/A	—		0.3		—
Electricity long forward and futures contracts (a)	Kilowatt hours	January 2022	4,184.1		4,440.3		668.7
Electricity short forward and futures contracts	Kilowatt hours	May 2021	490.9		447.0		526.1
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	September 2021	$	496.2	$	424.8	$	321.8
Cross-currency contracts	USD	April 2020	$	49.9	$	59.1	$	59.1


(a)	Amounts at March 31, 2018 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 of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2018 , September 30, 2017 and March 31, 2017 , restricted cash in brokerage accounts totaled $10.6 , $10.3 and $0.3 , respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss we would incur if these counterparties failed to perform according to the terms of their contracts, based upon the gross fair values of the derivative instruments, was not material at March 31, 2018 . Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of

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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)

additional collateral in the event of a downgrade of the Partnership’s debt rating. At March 31, 2018 , if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

Offsetting Derivative Assets and Liabilities

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

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

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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 March 31, 2018 , September 30, 2017 and March 31, 2017 :



	March 31, 2018			September 30, 2017			March 31, 2017
Derivative assets:
Derivatives designated as hedging instruments:
Foreign currency contracts	$	0.3		$	3.2		$	14.2
Cross-currency contracts	—			—			3.0
	0.3			3.2			17.2
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	0.9			1.7			2.1
Derivatives not designated as hedging instruments:
Commodity contracts	65.7			102.4			71.9
Foreign currency contracts	13.6			9.0			1.4
	79.3			111.4			73.3
Total derivative assets — gross	80.5			116.3			92.6
Gross amounts offset in the balance sheet	(31.5		)	(35.7		)	(31.8		)
Cash collateral received	(0.4		)	(8.3		)	(0.2		)
Total derivative assets — net	$	48.6		$	72.3		$	60.6
Derivative liabilities:
Derivatives designated as hedging instruments:
Foreign currency contracts	$	(4.0	)	$	(5.5	)	$	—
Cross-currency contracts	(2.2		)	(2.9		)	—
Interest rate contracts	(1.9		)	(2.3		)	(2.2		)
	(8.1		)	(10.7		)	(2.2		)
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	(0.6		)	(1.5		)	(0.2		)
Derivatives not designated as hedging instruments:
Commodity contracts	(37.2		)	(37.6		)	(38.8		)
Foreign currency contracts	(39.5		)	(32.7		)	(1.5		)
	(76.7		)	(70.3		)	(40.3		)
Total derivative liabilities — gross	(85.4		)	(82.5		)	(42.7		)
Gross amounts offset in the balance sheet	31.5			35.7			31.8
Total derivative liabilities — net	$	(53.9	)	$	(46.8	)	$	(10.9	)

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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 of Derivative Instruments

The following tables provide information on the effects of derivative instruments on the condensed consolidated statements of income and changes in AOCI for the six months ended March 31, 2018 and 2017 :



Three Months Ended March 31,:
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain (Loss) Reclassified from AOCI into Income
Cash Flow Hedges:	2018			2017			2018			2017			Location of Gain (Loss) Reclassified from AOCI into Income
Foreign currency contracts	$	(3.1	)	$	(1.7	)	$	(3.9	)	$	8.9		Cost of sales
Cross-currency contracts	0.3			0.3			0.3			—			Interest expense/other operating income, net
Interest rate contracts	0.5			0.6			(0.7		)	(1.0		)	Interest expense
Total	$	(2.3	)	$	(0.8	)	$	(4.3	)	$	7.9

	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2018			2017			Location of Gain (Loss) Recognized in Income
Commodity contracts	$	(41.8	)	$	22.0		Cost of sales
Commodity contracts	(0.2		)	0.8			Revenues
Commodity contracts	0.1			0.1			Operating and administrative expenses
Foreign currency contracts	(11.0		)	(1.2		)	(Losses) gains on foreign currency contracts, net
Total	$	(52.9	)	$	21.7

Six Months Ended March 31,:
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain (Loss) Reclassified from AOCI into Income
Cash Flow Hedges:	2018			2017			2018			2017			Location of Gain (Loss) Reclassified from AOCI into Income
Foreign currency contracts	$	(4.5	)	$	15.5		$	(3.1	)	$	16.8		Cost of sales
Cross-currency contracts	0.4			0.2			0.5			(0.3		)	Interest expense/other operating income, net
Interest rate contracts	1.2			1.8			(1.2		)	(2.0		)	Interest expense
Total	$	(2.9	)	$	17.5		$	(3.8	)	$	14.5

	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2018			2017			Location of Gain (Loss) Recognized in Income
Commodity contracts	$	(17.4	)	$	130.5		Cost of sales
Commodity contracts	(1.5		)	0.9			Revenues
Commodity contracts	0.2			—			Operating and administrative expenses
Foreign currency contracts	(15.8		)	0.1			(Losses) gains on foreign currency contracts, net
Total	$	(34.5	)	$	131.5

For the three and six months ended March 31, 2018 and 2017 , 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.

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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)

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, 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.

Note 14 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI during the three and six months ended March 31, 2018 and 2017 :



Three Months Ended March 31, 2018	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI — December 31, 2017	$	(18.8	)	$	(22.2	)	$	(30.5	)	$	(71.5	)
Other comprehensive (loss) income before reclassification adjustments (after-tax)	—			(1.6		)	35.9			34.3
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0.4			4.3			—			4.7
Reclassification adjustments tax benefit	(0.1		)	(1.5		)	—			(1.6		)
Reclassification adjustments (after-tax)	0.3			2.8			—			3.1
Other comprehensive income attributable to UGI	0.3			1.2			35.9			37.4
AOCI — March 31, 2018	$	(18.5	)	$	(21.0	)	$	5.4		$	(34.1	)

Three Months Ended March 31, 2017	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI — December 31, 2016	$	(28.1	)	$	(5.6	)	$	(183.1	)	$	(216.8	)
Other comprehensive (loss) income before reclassification adjustments (after-tax)	—			(0.5		)	17.8			17.3
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0.7			(7.9		)	—			(7.2		)
Reclassification adjustments tax (benefit) expense	(0.3		)	2.5			—			2.2
Reclassification adjustments (after-tax)	0.4			(5.4		)	—			(5.0		)
Other comprehensive income (loss) attributable to UGI	0.4			(5.9		)	17.8			12.3
AOCI — March 31, 2017	$	(27.7	)	$	(11.5	)	$	(165.3	)	$	(204.5	)

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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



Six Months Ended March 31, 2018	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)	—			(2.0		)	58.2			56.2
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	1.0			3.8			—			4.8
Reclassification adjustments tax benefit	(0.3		)	(1.4		)	—			(1.7		)
Reclassification adjustments (after-tax)	0.7			2.4			—			3.1
Other comprehensive income attributable to UGI	0.7			0.4			58.2			59.3
AOCI — March 31, 2018	$	(18.5	)	$	(21.0	)	$	5.4		$	(34.1	)

Six Months Ended March 31, 2017	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)	—			11.8			(53.1		)	(41.3		)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	2.3			(14.5		)	—			(12.2		)
Reclassification adjustments tax (benefit) expense	(0.9		)	4.6			—			3.7
Reclassification adjustments (after-tax)	1.4			(9.9		)	—			(8.5		)
Other comprehensive income (loss) attributable to UGI	1.4			1.9			(53.1		)	(49.8		)
AOCI — March 31, 2017	$	(27.7	)	$	(11.5	)	$	(165.3	)	$	(204.5	)

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

Note 15 — 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) 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 interest income. In addition, Corporate & Other includes net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) because such items are excluded from profit measures evaluated by our chief operating decision maker (“CODM”) in assessing our reportable segments’ performance or allocating resources. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company, and UGI corporate headquarters’ assets.

The accounting policies of our reportable segments are the same as those described in Note 2, “Summary of Significant Accounting Policies,” in the Company’s 2017 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization as adjusted for the effects of gains and losses on commodity derivative instruments not associated with current-period transactions and other gains and losses that competitors do not necessarily have (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies. Our CODM evaluates the performance 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.

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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



Three Months Ended March 31, 2018	Total			Eliminations				AmeriGas Propane			UGI International			Midstream & Marketing				UGI Utilities			Corporate & Other (b)
Revenues	$	2,812.0		$	—			$	1,040.3		$	909.6		$	436.2			$	424.6		$	1.3
Intersegment revenues	$	—		$	(188.9	)	(c)	$	—		$	—		$	129.0			$	58.7		$	1.2
Cost of sales	$	1,560.2		$	(187.9	)	(c)	$	483.7		$	541.1		$	418.6			$	257.3		$	47.4
Segment profit:
Operating income (loss)	$	589.5		$	0.3			$	266.6		$	131.8		$	107.5			$	135.1		$	(51.8	)
Income (loss) from equity investees	0.7			—				—			(0.1		)	0.8			(d)	—			—
Losses on foreign currency contracts, net	(11.0		)	—				—			(9.0		)	—				—			(2.0		)
Interest expense	(58.1		)	—				(41.0		)	(5.2		)	(0.7		)		(11.1		)	(0.1		)
Income (loss) before income taxes	$	521.1		$	0.3			$	225.6		$	117.5		$	107.6			$	124.0		$	(53.9	)
Partnership Adjusted EBITDA (a)								$	309.5
Noncontrolling interests’ net income (loss)	$	131.7		$	—			$	155.7		$	(1.2	)	$	—			$	—		$	(22.8	)
Depreciation and amortization	$	112.2		$	(0.1	)		$	45.2		$	34.9		$	10.8			$	21.1		$	0.3
Capital expenditures (including the effects of accruals)	$	110.1		$	—			$	23.6		$	26.1		$	4.3			$	55.1		$	1.0



Three Months Ended March 31, 2017	Total			Eliminations				AmeriGas Propane			UGI International			Midstream & Marketing				UGI Utilities			Corporate & Other (b)
Revenues	$	2,173.8		$	—			$	863.6		$	620.7		$	347.5			$	341.2		$	0.8
Intersegment revenues	$	—		$	(95.8	)	(c)	$	—		$	—		$	76.2			$	18.8		$	0.8
Cost of sales	$	1,071.2		$	(94.9	)	(c)	$	355.8		$	313.1		$	309.8			$	164.5		$	22.9
Segment profit:
Operating income (loss)	$	513.2		$	—			$	227.3		$	121.0		$	82.1			$	116.4		$	(33.6	)
Income (loss) from equity investees	2.3			—				—			(0.1		)	2.4			(d)	—			—
(Losses) gains on foreign currency contracts, net	(1.2		)	—				—			0.1			—				—			(1.3		)
Loss on extinguishments of debt	(22.1		)	—				(22.1		)	—			—				—			—
Interest expense	(55.8		)	—				(40.0		)	(4.8		)	(0.7		)		(10.3		)	—
Income (loss) before income taxes	$	436.4		$	—			$	165.2		$	116.2		$	83.8			$	106.1		$	(34.9	)
Partnership Adjusted EBITDA (a)								$	271.2
Noncontrolling interests’ net income (loss)	$	91.9		$	—			$	112.7		$	0.1		$	—			$	—		$	(20.9	)
Depreciation and amortization	$	99.3		$	(0.1	)		$	45.0		$	27.6		$	8.8			$	17.7		$	0.3
Capital expenditures (including the effects of accruals)	$	126.2		$	—			$	27.2		$	21.5		$	20.8			$	56.5		$	0.2

