Edgar Filing: UGI CORP /PA/

Document

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 December 31, 2017



¨	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 January 31, 2018, there were 173,014,311 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 December 31, 2017, September 30, 2017 and December 31, 2016	1

Condensed Consolidated Statements of Income for the three months ended December 31, 2017 and 2016	2

Condensed Consolidated Statements of Comprehensive Income for the three months ended December 31, 2017 and 2016	3

Condensed Consolidated Statements of Cash Flows for the three months ended December 31, 2017 and 2016	4

Condensed Consolidated Statements of Changes in Equity for the three months ended December 31, 2017 and 2016	5

Notes to Condensed Consolidated Financial Statements	6

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk	46

Item 4. Controls and Procedures	48

Part II Other Information

Item 1A. Risk Factors	49

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	49

Item 6. Exhibits	50

Signatures	52

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UGI CORPORATION AND SUBSIDIARIES

PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Millions of dollars)



	December 31, 2017			September 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	446.4		$	558.4		$	515.2
Restricted cash	19.8			10.3			7.9
Accounts receivable (less allowances for doubtful accounts of $35.1, $26.9 and $29.2, respectively)	1,101.8			626.8			917.3
Accrued utility revenues	95.9			13.3			55.6
Inventories	307.3			278.6			228.2
Utility regulatory assets	0.6			8.3			1.6
Derivative instruments	73.4			63.1			87.0
Prepaid expenses and other current assets	135.4			138.7			97.1
Total current assets	2,180.6			1,697.5			1,909.9
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $3,393.1, $3,312.9 and $3,139.8, respectively)	5,690.5			5,537.0			5,244.3
Goodwill	3,185.5			3,107.2			2,935.8
Intangible assets, net	641.9			611.7			558.9
Utility regulatory assets	362.2			360.6			391.3
Derivative instruments	13.3			9.2			24.2
Other assets	269.9			259.0			236.1
Total assets	$	12,343.9		$	11,582.2		$	11,300.5
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	224.1		$	177.5		$	48.5
Short-term borrowings	586.1			366.9			234.4
Accounts payable	680.8			439.6			573.6
Derivative instruments	32.7			25.0			16.2
Other current liabilities	692.3			681.1			702.2
Total current liabilities	2,216.0			1,690.1			1,574.9
Long-term debt	4,056.4			3,994.6			3,994.2
Deferred income taxes	890.7			1,357.0			1,204.7
Deferred investment tax credits	2.9			3.0			3.2
Derivative instruments	22.2			21.8			16.6
Other noncurrent liabilities	1,073.6			774.8			773.8
Total liabilities	8,261.8			7,841.3			7,567.4
Commitments and contingencies (Note 10)
Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 173,997,441, 173,987,691 and 173,903,191 shares, respectively)	1,189.3			1,188.6			1,203.4
Retained earnings	2,429.3			2,106.7			2,035.4
Accumulated other comprehensive loss	(71.5		)	(93.4		)	(216.8		)
Treasury stock, at cost	(45.4		)	(38.6		)	(34.3		)
Total UGI Corporation stockholders’ equity	3,501.7			3,163.3			2,987.7
Noncontrolling interests, principally in AmeriGas Partners	580.4			577.6			745.4
Total equity	4,082.1			3,740.9			3,733.1
Total liabilities and equity	$	12,343.9		$	11,582.2		$	11,300.5

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Millions of dollars, except per share amounts)



	Three Months Ended December 31,
	2017			2016
Revenues	$	2,125.2		$	1,679.5
Costs and expenses:
Cost of sales (excluding depreciation shown below)	1,137.4			647.4
Operating and administrative expenses	490.1			468.5
Depreciation	95.5			83.7
Amortization	14.8			14.4
Other operating income, net	(4.4		)	(0.7		)
	1,733.4			1,213.3
Operating income	391.8			466.2
Income (loss) from equity investees	1.0			(0.2		)
Loss on extinguishments of debt	—			(33.2		)
(Losses) gains on foreign currency contracts, net	(4.8		)	1.3
Interest expense	(58.2		)	(55.4		)
Income before income taxes	329.8			378.7
Income tax benefit (expense)	104.4			(87.8		)
Net income including noncontrolling interests	434.2			290.9
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners	(68.3		)	(60.2		)
Net income attributable to UGI Corporation	$	365.9		$	230.7
Earnings per common share attributable to UGI Corporation stockholders
Basic	$	2.11		$	1.33
Diluted	$	2.07		$	1.30
Weighted average common shares outstanding (thousands)
Basic	173,670			173,512
Diluted	176,948			176,984
Dividends declared per common share	$	0.2500		$	0.2375

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Millions of dollars)



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

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)



	Three Months Ended December 31,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income including noncontrolling interests	$	434.2		$	290.9
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization	110.3			98.1
Deferred income taxes	(173.9		)	(5.9		)
Provision for uncollectible accounts	9.3			6.7
Change in unrealized losses (gains) on derivative instruments	(6.6		)	(104.2		)
Loss on extinguishments of debt	—			33.2
Other, net	11.3			15.1
Net change in:
Accounts receivable and accrued utility revenues	(530.5		)	(437.0		)
Inventories	(23.5		)	(22.4		)
Utility deferred fuel and power costs, net of changes in unsettled derivatives	11.6			(1.0		)
Accounts payable	235.0			221.4
Other current assets	(34.0		)	(7.3		)
Other current liabilities	(11.8		)	39.0
Net cash provided by operating activities	31.4			126.6
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(147.5		)	(197.1		)
Acquisitions of businesses and assets, net of cash acquired	(175.8		)	(0.8		)
Decrease in restricted cash	(9.5		)	7.7
Other, net	5.3			(2.2		)
Net cash used by investing activities	(327.5		)	(192.4		)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(43.3		)	(41.2		)
Distributions on AmeriGas Partners publicly held Common Units	(65.7		)	(65.0		)
Issuances of debt, net of issuance costs	124.3			789.6
Repayments of debt, including redemption premiums	(41.9		)	(530.9		)
Increase (decrease) in short-term borrowings	212.5			(66.7		)
Receivables Facility net borrowings	6.0			9.5
Issuances of UGI Common Stock	1.4			3.3
Repurchases of UGI Common Stock	(9.5		)	—
Other	(2.7		)	—
Net cash provided by financing activities	181.1			98.6
EFFECT OF EXCHANGE RATE CHANGES ON CASH	3.0			(20.4		)
Cash and cash equivalents (decrease) increase	$	(112.0	)	$	12.4
CASH AND CASH EQUIVALENTS
End of period	$	446.4		$	515.2
Beginning of period	558.4			502.8
(Decrease) increase	$	(112.0	)	$	12.4

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)



	Three Months Ended December 31,
	2017			2016
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	(1.3		)	(1.2		)
Equity-based compensation expense	2.0			1.6
Gain on sale of treasury stock	—			1.4
Balance, end of period	$	1,189.3		$	1,203.4
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
Net income attributable to UGI Corporation	365.9			230.7
Cash dividends on Common Stock	(43.3		)	(41.2		)
Balance, end of period	$	2,429.3		$	2,035.4
Accumulated other comprehensive income (loss)
Balance, beginning of period	$	(93.4	)	$	(154.7	)
Net (losses) gains on derivative instruments	(0.4		)	12.3
Reclassification of net gains on derivative instruments	(0.4		)	(4.5		)
Benefit plans	0.4			1.0
Foreign currency adjustments	22.3			(70.9		)
Balance, end of period	$	(71.5	)	$	(216.8	)
Treasury stock
Balance, beginning of period	$	(38.6	)	$	(36.9	)
Common stock issued in connection with employee and director plans, net of tax withheld	2.7			2.8
Repurchases of Common Stock	(9.5		)	—
Reacquired common stock — employee and director plans	—			(0.4		)
Sale of treasury stock	—			0.2
Balance, end of period	$	(45.4	)	$	(34.3	)
Total UGI Corporation stockholders’ equity	$	3,501.7		$	2,987.7
Noncontrolling interests
Balance, beginning of period	$	577.6		$	750.9
Net income attributable to noncontrolling interests, principally in AmeriGas Partners	68.3			60.2
Dividends and distributions	(65.7		)	(65.0		)
Other	0.2			(0.7		)
Balance, end of period	$	580.4		$	745.4
Total equity	$	4,082.1		$	3,733.1

See accompanying notes to condensed consolidated financial statements.

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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 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 December 31, 2017, 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 three months ended December 31, 2017 and 2016 were $11.3 and $10.4, 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. 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 stockholders 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 December 31,
	2017	2016
Denominator (thousands of shares):
Weighted-average common shares outstanding — basic	173,670	173,512
Incremental shares issuable for stock options and awards (a)	3,278	3,472
Weighted-average common shares outstanding — diluted	176,948	176,984


(a)	For the three months ended December 31, 2017, there were 146 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 months ended December 31, 2016, 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 and from time to time we also enter into net investment 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. 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. 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.

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

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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.

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 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

Derivatives and Hedging. In August 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("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 operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.

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 this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. 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.

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

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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 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 currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.

Note 4 — Inventories

Inventories comprise the following:



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

At December 31, 2017, UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) which have terms of up to three years. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Note 5 — Income Tax Reform

U.S. Tax Reform

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

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

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

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


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


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


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

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

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

Changes in French Corporate Income Tax Rates

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

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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)

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

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

Note 6 — Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following:



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

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

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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:



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


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


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

Deferred fuel and power refunds. Gas Utility’s 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 (losses) gains on such contracts at December 31, 2017, September 30, 2017 and December 31, 2016 were $(1.7), $0.1 and $6.9, respectively.

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

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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

Other Regulatory Matters

Base Rate Filings. 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, although the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. This review process is expected to last up to nine months; 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.