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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



Six Months Ended March 31, 2018	Total			Eliminations				AmeriGas Propane			UGI International			Midstream & Marketing				UGI Utilities			Corporate & Other (b)
Revenues	$	4,937.2		$	—			$	1,827.6		$	1,693.8		$	686.0			$	730.0		$	(0.2	)
Intersegment revenues	$	—		$	(286.0	)	(c)	$	—		$	—		$	207.2			$	76.4		$	2.4
Cost of sales	$	2,697.6		$	(283.9	)	(c)	$	849.8		$	1,025.9		$	657.6			$	409.1		$	39.1
Segment profit:
Operating income (loss)	$	981.3		$	0.5			$	414.5		$	224.9		$	159.8			$	231.4		$	(49.8	)
Income (loss) from equity investees	1.7			—				—			(0.3		)	2.0			(d)	—			—
Losses on foreign currency contracts, net	(15.8		)	—				—			(13.7		)	—				—			(2.1		)
Interest expense	(116.3		)	—				(81.6		)	(10.8		)	(1.6		)		(22.0		)	(0.3		)
Income (loss) before income taxes	$	850.9		$	0.5			$	332.9		$	200.1		$	160.2			$	209.4		$	(52.2	)
Partnership Adjusted EBITDA (a)								$	503.6
Noncontrolling interests’ net income (loss)	$	200.0		$	—			$	223.7		$	(1.5	)	$	—			$	—		$	(22.2	)
Depreciation and amortization	$	222.5		$	(0.1	)		$	92.6		$	67.1		$	20.9			$	41.5		$	0.5
Capital expenditures (including the effects of accruals)	$	238.6		$	—			$	47.2		$	47.8		$	15.6			$	126.8		$	1.2
As of March 31, 2018
Total assets	$	12,445.3		$	(59.4	)		$	4,149.8		$	3,562.3		$	1,347.7			$	3,204.0		$	240.9
Short-term borrowings	$	302.8		$	—			$	154.5		$	3.3		$	10.0			$	135.0		$	—
Goodwill	$	3,218.1		$	—			$	2,001.3		$	1,023.2		$	11.5			$	182.1		$	—



Six Months Ended March 31, 2017	Total			Eliminations				AmeriGas Propane			UGI International			Midstream & Marketing				UGI Utilities			Corporate & Other (b)
Revenues	$	3,853.3		$	—			$	1,540.8		$	1,159.8		$	557.1			$	595.1		$	0.5
Intersegment revenues	$	—		$	(164.3	)	(c)	$	—		$	—		$	136.4			$	26.3		$	1.6
Cost of sales	$	1,718.6		$	(162.6	)	(c)	$	616.5		$	571.1		$	501.6			$	274.0		$	(82.0	)
Segment profit:
Operating income	$	979.4		$	0.1			$	369.2		$	209.9		$	131.8			$	198.6		$	69.8
Income (loss) from equity investees	2.1			—				—			(0.3		)	2.4			(d)	—			—
Gains (losses) on foreign currency contracts, net	0.1			—				—			0.2			—				—			(0.1		)
Loss on extinguishments of debt	(55.3		)	—				(55.3		)	—			—				—			—
Interest expense	(111.2		)	—				(80.0		)	(9.6		)	(1.3		)		(20.3		)	—
Income before income taxes	$	815.1		$	0.1			$	233.9		$	200.2		$	132.9			$	178.3		$	69.7
Partnership Adjusted EBITDA (a)								$	456.3
Noncontrolling interests’ net income (loss)	$	152.1		$	—			$	153.9		$	0.3		$	—			$	—		$	(2.1	)
Depreciation and amortization	$	197.4		$	(0.1	)		$	89.6		$	55.5		$	16.8			$	35.1		$	0.5
Capital expenditures (including the effects of accruals)	$	299.8		$	—			$	53.6		$	43.0		$	82.3			$	120.6		$	0.3
As of March 31, 2017
Total assets	$	11,385.5		$	(58.6	)		$	4,238.1		$	2,804.7		$	1,200.7			$	2,909.7		$	290.9
Short-term borrowings	$	50.1		$	—			$	—		$	1.6		$	—			$	48.5		$	—
Goodwill	$	2,948.4		$	—			$	1,981.2		$	773.6		$	11.5			$	182.1		$	—

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

(a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes:



	Three Months Ended March 31,						Six Months Ended March 31,
	2018			2017			2018			2017
Partnership Adjusted EBITDA	$	309.5		$	271.2		$	503.6		$	456.3
Depreciation and amortization	(45.2		)	(45.0		)	(92.6		)	(89.6		)
Interest expense	(41.0		)	(40.0		)	(81.6		)	(80.0		)
Loss on extinguishments of debt	—			(22.1		)	—			(55.3		)
Noncontrolling interest (i)	2.3			1.1			3.5			2.5
Income before income taxes	$	225.6		$	165.2		$	332.9		$	233.9


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

(b)

Includes net pre-tax (losses) gains on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $(48.1) and $(23.9) during the three months ended March 31, 2018 and 2017 , respectively, and $(41.5) and $81.6 during the six months ended March 31, 2018 and 2017 , respectively. Corporate & Other results for the three and six months ended March 31, 2017 , also include a pre-tax loss of $7.0 associated with the impairment of a cost basis investment (see Note 2).


(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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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 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”). Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

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 that actual results almost always 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 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 resulting in reduced demand; (2) cost volatility and availability of propane and other liquefied petroleum gases (“LPG”), oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax, consumer protection, environmental and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers and 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; (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, terrorism, 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; (13) transmission or distribution system service interruptions; (14) political, regulatory and economic conditions in the United States and in foreign countries, including the current conflicts in the Middle East, and foreign currency exchange rate fluctuations, particularly the euro; (15) 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) reduced distributions from subsidiaries impacting the ability to pay dividends; (18) changes in Marcellus Shale gas production; (19) the availability, timing and success of our acquisitions, commercial initiatives and investments to grow our businesses; (20) our ability to successfully integrate acquired businesses and achieve anticipated synergies; (21) the interruption, disruption, failure, malfunction, or breach of our information technology systems, including due to cyber attack; and (22) continued analysis of recent tax legislation.

These factors, and those factors set forth in Item 1A. Risk Factors in the Company’s 2017 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. We undertake no 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.

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare the Company’s results of operations for the three months ended March 31, 2018 (“2018 three-month period”) with the three months ended March 31, 2017 (“2017 three-month period”) and the six months ended March 31, 2018 (“2018 six-month period”) with the six months ended March 31, 2017 (“2017 six-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 15 to the 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.

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 gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period

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transactions and (2) other significant discrete items that management believes affect the comparison of period-over-period results. For further information on these non-GAAP financial measures including reconciliations of such non-GAAP financial measures to the most directly comparable GAAP measures, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share” below.

Our net income for the three and six months ended March 31, 2018, was affected by the December 22, 2017, enactment of the Tax Cuts and Jobs Act (the “TCJA”) and the December 2017 French Finance Bills as further discussed below under “Financial Condition and Liquidity - Impact of Tax Reform” and in Note 5 to condensed consolidated financial statements.

Our results for the three- and six-month periods ended March 31, 2018 include two types of impacts from 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 existing as of the dates the tax laws were enacted. These “one-time” adjustments to our income tax assets and liabilities have been excluded from our non-GAAP financial measures below.

The second impact 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 the current period results principally reflects the lower U.S. corporate income tax rate which for Fiscal 2018 consists of a blended federal corporate income tax rate of 24.5%. With respect to the December 2017 French Finance Bills, the impact on the current period results principally reflects the higher Fiscal 2018 French corporate income tax rate of 39.4%. These current-period impacts of the TCJA and the December 2017 French Finance Bills on current-period results have been included in our non-GAAP financial measures below.

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EXECUTIVE OVERVIEW

THREE MONTHS ENDED MARCH 31, 2018 AND 2017

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

Net income (loss) attributable to UGI Corporation for the three months ended March 31, 2018 and 2017 is as follows:



For the three months ended March 31,	2018					2017					Variance - Favorable (Unfavorable)
(Dollars in millions)	Amount (a)			% of Total		Amount			% of Total		Amount			% Change
AmeriGas Propane (b)	$	49.8		18.0	%	$	32.0		14.6	%	$	17.8		55.6	%
UGI International (c) (d)	77.4			28.0	%	79.3			36.1	%	(1.9		)	(2.4	)%
Midstream & Marketing	76.6			27.8	%	50.2			22.8	%	26.4			52.6	%
UGI Utilities	89.2			32.3	%	65.1			29.6	%	24.1			37.0	%
Corporate & Other (e) (f)	(17.0		)	(6.1	)%	(6.7		)	(3.1	)%	(10.3		)	N.M.
Net income attributable to UGI Corporation	$	276.0		100.0	%	$	219.9		100.0	%	$	56.1		25.5	%


(a)	Net income attributable to UGI Corporation for the three months ended March 31, 2018, includes changes to provisional one-time adjustments initially recorded in December 2017 as a result of the enactment of the TCJA which decreased income taxes and increased net income attributable to UGI by business unit as follows:



UGI International	$	0.2
Corporate & Other	5.1
Net income attributable to UGI Corporation	$	5.3

In addition to these changes to provisional one-time adjustments from the TCJA, net income attributable to UGI for the three months ended March 31, 2018, also reflects the current-period beneficial impact of the TCJA, principally due to the lower federal income tax rate in Fiscal 2018, of approximately $34.0 million.


(b)	Three months ended March 31, 2017, includes net after-tax loss of $3.6 million from extinguishments of debt.

(c)

Three months ended March 31, 2018, includes changes to provisional one-time adjustments initially recorded in December 2017 as a result of the enactment of the December 2017 French Finance Bills which increased income taxes and decreased net income attributable to UGI by $3.7 million. In addition to this change to the provisional one-time adjustments from the December 2017 French Finance Bills, net income attributable to UGI for the three months ended March 31, 2018 also reflects the current-period negative impact of the December 2017 French Finance Bills, principally due to the higher French income tax rate in Fiscal 2018, of approximately $1.1 million.


(d)	Includes after-tax integration expenses associated with Finagaz acquired on May 29, 2015 of $6.8 million and $4.4 million for the three months ended March 31, 2018 and 2017, respectively.

(e)

Includes net after-tax losses on commodity derivative instruments not associated with current-period transactions of $15.7 million and $3.1 million for the three months ended March 31, 2018 and 2017, respectively. Also includes after-tax unrealized losses on certain foreign currency derivative instruments of $1.3 million and $0.8 million for the three months ended March 31, 2018 and 2017, respectively.


(f)	Three months ended March 31, 2017, includes $4.5 million after-tax loss associated with the impairment of a cost basis investment (see Note 2 to condensed consolidated financial statements).

N.M. — Variance is not meaningful.

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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 March 31, 2018 and 2017 is as follows:



For the three months ended March 31,	2018					2017					Variance - Favorable (Unfavorable)
(Dollars in millions)	Amount			% of Total		Amount			% of Total		Amount			% Change
AmeriGas Propane	$	49.8		16.7	%	$	35.6		15.4	%	$	14.2		39.9	%
UGI International	87.7			29.4	%	83.7			36.1	%	4.0			4.8	%
Midstream & Marketing	76.6			25.7	%	50.2			21.7	%	26.4			52.6	%
UGI Utilities	89.2			29.9	%	65.1			28.1	%	24.1			37.0	%
Corporate & Other	(5.1		)	(1.7	)%	(2.8		)	(1.3	)%	(2.3		)	N.M.
Adjusted net income attributable to UGI Corporation	$	298.2		100.0	%	$	231.8		100.0	%	$	66.4		28.6	%

Discussion. Adjusted net income attributable to UGI Corporation for the 2018 three-month period was $298.2 million (equal to $1.69 per diluted share) compared to $231.8 million (equal to $1.31 per diluted share) for the 2017 three-month period.

Our adjusted results for the three months ended March 31, 2018, reflect the benefits of U.S. weather that was colder than the significantly warmer-than-normal temperatures experienced in the prior-year three-month period but slightly warmer than normal. Weather at our UGI International service territories was slightly colder than normal and colder than the prior-year period.

Midstream & Marketing results in the 2018 three-month period benefited from colder and more volatile weather patterns as well as income from the recent expansion of our natural gas gathering, natural gas pipeline, liquefied natural gas (“ LNG”) and natural gas peaking investments, and higher electric generation net income. UGI Utilities improved results include the impact of the colder weather on core market customer volumes as well as higher base rates at PNG, which became effective on October 20, 2017. AmeriGas Propane retail volumes sold during the 2018 three-month period also benefited from much colder weather in the 2018 three-month period. Our UGI International results benefited from the colder weather as well as incremental income from the October 2017 acquisition of Total’s retail LPG operations in Italy (now known as “UniverGas”) and the August 2017 acquisition of an electricity and natural gas marketing business in the Netherlands (“DVEP”).

Our adjusted results for the three months ended March 31, 2018 also reflect the current-period tax effects of the TCJA and the December 2017 French Finance Bills. For the three months ended March 31, 2018, the current-period effects of the TCJA (primarily the impact of a blended 24.5% U.S. corporate income tax rate compared to a 35% rate in the prior-year period) increased net income attributable to UGI by approximately $34.0 million. With respect to the December 2017 French Finance Bills, adjusted results for the three months ended March 31, 2018 reflect a higher French income tax rate which decreased adjusted net income attributable to UGI by approximately $1.1 million. On a combined basis, the changes from the TCJA and the December 2017 French Finance Bills increased current-period adjusted net income attributable to UGI by $32.9 million, or $0.19 per diluted share, during the three months ended March 31, 2018.

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SIX MONTHS ENDED MARCH 31, 2018 AND 2017

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

Net income (loss) attributable to UGI Corporation for the six months ended March 31, 2018 and 2017 is as follows:



For the six months ended March 31,	2018					2017				Variance - Favorable (Unfavorable)
(Dollars in millions)	Amount (a)			% of Total		Amount		% of Total		Amount			% Change
AmeriGas Propane (b)	$	191.4		29.8	%	$	48.6	10.8	%	$	142.8		293.8	%
UGI International (c)(d)	138.5			21.6	%	167.6		37.2	%	(29.1		)	(17.4	)%
Midstream & Marketing	188.6			29.4	%	80.1		17.8	%	108.5			135.5	%
UGI Utilities	157.5			24.5	%	109.4		24.3	%	48.1			44.0	%
Corporate & Other (e)(f)	(34.1		)	(5.3	)%	44.9		9.9	%	(79.0		)	N.M.
Net income attributable to UGI Corporation	$	641.9		100.0	%	$	450.6	100.0	%	$	191.3		42.5	%


(a)	Net income attributable to UGI Corporation for the six months ended March 31, 2018, 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	(9.1		)
Midstream & Marketing	74.3
UGI Utilities	8.1
Corporate & Other	(15.1		)
Net income attributable to UGI Corporation	$	171.3

In addition to these one-time adjustments from the TCJA, net income attributable to UGI for the six months ended March 31, 2018, also reflects the current-period beneficial impact of the TCJA principally due to the lower federal income tax rate in Fiscal 2018 of approximately $54.5 million.


(b)	Six months ended March 31, 2017, includes net after-tax loss of $8.9 million from extinguishments of debt.

(c)

Six months ended March 31, 2018, includes beneficial impact of a $13.6 million adjustment to net deferred income tax liabilities associated with the enactment of the December 2017 French Finance Bills. Six months ended March 31, 2017, 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 six months ended March 31, 2018, also reflects the current-period negative impact of the December 2017 French Finance Bills principally due to the higher French income tax rate in Fiscal 2018 of approximately $5.0 million.


(d)	Includes after-tax integration expenses associated with Finagaz of $8.0 million and $9.7 million for the six months ended March 31, 2018 and 2017, respectively.


(e)	Includes net after-tax (losses) gains on commodity derivative instruments not associated with current-period transactions of $(11.1) million and $49.1 million for the six months ended March 31, 2018 and 2017, respectively. Also includes after-tax unrealized losses on certain foreign currency derivative instruments of $1.4 million for the six months ended March 31, 2018.


(f)	Six months ended March 31, 2017, includes a $4.5 million after-tax loss associated with the impairment of a cost basis investment (see Note 2 to condensed consolidated financial statements).

N.M. — Variance is not meaningful.

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

Adjusted net income (loss) attributable to UGI Corporation for the six months ended March 31, 2018 and 2017 is as follows:



For the six months ended March 31,	2018					2017					Variance - Favorable (Unfavorable)
(Dollars in millions)	Amount			% of Total		Amount			% of Total		Amount			% Change
AmeriGas Propane	$	78.3		16.4	%	$	57.5		14.6	%	$	20.8		36.2	%
UGI International	142.0			29.7	%	149.9			38.2	%	(7.9		)	(5.3	)%
Midstream & Marketing	114.3			23.9	%	80.1			20.4	%	34.2			42.7	%
UGI Utilities	149.4			31.3	%	109.4			27.9	%	40.0			36.6	%
Corporate & Other	(6.5		)	(1.3	)%	(4.2		)	(1.1	)%	(2.3		)	N.M.
Adjusted net income attributable to UGI Corporation	$	477.5		100.0	%	$	392.7		100.0	%	$	84.8		21.6	%

Discussion. Adjusted net income attributable to UGI Corporation for the 2018 six-month period was $477.5 million (equal to $2.70 per diluted share) compared to adjusted net income attributable to UGI Corporation for the 2017 six-month period of $392.7 million (equal to $2.22 per diluted share).

Temperatures in our U.S. business units during the six months ended March 31, 2018, were colder than the significantly warmer-than-normal temperatures experienced in the prior-year six-month period. Average temperatures at UGI International were slightly colder than normal and about equal to the prior-year period. UGI Utilities improved results reflect, among other things, the impact of the colder weather as well as higher base rates at PNG, which became effective on October 20, 2017. Midstream & Marketing results benefited from colder and more volatile weather principally in late December and January as well as income from the recent expansion of our natural gas gathering, natural gas pipeline, LNG storage and natural gas peaking investments and higher electric generation net income. AmeriGas Propane retail volumes sold during the 2018 six-month period also benefited from the effects of the much colder weather on heating-related retail volumes. Our 2018 six-month period UGI International net income benefited from incremental net income from UniverGas and DVEP but was negatively impacted by a higher effective income tax rate as a result of the December 2017 French Finance Bills.

Our adjusted results for the six months ended March 31, 2018 also reflect the current-period tax effects of the TCJA and the December 2017 French Finance Bills. For the six months ended March 31, 2018, the current-period effects of the TCJA (primarily the impact of the lower blended U.S. corporate income tax rate of 24.5%) increased adjusted net income attributable to UGI by approximately $54.5 million. The current-period effects of the December 2017 French Finance Bills (including the higher Fiscal 2018 French corporate income tax rate) decreased adjusted net income attributable to UGI by approximately $5.0 million. On a combined basis, the changes from the TCJA and the December 2017 French Finance Bills increased current-period adjusted net income attributable to UGI by $49.5 million, or $0.28 per diluted share, for the six months ended March 31, 2018.

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 2018 and 2017 three- and six-month periods, adjusted net income attributable to UGI Corporation is net income attributable to UGI after excluding (1) 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) (2) Finagaz integration expenses, (3) losses associated with extinguishments of debt at AmeriGas Propane and (4) the one-time impacts on income tax balances resulting from the enactments of the TCJA and French Finance Bills. UGI does not designate its commodity and certain foreign currency derivative instruments as hedges under U.S. generally accepted accounting principles (“GAAP”). Volatility in net income 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 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

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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.

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.

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



Three Months Ended March 31, 2018	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	$	276.0		$	49.8	$	77.4		$	76.6	$	89.2	$	(17.0	)
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $(8.1)) (a)	15.7			—		—			—		—		15.7
Unrealized losses on foreign currency derivative instruments (net of tax of $(0.7)) (a)	1.3			—		—			—		—		1.3
Integration expenses associated with Finagaz (net of tax of $(4.5)) (a)	6.8			—		6.8			—		—		—
Impact of December 2017 French Finance Bills	3.7			—		3.7			—		—		—
Impact from TCJA	(5.3		)	—		(0.2		)	—		—		(5.1		)
Adjusted net income (loss) attributable to UGI Corporation	$	298.2		$	49.8	$	87.7		$	76.6	$	89.2	$	(5.1	)

Adjusted diluted earnings per share:
UGI Corporation earnings (loss) per share — diluted	$	1.57		$	0.28	$	0.44		$	0.43	$	0.51	$	(0.09	)
Net losses on commodity derivative instruments not associated with current-period transactions (b)	0.08			—		—			—		—		0.08
Unrealized losses on foreign currency derivative instruments	0.01			—		—			—		—		0.01
Integration expenses associated with Finagaz	0.04			—		0.04			—		—		—
Impact of December 2017 French Finance Bills	0.02			—		0.02			—		—		—
Impact from TCJA	(0.03		)	—		—			—		—		(0.03		)
Adjusted diluted earnings (loss) per share	$	1.69		$	0.28	$	0.50		$	0.43	$	0.51	$	(0.03	)

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Three Months Ended March 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	$	219.9	$	32.0	$	79.3	$	50.2	$	65.1	$	(6.7	)
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $1.5) (a)	3.1		—		—		—		—		3.1
Unrealized losses on foreign currency derivative instruments (net of tax of $(0.5)) (a)	0.8		—		—		—		—		0.8
Loss on extinguishment of debt (net of tax of $(2.3)) (a)	3.6		3.6		—		—		—		—
Integration expenses associated with Finagaz (net of tax of $(2.3)) (a)	4.4		—		4.4		—		—		—
Adjusted net income (loss) attributable to UGI Corporation	$	231.8	$	35.6	$	83.7	$	50.2	$	65.1	$	(2.8	)

Adjusted diluted earnings per share:
UGI Corporation earnings (loss) per share - diluted	$	1.24	$	0.18	$	0.45	$	0.28	$	0.37	$	(0.04	)
Net losses on commodity derivative instruments not associated with current-period transactions	0.02		—		—		—		—		0.02
Unrealized losses on foreign currency derivative instruments (b)	0.01		—		—		—		—		0.01
Loss on extinguishment of debt	0.02		0.02		—		—		—		—
Integration expenses associated with Finagaz	0.02		—		0.02		—		—		—
Adjusted diluted earnings (loss) per share	$	1.31	$	0.20	$	0.47	$	0.28	$	0.37	$	(0.01	)

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Six Months Ended March 31, 2018	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	$	641.9		$	191.4		$	138.5		$	188.6		$	157.5		$	(34.1	)
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $6.0) (a)	11.1			—			—			—			—			11.1
Unrealized losses on foreign currency derivative instruments (net of tax of $(0.7)) (a)	1.4			—			—			—			—			1.4
Integration expenses associated with Finagaz (net of tax of $(5.2)) (a)	8.0			—			8.0			—			—			—
Impact of December 2017 French Finance Bills	(13.6		)	—			(13.6		)	—			—			—
Impact from TCJA	(171.3		)	(113.1		)	9.1			(74.3		)	(8.1		)	15.1
Adjusted net income (loss) attributable to UGI Corporation	$	477.5		$	78.3		$	142.0		$	114.3		$	149.4		$	(6.5	)

Adjusted diluted earnings per share:
UGI Corporation earnings (loss) per share — diluted	$	3.63		$	1.08		$	0.78		$	1.07		$	0.89		$	(0.19	)
Net losses on commodity derivative instruments not associated with current-period transactions	0.06			—			—			—			—			0.06
Unrealized losses on foreign currency derivative instruments	0.01			—			—			—			—			0.01
Integration expenses associated with Finagaz	0.05			—			0.05			—			—			—
Impact of December 2017 French Finance Bills	(0.08		)	—			(0.08		)	—			—			—
Impact from TCJA	(0.97		)	(0.64		)	0.05			(0.42		)	(0.05		)	0.09
Adjusted diluted earnings (loss) per share	$	2.70		$	0.44		$	0.80		$	0.65		$	0.84		$	(0.03	)

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Six Months Ended March 31, 2017	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	$	450.6		$	48.6	$	167.6		$	80.1	$	109.4	$	44.9
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $34.8) (a)	(49.1		)	—		—			—		—		(49.1		)
Loss on extinguishments of debt (net of tax of $(5.7)) (a)	8.9			8.9		—			—		—		—
Integration expenses associated with Finagaz (net of tax of $(5.1)) (a)	9.7			—		9.7			—		—		—
Impact from December 2016 French Finance Bills	(27.4		)	—		(27.4		)	—		—		—
Adjusted net income (loss) attributable to UGI Corporation	$	392.7		$	57.5	$	149.9		$	80.1	$	109.4	$	(4.2	)

Adjusted diluted earnings per share:
UGI Corporation earnings per share - diluted	$	2.55		$	0.27	$	0.95		$	0.45	$	0.62	$	0.26
Net gains on commodity derivative instruments not associated with current-period transactions	(0.28		)	—		—			—		—		(0.28		)
Loss on extinguishments of debt	0.05			0.05		—			—		—		—
Integration expenses associated with Finagaz	0.05			—		0.05			—		—		—
Impact from December 2016 French Finance Bills	(0.15		)	—		(0.15		)	—		—		—
Adjusted diluted earnings (loss) per share	$	2.22		$	0.32	$	0.85		$	0.45	$	0.62	$	(0.02	)


(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.

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SEGMENT RESULTS OF OPERATIONS

Note - Average temperatures based upon heating degree days for all of our business segments presented below are now based upon recent 15-year periods (rather than recent 30-year periods) as we believe more recent temperatures are a better indication of normal heating degree days. Prior-period weather statistics have been restated, as appropriate, to conform to the new periods.

2018 Three-Month Period Compared to the 2017 Three-Month Period

AmeriGas Propane



For the three months ended March 31,	2018			2017			Increase
(Dollars in millions)
Revenues	$	1,040.3		$	863.6		$	176.7	20.5	%
Total margin (a)	$	556.6		$	507.8		$	48.8	9.6	%
Partnership operating and administrative expenses	$	251.5		$	240.0		$	11.5	4.8	%
Partnership Adjusted EBITDA (b)	$	309.5		$	271.2		$	38.3	14.1	%
Operating income (c)	$	266.6		$	227.3		$	39.3	17.3	%
Retail gallons sold (millions)	398.5			362.7			$	35.8	9.9	%
Heating degree days—% (warmer) than normal (e)	(0.5		)%	(12.9		)%	—		—


(a)	Total margin represents total revenues less total cost of sales. Total margin for the three months ended March 31, 2018 and 2017 excludes net pre-tax losses of $31.2 million and $28.6 million, respectively, on 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)	Operating income reflects certain operating and administrative expenses of the General Partner.


(d)	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.

AmeriGas Propane’s retail gallons sold during the 2018 three-month period increased 9.9% compared with the prior-year period. Average temperatures based upon heating degree days during the 2018 three-month period were 0.5% warmer than normal but 14.2% colder than the prior-year period.

Retail propane revenues increased $164.6 million during the 2018 three-month period reflecting the effects of higher average retail selling prices ($87.6 million) and the higher retail volumes sold ($77.0 million). Wholesale propane revenues increased $7.3 million reflecting higher wholesale volumes sold ($3.8 million) and the effects of higher average wholesale selling prices ($3.5 million). Average daily wholesale propane commodity prices during the 2018 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 18% higher than such prices in the 2017 three-month period. Other revenues in the 2018 three-month period were $4.7 million higher than in the prior-year period principally reflecting higher fee revenues on increased retail volumes sold. AmeriGas Propane total cost of sales increased $127.9 million principally reflecting the effects of higher Partnership average propane product costs ($90.4 million) and the effects of the higher volumes sold ($35.6 million).

AmeriGas Propane total margin increased $48.8 million in the 2018 three-month period principally reflecting higher retail propane total margin ($45.8 million) and slightly higher other margin. The increase in retail propane total margin reflects the higher retail volumes sold and slightly higher average retail unit margin.

Partnership Adjusted EBITDA increased $38.3 million in the 2018 three-month period principally reflecting the effects of the higher total margin ( $48.8 million ) partially offset by higher Partnership operating and administrative expenses ($11.5 million). Partnership operating and administrative expenses increased reflecting, among other things, higher total compensation costs ($9.1 million) principally higher labor and incentive compensation costs associated with the increased activity and improved performance, and higher vehicle expenses ($2.3 million) including higher vehicle fuel and lease expenses. AmeriGas Propane operating income increased $39.3 million in the 2018 three-month period principally reflecting the $38.3 million increase in Partnership Adjusted EBITDA.

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During the 2017 three-month period, AmeriGas Partners recognized a pre-tax loss of $22.1 million associated with an early repayment of $378.3 million principal amount of AmeriGas Partners’ 7.00% Senior Notes comprising early redemption premiums and the write-off of unamortized debt issuance costs.

UGI International



For the three months ended March 31,	2018			2017			Increase
(Dollars in millions)
Revenues	$	909.6		$	620.7		$	288.9	46.5	%
Total margin (a)	$	368.5		$	307.6		$	60.9	19.8	%
Operating and administrative expenses (b)	$	199.5		$	159.6		$	39.9	25.0	%
Operating income (b)	$	131.8		$	121.0		$	10.8	8.9	%
Income before income taxes (b) (c)	$	117.5		$	116.2		$	1.3	1.1	%
LPG retail gallons sold (millions)	278.1			253.1			$	25.0	9.9	%
UGI International degree days—% colder (warmer) than normal (d)	2.2		%	(3.9		)%	—		—


(a)	Total margin represents total revenues less total cost of sales. Total margin for the three months ended March 31, 2018 and 2017 excludes net pre-tax losses of $20.6 million and $17.4 million, respectively, on commodity derivative instruments not associated with current-period transactions.


(b)	Reflects impacts of Finagaz integration expenses for the three months ended March 31, 2018 and 2017, of $11.3 million and $6.7 million, respectively.


(c)	Income before income taxes for the three months ended March 31, 2018 and 2017 excludes net pre-tax unrealized losses on certain foreign currency derivative contracts of $2.0 million and $1.3 million, respectively.


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

Average temperatures during the 2018 three-month period were approximately 2.2% colder than normal and 6.3% colder than the prior-year period. Total retail gallons sold during the 2018 three-month period were higher than the prior-year period as incremental retail gallons sold as a result of our October 2017 acquisition of UniverGas in Italy and the effects on legacy business volumes from the colder weather.

UGI International base-currency results are translated into U.S. dollars 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 2018 and 2017 three-month periods, the average unweighted euro-to-dollar translation rates were approximately $1.23 and $1.07, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.39 and $1.25, respectively. Although the euro and British pound sterling were stronger during the 2018 three-month period and impact the year-over-year comparisons of line item amounts presented in the table above, the effects of these stronger currencies did not have a significant impact on UGI International net income due to gains and losses on foreign currency exchange contracts recorded in both periods.

UGI International revenues increased $288.9 million during the 2018 three-month period reflecting approximately $135.4 million of combined incremental revenues from UniverGas and DVEP, the translation effects on local currency revenues of the stronger euro and British pound sterling and the effects of higher LPG selling prices. UGI International cost of sales increased $228.0 million during the 2018 three-month period reflecting approximately $114.8 million of incremental cost of sales associated with UniverGas and DVEP, the translation effects of the stronger euro and British pound sterling and higher LPG commodity costs.

UGI International total margin increased $60.9 million primarily reflecting the translation effects of the stronger euro and British pound sterling, approximately $20.6 million of incremental margin from UniverGas and DVEP and, to a much lesser extent, slightly higher legacy business LPG retail volumes sold. These increases in margin were partially offset by the effects of slightly lower average LPG retail bulk unit margins at our legacy business.

The $10.8 million increase in UGI International operating income principally reflects the previously mentioned $60.9 million increase in total margin partially offset by a $39.9 million increase in operating and administrative costs and a $7.3 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. Operating and administrative costs in the 2018 and 2017 three-month periods include $11.3

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million and $6.7 million of Finagaz integration costs, respectively. These increases in operating and administrative expenses were partially offset by expense synergies from Finagaz integration activities and lower tank and cylinder repairs and maintenance. The higher depreciation and amortization expense reflects the translation effects of the stronger currencies, the net impact of changes in estimated book lives of certain tanks and cylinders, and incremental amounts associated with UniverGas and DVEP ($2.2 million). UGI International income before income taxes increased $1.3 million principally reflecting the previously mentioned $10.8 million increase in UGI International operating income reduced by higher realized losses on foreign currency exchange contracts ($9.1 million) and slightly higher interest expense reflecting the effects of the stronger euro.

Midstream & Marketing



For the three months ended March 31,	2018		2017		Increase
(Dollars in millions)
Revenues	$	565.2	$	423.7	$	141.5	33.4	%
Total margin (a)	$	146.6	$	113.9	$	32.7	28.7	%
Operating and administrative expenses	$	28.4	$	24.0	$	4.4	18.3	%
Operating income	$	107.5	$	82.1	$	25.4	30.9	%
Income before income taxes	$	107.6	$	83.8	$	23.8	28.4	%


(a)	Total margin represents total revenues less total cost of sales. Total margin for the three months ended March 31, 2018 and 2017 excludes net pre-tax gains of $5.7 million and $23.4 million, respectively, on commodity derivative instruments not associated with current-period transactions.

Temperatures across Midstream & Marketing’s energy marketing territory were approximately 1.9% warmer than normal but 14.3% colder than in the prior-year period. Midstream & Marketing 2018 three-month period revenues were $141.5 million higher reflecting higher natural gas ($104.3 million) and retail power marketing ($5.2 million) revenues, and higher capacity management ($12.5 million), natural gas gathering ($7.8 million) and electric generation and peaking revenues. The increase in natural gas revenues principally reflects the effects of higher average natural gas prices and to a lesser extent higher natural gas volumes resulting from the colder 2018 three-month period temperatures and customer growth. The increase in capacity management and peaking revenues principally reflects the effects of colder weather in January and, with respect to peaking revenues, an increase in the number of peaking contracts. The higher natural gas gathering revenues reflects incremental revenues from the Sunbury Pipeline placed in service in August 2017 and incremental revenues from the acquisition of a north-central Pennsylvania natural gas gathering system acquired October 31, 2017. Electric generation revenues increased, reflecting higher volumes generated principally from the Hunlock natural-gas fired generation station and higher average selling prices. Midstream & Marketing cost of sales were $418.6 million in the 2018 three-month period compared to $309.8 million in the 2017 three-month period, an increase of $108.8 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 $32.7 million in the 2018 three-month period reflecting higher total margin from our midstream assets ($27.0 million), principally the result of higher capacity management, peaking and natural gas gathering total margin, and higher electricity generation total margin ($4.6 million). The increase in capacity management and peaking total margin principally reflects the effects of extremely cold weather early in the 2018 three-month period and, with respect to peaking margin, an increase in the number of peaking contracts. The higher natural gas gathering total margin reflects incremental margin from the Sunbury Pipeline and, to a much lesser extent, margin from the previously mentioned natural gas gathering assets acquired in October 2017. The higher electricity generation total margin reflects higher electric generation volumes principally at our Hunlock Station generating facility and higher electricity unit margins.

Midstream & Marketing operating income and income before income taxes during the 2018 three-month period increased $25.4 million and $23.8 million , respectively. The increase in operating income principally reflects the previously mentioned increase in total margin ( $32.7 million ) partially offset by higher operating and administrative expenses ($4.4 million), higher depreciation expense ($2.0 million), and a $2.9 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 $4.4 million increase in operating and administrative expenses reflects higher compensation and benefits expense and higher expenses associated with greater peaking, LNG and natural gas gathering activities, while the increase in depreciation expense principally reflects incremental depreciation from the expansion of our natural gas pipeline, natural gas gathering, LNG and peaking assets. The increase in income before income taxes in the 2018 three-month period reflects the higher operating income partially offset by a $1.6 million decrease in equity income from our PennEast pipeline equity investment reflecting higher AFUDC income recorded in the prior year.

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UGI Utilities



For the three months ended March 31,	2018			2017			Increase
(Dollars in millions)
Revenues	$	483.3		$	360.0		$	123.3	34.3	%
Total margin (a)	$	224.6		$	194.2		$	30.4	15.7	%
Operating and administrative expenses (a)	$	69.4		$	61.3		$	8.1	13.2	%
Operating income	$	135.1		$	116.4		$	18.7	16.1	%
Income before income taxes	$	124.0		$	106.1		$	17.9	16.9	%
Gas Utility system throughput—billions of cubic feet (“bcf”)
Core market	38.9			33.8			5.1		15.1	%
Total	87.3			81.8			5.5		6.7	%
Electric Utility distribution sales - millions of kilowatt hours (“gwh”)	278.7			260.5			18.2		7.0	%
Gas Utility heating degree days—% (warmer) than normal (b)	(2.2		)%	(11.7		)%	—		—

(a)

Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e., Electric Utility gross receipts taxes, of $1.4 million and $1.2 million during the three months ended March 31, 2018 and 2017, respectively. For financial statement purposes, revenue-related taxes are included in “ Operating and administrative expenses ” on the Condensed Consolidated Statements of Income (but excluded from operating expenses presented above).


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

Temperatures in Gas Utility’s service territory during the three months ended March 31, 2018, were 2.2% warmer than normal but 10.8% colder than in the prior-year period. Gas Utility core market volumes increased 5.1 bcf (15.1%) principally reflecting the effects of the colder 2018 three-month period weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 5.5 bcf principally reflecting the higher core market volumes and higher large firm delivery service volumes. These increases were partially offset by lower interruptible delivery service volumes. Electric Utility kilowatt-hour sales were 7.0% higher than the prior-year period principally reflecting the impact of the colder weather on Electric Utility heating-related sales.

UGI Utilities revenues increased $123.3 million reflecting a $120.1 million increase in Gas Utility revenues and higher Electric Utility revenues. The higher Gas Utility revenues principally reflect an increase in core market revenues ($73.2 million), higher off-system sales revenues ($40.9 million), and higher large firm delivery service revenues ($7.3 million). The $73.2 million increase in Gas Utility core market revenues reflects the effects of the higher core market throughput ($34.2 million), higher average retail core market PGC rates ($32.1 million) and the increase in PNG base rates effective October 20, 2017 ($6.9 million). The increase in Electric Utility revenues principally reflects the higher distribution system sales and slightly higher average DS rates ($3.3 million). UGI Utilities cost of sales was $257.3 million in the three months ended March 31, 2018 compared with $164.5 million in the three months ended March 31, 2017, principally reflecting higher Gas Utility cost of sales ($90.2 million) and higher Electric Utility cost of sales ($2.6 million) from higher distribution system sales and the slightly higher DS rates. The higher Gas Utility cost of sales reflects higher average retail core market PGC rates ($32.1 million), higher cost of sales associated with Gas Utility off-system sales ($40.9 million), and higher retail core-market volumes ($18.1 million).

UGI Utilities total margin increased $30.4 million principally reflecting higher total margin from Gas Utility core market customers ($26.0 million) and higher large firm delivery service total margin ($4.1 million). The increase in Gas Utility core market margin principally reflects the higher core market throughput ($19.8 million) and the increase in PNG base rates effective October 20, 2017 ($6.2 million). Electric Utility total margin increased slightly principally reflecting the higher distribution volumes sold.

UGI Utilities operating income increased $18.7 million, principally reflecting the increase in total margin ($30.4 million) partially offset by higher Gas Utility and Electric Utility operating and administrative expenses ($8.1 million) and greater depreciation and amortization expense ($3.4 million) associated with increased distribution system and information technology (“IT”) capital expenditure activity. The increase in UGI Utilities operating and administrative expenses principally reflects higher uncollectible accounts expense ($6.0 million) and higher compensation and benefits expenses ($3.6 million). UGI Utilities income before income taxes increased $17.9 million reflecting the increase in UGI Utilities operating income ($18.7 million) partially offset by slightly higher interest expense.

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Interest Expense and Income Taxes

Our consolidated interest expense during the 2018 three-month period was $58.1 million, $2.3 million higher than the $55.8 million of interest expense recorded during the 2017 three-month period. The higher interest expense principally reflects the effects of higher long-term debt outstanding 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 March 31, 2018, 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 2018 three-month period includes the effects of the lower U.S. federal income tax rate of 24.5% in the 2018 three-month period compared with 35% in the prior-year period partially offset by the slightly higher Fiscal 2018 income tax rate in France. These changes from the TCJA and the December 2017 French Finance Bills decreased current-period income taxes and increased current-period net income attributable to UGI by $32.9 million, or $0.19 per diluted share, during the three months ended March 31, 2018.

On March 15, 2018, the PUC entered a temporary rates Order that converted commission-approved rates of most large Pennsylvania public utilities, including Gas Utility, into “temporary rates” for a period of six months, with a possible extension for an additional six months. This action was taken in response to the TCJA that became effective on January 1, 2018. This action by the PUC did not directly impact our estimated annual effective tax rate for Fiscal 2018 and did not have a material impact on our results for the three months ended March 31, 2018. For further information on the TCJA and related regulatory actions, see Note 5 to condensed consolidated financial statements.

The effective income tax rate in the 2017 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.

2018 Six-Month Period Compared to the 2017 Six-Month Period

AmeriGas Propane



For the six months ended March 31,	2018			2017			Increase
(Dollars in millions)
Revenues	$	1,827.6		$	1,540.8		$	286.8	18.6	%
Total margin (a)	$	977.8		$	924.3		$	53.5	5.8	%
Partnership operating and administrative expenses	$	481.8		$	466.8		$	15.0	3.2	%
Partnership Adjusted EBITDA (b)(c)	$	503.6		$	456.3		$	47.3	10.4	%
Operating income (c) (d)	$	414.5		$	369.2		$	45.3	12.3	%
Retail gallons sold (millions)	703.5			668.4			$	35.1	5.3	%
Heating degree days—% (warmer) than normal (e)	(0.9		)%	(11.7		)%	—		—


(a)	Total margin represents total revenues less total cost of sales. Total margin for the six months ended March 31, 2018 and 2017 excludes net pre-tax losses of $30.4 million and $2.9 million, respectively, on 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 six months ended March 31, 2017, 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 NOAA for 344 Geo Regions in the United States, excluding Alaska and Hawaii.

AmeriGas Propane’s retail gallons sold during the 2018 six-month period were 5.3% higher than in the prior-year period. Average temperatures based upon heating degree days during the 2018 six-month period were 0.9% warmer than normal but 12.3% colder than the prior-year period.

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AmeriGas Propane retail propane revenues increased $263.8 million during the 2018 six-month period reflecting the effects of higher average retail selling prices ($191.6 million) and higher retail volumes sold ($72.2 million). Wholesale propane revenues increased $15.6 million reflecting the effects of higher average wholesale selling prices ($9.4 million) and higher wholesale volumes sold ($6.2 million). Average daily wholesale propane commodity prices during the 2018 six-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 39% higher than such prices during the 2017 six-month period. Other revenues in the 2018 six-month period were slightly higher than in the prior-year period principally reflecting higher fee income on the incremental retail volumes sold. AmeriGas Propane total cost of sales increased $233.3 million principally reflecting the effects of higher average propane product costs ($195.8 million) and, to a much lesser extent, the effects of the higher retail and wholesale propane volumes sold ($35.1 million).

AmeriGas Propane total margin increased $53.5 million in the 2018 six-month period principally reflecting slightly higher retail propane total margin ($48.4 million) and slightly higher non-propane total margin ($5.0 million). The increase in retail propane total margin reflects the higher retail volumes sold and, to a much lesser extent, slightly higher average retail propane unit margins.

Partnership Adjusted EBITDA increased $47.3 million in the 2018 six-month period principally reflecting the effects of the higher total margin ( $53.5 million ) and higher other operating income ($9.2 million) partially offset by higher Partnership operating and administrative expenses ($15.0 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 reflects, among other things, higher total compensation costs ($10.8 million) principally higher labor and incentive compensation costs associated with the increased activity and improved performance, higher vehicle expenses ($5.2 million) and, to a lesser extent, slightly higher bad debt expense partially offset by lower general insurance and self-insured casualty and liability expense.

AmeriGas Propane operating income increased $45.3 million in the 2018 six-month period principally reflecting the $47.2 million increase in Partnership Adjusted EBITDA partially offset by a $3.0 million increase in depreciation and amortization expense.

During the 2017 six-month period, AmeriGas Partners recognized a pre-tax loss of $55.3 million associated with early repayments of $878.3 million principal amount of AmeriGas Partners’ 7.00% Senior Notes comprising early redemption premiums and the write-off of unamortized debt issuance costs.

UGI International



For the six months ended March 31,	2018			2017			Increase (Decrease)
(Dollars in millions)
Revenues	$	1,693.8		$	1,159.8		$	534.0		46.0	%
Total margin (a)	$	667.9		$	588.7		$	79.2		13.5	%
Operating and administrative expenses (b)	$	373.4		$	325.2		$	48.2		14.8	%
Operating income (b)	$	224.9		$	209.9		$	15.0		7.1	%
Income before income taxes (b) (c)	$	200.1		$	200.2		$	(0.1	)	—	%
LPG retail gallons sold (millions)	541.7			507.3			$	34.4		6.8	%
UGI International degree days—% colder than normal (d)	1.0		%	0.5		%	—			—


(a)	Total margin represents total revenues less total cost of sales. Total margin for the six months ended March 31, 2018 and 2017 excludes net pre-tax losses of $3.6 million and $1.5 million, respectively, on commodity derivative instruments not associated with current-period transactions.


(b)	Reflects impacts of Finagaz integration expenses for the six months ended March 31, 2018 and 2017, of $13.2 million and $14.8 million, respectively.


(c)	Income before income taxes for the six months ended March 31, 2018 and 2017 excludes net pre-tax unrealized losses on certain foreign currency derivative contracts of $2.1 million and $0.1 million, respectively.


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

Average temperatures during the 2018 six-month period were approximately 1.0% colder than normal and approximately equal to the prior-year period. Total retail gallons sold during the 2018 six-month period were higher than the prior-year period principally reflecting retail LPG gallons sold as a result of our October 2017 acquisition of UniverGas partially offset by lower crop-drying volumes earlier in the 2018 six-month period.

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UGI International base-currency results are translated into U.S. dollars 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 2018 and 2017 six-month periods, the average unweighted euro-to-dollar translation rates were approximately $1.20 and $1.07, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.36 and $1.25, respectively. Although the euro and British pound sterling were stronger during the 2018 six-month period and impact the comparison of line item amounts presented in the table above, the effects of these stronger currencies did not have a significant impact on UGI International net income due to gains and losses on foreign currency exchange contracts.

UGI International revenues increased $534.0 million during the 2018 six-month period reflecting approximately $272.4 million of combined incremental revenues from UniverGas and DVEP, the translation effects on legacy business revenues of the stronger euro and British pound sterling, and higher LPG selling prices resulting from the higher LPG product costs. During the 2018 six-month period, average unweighted wholesale commodity prices for propane and butane in northwest Europe were approximately 15% and 4% higher than in the prior-year period, respectively. UGI International cost of sales increased $454.8 million during the 2018 six-month period reflecting approximately $234.0 million of incremental cost of sales associated with UniverGas and DVEP, the effects on cost of sales from the higher average LPG commodity costs, and the translation effects of the stronger euro and British pound sterling.

UGI International total margin increased $79.2 million primarily reflecting the translation effects of the stronger euro and British pound sterling and approximately $38.4 million of incremental margin from UniverGas and DVEP. These increases in margin were reduced by the effects on legacy business total margin of slightly lower average LPG retail bulk unit margins, slightly lower legacy business LPG retail volumes sold and lower retail natural gas total margin the result of lower average unit margins.

The $15.0 million increase in UGI International operating income principally reflects the previously mentioned $79.2 million increase in total margin partially offset by a $48.2 million increase in operating and administrative costs, an $11.6 million increase in depreciation and amortization expense and lower other operating income. 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 $20.7 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 tank and cylinder repairs and maintenance. Operating and administrative costs in the 2018 and 2017 six-month periods include $13.2 million and $14.8 million of Finagaz integration costs, respectively. The increase in depreciation and amortization reflects the translation effects of the stronger currencies, incremental amounts associated with UniverGas and DVEP ($5.0 million), and the impact of changes in estimated book lives of certain tanks and cylinders. UGI International income before income taxes decreased $0.1 million principally reflecting the previously mentioned $15.0 million increase in UGI International operating income reduced by higher realized losses on foreign currency exchange contracts ($13.9 million) and slightly higher interest expense ($1.2 million) principally due to the stronger euro.

Midstream & Marketing



For the six months ended March 31,	2018		2017		Increase
(Dollars in millions)
Revenues	$	893.2	$	693.5	$	199.7	28.8	%
Total margin (a)	$	235.6	$	191.9	$	43.7	22.8	%
Operating and administrative expenses	$	55.1	$	47.0	$	8.1	17.2	%
Operating income	$	159.8	$	131.8	$	28.0	21.2	%
Income before income taxes	$	160.2	$	132.9	$	27.3	20.5	%


(a)	Total margin represents total revenues less total cost of sales. Total margin for the six months ended March 31, 2018 and 2017 excludes net pre-tax (losses) gains of $(5.4) million and $86.1 million, respectively, on commodity derivative instruments not associated with current-period transactions.

Temperatures across Midstream & Marketing’s energy marketing territory were approximately 1.6% warmer than normal but 10.9% colder than in the prior-year period. Midstream & Marketing 2018 six-month period revenues were $199.7 million higher reflecting higher natural gas ($146.2 million) and retail power marketing ($7.5 million) revenues; higher revenues from midstream assets ($36.9 million) principally higher natural gas gathering, peak shaving, and capacity management revenues; and higher electric generation revenues ($11.4 million). The increase in natural gas revenues principally reflects the effects of higher average natural gas prices and to a lesser extent higher natural gas volumes on colder 2018 six-month period temperatures and customer

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growth. The increase in capacity management and peaking revenues reflects the effects of colder weather in January and, with respect to peaking revenues, also an increase in the number of peaking contracts. The higher natural gas gathering revenues reflects incremental revenues from the Sunbury Pipeline and incremental revenues from the acquisition of a north-central Pennsylvania natural gas gathering system acquired October 31, 2017. Electric generation revenues reflect higher volumes generated principally from the Hunlock natural-gas fired generation station and higher average selling prices. Midstream & Marketing cost of sales were $657.6 million in the 2018 six-month period compared to $501.6 million in the 2017 six-month period, an increase of $156.0 million, principally reflecting higher natural gas and retail power cost of sales primarily a result of the higher natural gas volumes and higher average natural gas and retail power costs.

Midstream & Marketing total margin increased $43.7 million in the 2018 six-month period reflecting higher total margin from our midstream assets ($35.0 million), principally the result of higher natural gas gathering, capacity management and peaking total margin, and higher electricity generation total margin ($7.8 million). The higher natural gas gathering total margin reflects incremental margin from the Sunbury Pipeline and, to a much lesser extent, margin from the previously mentioned natural gas gathering assets acquired in October 2017. The increase in capacity management and peaking total margin reflects the effects of extremely cold weather in January and, with respect to peaking margin, also an increase in the number of peaking contracts. The higher electricity generation total margin reflects higher electric generation volumes principally at our Hunlock Station generating facility and higher electricity unit margins.

Midstream & Marketing operating income and income before income taxes during the 2018 six-month period increased $28.0 million and $27.3 million , respectively. The increase in operating income principally reflects the previously mentioned increase in total margin ( $43.7 million ) partially offset by higher operating and administrative expenses ( $8.1 million ), higher depreciation expense ($4.1 million), and a $4.2 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 $8.1 million increase in operating and administrative expenses reflects higher compensation and benefits expense and higher expenses associated with greater peaking, LNG and gas gathering activities, while the increase in depreciation expense principally reflects incremental depreciation from the expansion of our natural gas pipeline, natural gas gathering, LNG and peaking assets. The increase in income before income taxes in the 2018 six-month period principally reflects the higher operating income partially offset by lower income from our PennEast pipeline equity investment reflecting lower AFUDC income and slightly higher interest expense.

UGI Utilities



For the six months ended March 31,	2018			2017			Increase
(Dollars in millions)
Revenues	$	806.4		$	621.4		$	185.0	29.8	%
Total margin (a)	$	394.7		$	344.9		$	49.8	14.4	%
Operating and administrative expenses (a)	$	122.8		$	112.3		$	10.5	9.3	%
Operating income	$	231.4		$	198.6		$	32.8	16.5	%
Income before income taxes	$	209.4		$	178.3		$	31.1	17.4	%
Gas Utility system throughput—billions of cubic feet (“bcf”)
Core market	64.4			56.7			7.7		13.6	%
Total	156.6			148.0			8.6		5.8	%
Electric Utility distribution sales - millions of kilowatt hours (“gwh”)	525.3			501.1			24.2		4.8	%
Gas Utility heating degree days—% (warmer) than normal (b)	(2.1		)%	(10.0		)%	—		—

(a)

Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e., Electric Utility gross receipts taxes, of $2.6 million and $2.5 million during the six months ended March 31, 2018 and 2017, respectively. For financial statement purposes, revenue-related taxes are included in “ Operating and administrative expenses ” on the Condensed Consolidated Statements of Income (but excluded from operating expenses presented above).


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

Temperatures in Gas Utility’s service territory during the six months ended March 31, 2018, were 2.1% warmer than normal but 8.8% colder than during the six months ended March 31, 2017. Gas Utility core market volumes increased 7.7 bcf (13.6%) principally reflecting the effects of the colder 2018 six-month period weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 8.6 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.

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Electric Utility kilowatt-hour sales were 4.8% higher than the prior-year period, principally reflecting the impact of the colder weather on Electric Utility heating-related sales.

UGI Utilities revenues increased $185.0 million reflecting a $182.9 million increase in Gas Utility revenues and slightly higher Electric Utility revenues. The higher Gas Utility revenues principally reflect an increase in core market revenues ($121.3 million), higher off-system sales revenues ($52.4 million), and higher large firm delivery service revenues ($11.6 million). The $121.3 million increase in Gas Utility core market revenues reflects the effects of the higher core market throughput ($53.0 million), higher average retail core market PGC rates ($57.5 million) and the increase in PNG base rates effective October 20, 2017 ($10.9 million). The increase in Electric Utility revenues principally reflects higher Electric Utility distribution system sales ($2.8 million) partially offset by lower transmission revenue ($0.5 million). UGI Utilities cost of sales was $409.1 million in the six months ended March 31, 2018 compared with $274.0 million in the six months ended March 31, 2017, principally reflecting higher Gas Utility cost of sales ($133.4 million) and higher Electric Utility cost of sales ($1.6 million) from the higher sales. The higher Gas Utility cost of sales reflects higher average retail core market PGC rates ($57.5 million), higher cost of sales associated with Gas Utility off-system sales ($52.4 million), and higher retail core-market volumes ($27.3 million).

UGI Utilities total margin increased $49.8 million principally reflecting higher total margin from Gas Utility core market customers ($42.3 million) and higher large firm delivery service total margin ($7.9 million). The increase in Gas Utility core market margin principally reflects the higher core market throughput ($32.6 million) and the increase in PNG base rates effective October 20, 2017 ($9.7 million). Electric Utility total margin increased $0.3 million principally reflecting the higher distribution system sales.

UGI Utilities operating income increased $32.8 million, principally reflecting the increase in total margin ($49.8 million) partially offset by higher operating and administrative expenses ($10.5 million) and greater depreciation and amortization expense ($6.4 million) associated with increased distribution system and IT capital expenditure activity. The increase in UGI Utilities operating and administrative expenses reflects higher uncollectible accounts expense ($7.0 million) and higher contractor and outside services expenses ($3.0 million) and higher compensation and benefits expenses ($3.6 million) partially offset by a favorable payroll tax adjustment related to prior periods ($2.1 million). UGI Utilities income before income taxes increased $31.1 million reflecting the increase in UGI Utilities operating income ($32.8 million) partially offset by slightly higher interest expense.

Interest Expense and Income Taxes

Our consolidated interest expense during the 2018 six-month period was $116.3 million, $5.1 million higher than the $111.2 million of interest expense recorded during the 2017 six-month period. The higher interest expense principally reflects the effects of higher long-term debt outstanding at AmeriGas Propane and UGI Utilities and the effects of the stronger euro on UGI International interest expense. 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 six months ended March 31, 2018, were 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 2018 six-month period includes the effects of the TCJA and the December 2017 French Finance Bills on income taxes and deferred tax valuation allowances which reduced income tax expense by $184.9 million.

On March 15, 2018, the PUC entered a temporary rates Order that converted commission-approved rates of most large Pennsylvania public utilities, including Gas Utility, into “temporary rates” for a period of six months, with a possible extension for an additional six months. This action was taken in response to the TCJA that became effective on January 1, 2018. This action by the PUC did not directly impact our estimated annual effective tax rate for Fiscal 2018 and did not have a material impact on our results for the six months ended March 31, 2018. For further information on the TCJA and related regulatory actions, see Note 5 to condensed consolidated financial statements.

The effective income tax rate in the 2017 six-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 described above, our effective income tax rate for the 2018 six-month period was lower than in the prior-year period principally reflecting the lower blended U.S. tax rate of 24.5% in the 2018 six-month period compared with 35% in the prior-year period partially offset by the slightly higher Fiscal 2018 income tax rate in France. These changes from the TCJA and the December 2017 French Finance Bills decreased income tax expense and increased current-period adjusted net income attributable to UGI by $49.5 million, or $0.28 per diluted share, for the six months ended March 31, 2018.

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FINANCIAL CONDITION AND LIQUIDITY

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 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 Facility borrowings; and the ability to obtain long-term financing to meet anticipated contractual and projected cash commitments. Issuances of debt and equity securities in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.

The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business units. Our cash and cash equivalents totaled $474.8 million at March 31, 2018 , compared with $558.4 million at September 30, 2017 . Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at March 31, 2018 and September 30, 2017 , UGI had $155.8 million and $291.1 million of cash and cash equivalents, respectively, most of which are located in the U.S. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.

Long-term Debt and Short-term Borrowings

Long-term Debt

The Company’s debt outstanding at March 31, 2018 and September 30, 2017 , comprises the following:



	March 31, 2018																	September 30, 2017
(Millions of dollars)	AmeriGas Propane			UGI International			Midstream & Marketing		UGI Utilities			Other			Total			Total
Short-term borrowings	$	154.5		$	3.3		$	10.0	$	135.0		$	—		$	302.8		$	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	—			843.8			—		163.4			—			1,007.2			902.1
Other long-term debt	26.8			22.6			0.5		—			9.2			59.1			59.8
Unamortized debt issuance costs	(29.4		)	(3.7		)	—		(4.3		)	(0.1		)	(37.5		)	(39.8		)
Total long-term debt	$	2,572.4		$	862.7		$	0.5	$	834.1		$	9.1		$	4,278.8		$	4,172.1
Total debt	$	2,726.9		$	866.0		$	10.5	$	969.1		$	9.1		$	4,581.6		$	4,539.0

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 (the “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. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement borrowings and for general corporate purposes. The outstanding principal amount of the Utilities Term Loan is payable in equal quarterly installments of $1.6 million , which commenced March 2018, with the balance of the principal being due and payable in full on October 30, 2022. 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.

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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 5 to the Consolidated Financial Statements in the Company’s 2017 Annual Report.

Information about the Company’s principal credit agreements (excluding the Energy Services Receivables Facility discussed below) as of March 31, 2018 and 2017 , is presented in the table below.



(Currency in millions)	Total Capacity		Borrowings Outstanding		Letters of Credit and Guarantees Outstanding		Available Borrowing Capacity
As of March 31, 2018
AmeriGas OLP	$	600.0	$	154.5	$	67.2	$	378.3
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	$	—	$	—	$	240.0
UGI Utilities	$	300.0	$	135.0	$	2.0	$	163.0
As of March 31, 2017
AmeriGas OLP	$	525.0	$	—	$	67.2	$	457.8
UGI France SAS	€	60.0	€	—	€	—	€	60.0
Flaga (a)	€	55.0	€	—	€	7.4	€	47.6
Energy Services, LLC	$	240.0	$	—	$	—	$	240.0
UGI Utilities	$	300.0	$	48.5	$	2.0	$	249.5


(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.

The average daily and peak short-term borrowings under the Company’s principal credit agreements during the six months ended March 31, 2018 and 2017 are as follows:



	For the six months ended March 31, 2018				For the six months ended March 31, 2017
(Currency in millions)	Average		Peak		Average		Peak
AmeriGas OLP	$	206.3	$	349.0	$	105.0	$	292.5
UGI International, LLC	€	—	€	—	€	—	€	—
UGI France SAS	€	—	€	—	€	—	€	—
Flaga	€	—	€	—	€	—	€	—
Energy Services, LLC	$	31.0	$	79.0	$	12.6	$	28.0
UGI Utilities	$	171.4	$	215.0	$	92.4	$	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% . For additional information regarding the AmeriGas Credit Agreement, see Note 9 to the condensed consolidated financial statements.

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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% . For additional information regarding the UGI International Credit Agreement, see Note 9 to the condensed consolidated financial statements.

Midstream & Marketing. Energy Services, LLC has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2018. At March 31, 2018 , the outstanding balance of ESFC trade receivables was $99.6 million , of which $10.0 million was sold to the bank. At March 31, 2017 , the outstanding balance of ESFC trade receivables was $85.3 million and there were no amounts sold to the bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. During the six months ended March 31, 2018 and 2017 , peak sales of receivables were $68.0 million and $49.0 million , respectively, and average daily amounts sold were $22.2 million and $15.7 million , respectively. For additional information regarding the Receivables Facility, see Note 8 to the condensed consolidated financial statements.

Dividends and Distributions

On April 24, 2018, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.26 per Common Share, or $1.04 on an annual basis. The new dividend rate reflects a 4% increase from the previous quarterly rate of $0.25. The new quarterly dividend rate is effective with the dividend payable on July 1, 2018, to shareholders of record on June 15, 2018.

On April 23, 2018, the General Partner’s Board of Directors approved a quarterly distribution on AmeriGas Partners Common Units of $0.95 per Common Unit, equal to an annual rate of $3.80 per Common Unit. The distribution is payable on May 18, 2018, to unitholders of record on May 10, 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, UGI’s 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 expiring in January 2022.

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. Cash flow provided by operating activities was $ 579.4 million in the 2018 six -month period compared to $ 585.0 million in the 2017 six -month period. Cash flow from operating activities before changes in operating working capital was $ 949.2 million in the 2018 six -month period compared to $862.5 million in the prior-year period. The higher cash flow from operating activities before changes in operating working capital reflects the 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 in the 2018 six-month period ($184.9 million) and in the 2017 six-month period ($27.4 million); the non-cash effects of changes in unrealized gains and losses on derivative instruments in both periods; and the loss on extinguishments of debt at AmeriGas Partners in the 2017 six-month period ($55.3 million), the cash flow effects of which are reflected in cash flows from financing activities). Cash used to fund changes in operating working capital totaled $ 369.8 million in the 2018 six -month period compared to $277.5 million in the prior-year period. Higher cash required to fund changes in accounts receivable was partially offset by higher cash from changes in other current liabilities including accrued income taxes, higher cash from changes in inventories and higher overcollections of deferred fuel costs at UGI Utilities. The higher cash needed to fund changes in accounts receivable reflects, in large part, the impact of higher volumes sold and higher LPG and natural gas costs.

Investing Activities. Cash flow used by investing activities was $ 431.7 million in the 2018 six -month period compared with $ 338.1 million in the prior-year period. Investing activity cash flow is principally affected by expenditures for property, plant and equipment; cash paid for acquisitions of businesses; changes in restricted cash balances; investments in investees; and proceeds from sales of assets and businesses. Cash payments for property, plant and equipment were $266.1 million in the 2018 six -month period compared to $341.8 million in the prior-year period. Cash payments in the prior-year included capital expenditures associated

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with the Sunbury Pipeline project at Midstream & Marketing. Cash used for acquisitions of businesses and assets in the 2018 six-month period principally reflects UGI International’s acquisition of UniverGas and Midstream & Marketing’s acquisition of a natural gas gathering system in northern Pennsylvania.

Financing Activities. Cash flow used by financing activities was $ 240.2 million in the 2018 six -month period compared with $ 95.9 million in the prior-year period. Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; net short-term borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units; and, from time to time, issuances of UGI and AmeriGas Partners equity instruments. In October 2017, UGI Utilities issued $125 million of unsecured notes and used the proceeds principally to reduce short-term borrowings and for general corporate purposes. During the 2018 six-month period, UGI Utilities repaid $40 million of maturing Medium-Term Notes.

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 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.

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.

IMPACT OF TAX REFORM

U.S. Tax Reform

As a result, in December 2017, we reduced our net deferred income tax liabilities due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of enactment. We adjusted these original provisional amounts during the three months ended March 31, 2018. Because part of the reduction to our net deferred income taxes relates to UGI Utilities’ regulated utility plant, most of the reduction in UGI Utilities’ deferred income taxes is not being recognized immediately in income tax expense and UGI Utilities has recorded a regulatory liability associated with excess deferred federal income taxes related to its regulated utility plant assets (see Note 7 to condensed consolidated financial statements).

For the three months ended March 31, 2018, net income attributable to UGI Corporation includes changes to provisional adjustments initially recorded in December 2017 as a result of the enactment of the TCJA which changes decreased income taxes and increased net income attributable to UGI by $5.3 million. In addition to these changes to the one-time provisional adjustments initially recorded in December 2017, net income attributable to UGI for the three months ended March 31, 2018, also reflects the current-period beneficial impacts of the TCJA, principally the effects of the lower blended federal income tax rate in Fiscal 2018 of 24.5%, of approximately $34.0 million.

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For the six months ended March 31, 2018, net income attributable to UGI includes income from provisional adjustments to tax-related accounts as a result of the enactment of the TCJA which decreased income taxes and increased net income attributable to UGI by $171.3 million. In addition to these one-time provisional adjustments resulting from the TCJA, net income attributable to UGI for the six months ended March 31, 2018, also reflects the current-period beneficial impacts of the TCJA, principally the effects of the lower blended federal income tax rate of 24.5% in Fiscal 2018, of approximately $54.5 million.

For a more detailed description of the impacts of the TCJA, see Note 5 to condensed consolidated financial statements.

Changes in French Corporate Income Tax Rates

In December 2017, the French Parliament approved 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% . 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).

For the three months ended March 31, 2018, net income attributable to UGI Corporation includes changes to provisional adjustments initially recorded in December 2017 as a result of the December 2017 French Finance Bills which increased income taxes and decreased net income attributable to UGI by $3.7 million. In addition to these changes to the provisional one-time adjustments from the December 2017 French Finance Bills, net income attributable to UGI for the three months ended March 31, 2018 also reflects the current-period negative impact of the December 2017 French Finance Bills, principally due to the higher French income tax rate in Fiscal 2018 of 39.4%, of approximately $1.1 million.

For the six months ended March 31, 2018, net income attributable to UGI Corporation includes the beneficial impact of adjustments to net deferred income tax liabilities associated with the enactment of the December 2017 French Finance Bills which decreased income taxes and increased net income attributable to UGI by $13.6 million. In addition to these one-time provisional adjustments from the December 2017 French Finance Bills, net income attributable to UGI for the six months ended March 31, 2018, also reflects the current-period negative impact of the December 2017 French Finance Bills, principally due to the higher French income tax rate in Fiscal 2018 of 39.4%, of approximately $5.0 million.

For a more detailed description of the impacts of the December 2017 French Finance Bills, see Note 5 to condensed consolidated financial statements.

UTILITY REGULATORY MATTERS

Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PUC to increase its annual base distribution revenues by $9.2 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. The PUC entered an Order dated March 1, 2018, suspending the effective date for the rate increase to allow for investigation and public hearings. Unless a settlement is reached sooner, this review process is expected to last up to nine months from the date of filing; however, 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 million annual base distribution rate increase for PNG. The increase became effective on October 20, 2017.

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

EVALUATION OF AMERIGAS PARTNERS TRADENAMES AND TRADEMARKS

In April 2018, a plan to discontinue the use of these tradenames and trademarks was presented to the Partnership’s senior management. After considering the merits of the plan, the Partnership’s senior management approved, and the General Partner’s Board of Directors endorsed, a plan to discontinue the use of these tradenames and trademarks which is expected to occur over a period of approximately four years. As a result, during the three months ending June 30, 2018, the Partnership will adjust the carrying amounts of these tradenames and trademarks to their fair values and will reclassify the remaining fair value of these tradenames and trademarks from indefinite-lived intangible assets to definite-lived intangible assets having a remaining estimated period of benefit of approximately four years. The Partnership estimates that it will record a pre-tax non-cash impairment charge of approximately $70 million which will decrease net income attributable to UGI by approximately $13 million .

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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 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 customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. 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 Gas Utility's PGC recovery mechanism. At March 31, 2018 , the fair values of Gas Utility’s natural gas futures and option contracts were not material.

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 March 31, 2018 , all of Electric Utility’s forward electricity purchase contracts were subject to the NPNS exception. At March 31, 2018 , 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 contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX, ICE and over-the-counter natural gas and electricity futures 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 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 March 31, 2018 (excluding those Gas Utility and Electric Utility commodity derivative instruments that are refundable to, or recoverable from, customers) was a gain of $28.5 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 $64.4 million at March 31, 2018 .

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 March 31, 2018 , includes short-term borrowings and UGI France SAS’s, Flaga’s and UGI Utilities’ variable-rate term loans. 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 pay-fixed, receive-variable interest rate swaps, have fixed the underlying euribor interest rates on their euro-denominated term loans through all, or a substantial portion of, the periods such debt is outstanding. In addition, Flaga’s U.S. dollar-denominated loan has been swapped from a floating-rate U.S. dollar-denominated interest rate to a fixed-rate euro-denominated interest rate through a cross-currency swap, removing interest rate risk (and foreign currency exchange risk as further described below under Foreign Currency Exchange Rate Risk) associated with the underlying interest payments. At March 31, 2018 , combined borrowings outstanding under variable-rate debt agreements, excluding UGI France SAS’s and Flaga’s effectively fixed-rate debt, totaled $426.2 million .

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 March 31, 2018 (including pay-fixed, receive-variable interest rate swaps) was a loss of $1.9 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 $1.6 million .

Foreign Currency Exchange Rate Risk

Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro and, to a lesser extent, the U.S. dollar versus the British pound sterling. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. 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 would reduce their aggregate net book value at March 31, 2018 , by approximately $145.0 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 (“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 March 31, 2018 , there were no unsettled net investment hedges outstanding.

In addition, in order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March.

As previously mentioned, Flaga has a cross-currency swap to hedge its exposure to the variability 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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The fair value of unsettled foreign currency exchange rate risk sensitive derivative instruments held at March 31, 2018 , including the fair value of Flaga’s cross-currency swap, was a loss of $31.8 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 $58.0 million .

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 March 31, 2018 , restricted cash in brokerage accounts totaled $10.6 million . Although we have concentrations of credit risk associated with derivative instruments, 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 March 31, 2018 . Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At March 31, 2018 , if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

ITEM 4. 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

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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PART II OTHER INFORMATION

ITEM 1A. RISK FACTORS

In addition to the information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 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 in our 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.

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 March 31, 2018 .



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 (1)
January 1, 2018 to January 31, 2018	97,500	$47.26	97,500	8.00 million
February 1, 2018 to February 28, 2018	—	—	—	8.00 million
March 1, 2018 to March 31, 2018	—	—	—	8.00 million
Total	97,500		97,500

(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. The quarterly repurchase noted above that was transacted in January 2018 was the last repurchase under this plan. 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 expiring in January 2022. All future repurchases will be made under the plan approved in January 2018.

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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 UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI, Utilities and AmeriGas Employees, dated January 1, 2018.

10.2	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI and Utilities Employees, dated January 1, 2018.

10.3	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Stock Unit Grant Letter for Non Employee Directors, dated January 25, 2018.

10.4	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 25, 2018.

10.5	Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Phantom Unit Grant Letter for Non Employee Directors, dated January 24, 2018.

10.6	Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Performance Unit Grant Letter for Employees dated January 1, 2018.

10.7	AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective January 1, 2018 - Terms and Conditions.

31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2018, 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 March 31, 2018, 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 March 31, 2018, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS	XBRL Instance

101.SCH	XBRL Taxonomy Extension Schema

101.CAL	XBRL Taxonomy Extension Calculation Linkbase

101.DEF	XBRL Taxonomy Extension Definition Linkbase

101.LAB	XBRL Taxonomy Extension Labels Linkbase

101.PRE	XBRL Taxonomy Extension Presentation Linkbase

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EXHIBIT INDEX





10.1		Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI, Utilities and AmeriGas Employees, dated January 1, 2018.

10.2		Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI and Utilities Employees, dated January 1, 2018.

10.3		Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Stock Unit Grant Letter for Non Employee Directors, dated January 25, 2018.

10.4		Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 25, 2018.

10.5		Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Phantom Unit Grant Letter for Non Employee Directors, dated January 24, 2018.

10.6		Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Performance Unit Grant Letter for Employees dated January 1, 2018.

10.7		AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective January 1, 2018 - Terms and Conditions.

31.1		Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2018, 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 March 31, 2018, 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 March 31, 2018, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		XBRL Instance

101.SCH		XBRL Taxonomy Extension Schema

101.CAL		XBRL Taxonomy Extension Calculation Linkbase

101.DEF		XBRL Taxonomy Extension Definition Linkbase

101.LAB		XBRL Taxonomy Extension Labels Linkbase

101.PRE		XBRL Taxonomy Extension Presentation Linkbase

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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:	May 8, 2018	By:	/s/ Kirk R. Oliver
			Kirk R. Oliver
			Chief Financial Officer


Date:	May 8, 2018	By:	/s/ Ann P. Kelly
			Ann P. Kelly
			Vice President, Chief Accounting Officer
			and Corporate Controller

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Part I Financial Information Item 1. Financial Statements Note 1 Nature Of Operations Note 2 Summary Of Significant Accounting Policies Note 3 Accounting Changes Note 4 Inventories Note 5 Income Tax Reform Note 6 Goodwill and Intangible Assets Note 7 Utility Regulatory Assets and Liabilities and Regulatory Matters Note 8 Energy Services Accounts Receivable Securitization Facility Note 9 Debt Note 10 Commitments and Contingencies Note 11 Defined Benefit Pension and Other Postretirement Plans Note 12 Fair Value Measurements Note 13 Derivative Instruments and Hedging Activities Note 14 Accumulated Other Comprehensive Income Note 15 Segment Information Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 6. Exhibits

Exhibits

10.1 Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI, Utilities and AmeriGas Employees, dated January 1, 2018. 10.2 Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI and Utilities Employees, dated January 1, 2018. 10.3 Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Stock Unit Grant Letter for Non Employee Directors, dated January 25, 2018. 10.4 Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 25, 2018. 10.5 Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Phantom Unit Grant Letter for Non Employee Directors, dated January 24, 2018. 10.6 Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Performance Unit Grant Letter for Employees dated January 1, 2018. 10.7 AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective January 1, 2018 - Terms and Conditions. 31.1 Certification by the Chief Executive Officer relating to the Registrants Report on Form 10-Q for the quarter ended March 31, 2018, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification by the Chief Financial Officer relating to the Registrants Report on Form 10-Q for the quarter ended March 31, 2018, 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 Registrants Report on Form 10-Q for the quarter ended March 31, 2018, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 10.1 Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI, Utilities and AmeriGas Employees, dated January 1, 2018. 10.2 Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI and Utilities Employees, dated January 1, 2018. 10.3 Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Stock Unit Grant Letter for Non Employee Directors, dated January 25, 2018. 10.4 Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 25, 2018. 10.5 Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Phantom Unit Grant Letter for Non Employee Directors, dated January 24, 2018. 10.6 Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Performance Unit Grant Letter for Employees dated January 1, 2018. 10.7 AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective January 1, 2018 - Terms and Conditions. 31.1 Certification by the Chief Executive Officer relating to the Registrants Report on Form 10-Q for the quarter ended March 31, 2018, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification by the Chief Financial Officer relating to the Registrants Report on Form 10-Q for the quarter ended March 31, 2018, 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 Registrants Report on Form 10-Q for the quarter ended March 31, 2018, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

UGI 10-Q Quarter ended March 31, 2018

Exhibits