Note 8 — Energy Services Accounts Receivable Securitization Facility

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

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Information regarding the trade receivables transferred to ESFC and the amounts sold to the bank for the three months ended December 31, 2017 and 2016, as well as the balance of ESFC trade receivables at December 31, 2017, September 30, 2017 and December 31, 2016, is as follows:



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



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


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

Note 9 — Debt

AmeriGas Propane. 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 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).

In December 2016, the Partnership recognized a pre-tax loss of $33.2 in connection with the early repayment of a portion of AmeriGas Partners’ 7.00% Senior Notes. This loss is reflected in “Loss on extinguishments of debt” on the Condensed Consolidated Statements of Income for the three months ended December 31, 2016.

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

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

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

October 30, 2022, after UGI Utilities receives a securities certificate from the PUC authorizing issuance of the security and upon delivery of such certificate to the agent. Proceeds from the Utilities Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Utilities Term Loan is payable in equal quarterly installments of $1.6 with the balance of the principal being due and payable in full on the maturity date. Under the Utilities Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The Utilities Term Loan requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. Because UGI Utilities has not yet received a securities certificate from the PUC authorizing the extension of the maturity date to October 30, 2022, the Utilities Term Loan has been reflected in “Current maturities of long-term debt” on the December 31, 2017, Condensed Consolidated Balance Sheet.

Note 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. 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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

gas wells. The COA environmental costs caps are $2.5, $1.8, and $1.1, for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively. At December 31, 2017, September 30, 2017 and December 31, 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $53.4, $54.3 and $55.3, 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 December 31, 2017, September 30, 2017 and December 31, 2016, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material.

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. To AmeriGas OLP’s knowledge, the DEC has not yet commenced implementation of the remediation plan but remediation is currently expected to commence in 2018. AmeriGas OLP responded to the DEC’s March 2017 request for ownership information, renewing 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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

affirmed by a panel of the Eighth Circuit. In September 2017, we filed a Petition for a Writ of Certiorari to the U.S. Supreme Court appealing the decision of the Eighth Circuit. The petition was denied in January 2018 and, as a result, 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; such appeal was subject to a stay pending the en banc review of the direct purchasers’ claims. In light of the Eighth Circuit decision with respect to the direct purchaser claims, the briefing schedule in respect of the indirect purchaser appeal will now resume. On July 21, 2016, several new indirect customer plaintiffs filed an antitrust class action lawsuit against the Partnership in the Western District of Missouri. The new indirect customer class action lawsuit was dismissed in September 2016 and certain indirect customer plaintiffs appealed the decision, consolidating their appeal with the indirect customer appeal still pending in the Eighth Circuit. Now that the Eighth Circuit has ruled on the direct purchasers’ claims, the stay has been lifted for the indirect claims and the parties submitted briefs in October 2017 to the Eighth Circuit and are awaiting the court’s ruling.

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.

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



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

The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. During the three months ended December 31, 2017 and 2016, the Company made cash contributions to the U.S. Pension Plan of $3.4 and $2.8, respectively. The Company expects to make additional discretionary cash contributions of approximately $10.1 to the U.S. Pension Plan during the remainder of Fiscal 2018.

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the three months ended December 31, 2017 and 2016.

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Note 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 December 31, 2017, September 30, 2017 and December 31, 2016:



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


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

The fair values of our Level 1 exchange-traded commodity futures and option contracts and non-exchange-traded commodity futures and forward contracts are based upon actively quoted market prices for identical assets and liabilities. The remainder of our derivative instruments are designated as Level 2. The fair values of certain non-exchange-traded commodity derivatives

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 that are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts, 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 December 31, 2017, September 30, 2017 and December 31, 2016 were as follows:



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

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

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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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Electricity

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

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities on the condensed consolidated balance sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 7).

Non-utility Operations

LPG

In order to manage market price risk associated with the Partnerships’ 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 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 December 31, 2017, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3.5.

Foreign Currency Exchange Rate Risk

Forward Foreign Currency Exchange Contracts

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

Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. The fair value of these forward foreign currency contracts are recorded as assets or liabilities on the condensed consolidated balance sheets. Changes in the fair value of these foreign currency exchange contracts are recorded in “Losses on foreign currency contracts, net” on the Condensed Consolidated Statements of Income.

From time to time we also enter into 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 December 31, 2017 and 2016, 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 December 31, 2017, the amount of net losses associated with such cross-currency swaps expected to be reclassified into earnings during the next twelve months is not material.

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



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


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

Derivative Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain 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 December 31, 2017, September 30, 2017 and December 31, 2016, restricted cash in brokerage accounts totaled $19.8, $10.3 and $7.9, 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 December 31, 2017. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

At December 31, 2017, 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 December 31, 2017, September 30, 2017 and December 31, 2016:



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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Effect of Derivative Instruments

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



Three Months Ended December 31,:
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain (Loss) Reclassified from AOCI into Income
Cash Flow Hedges:	2017			2016			2017			2016			Location of Gain (Loss) Reclassified from AOCI into Income
Foreign currency contracts	$	(1.4	)	$	17.2		$	0.8		$	7.9		Cost of sales
Cross-currency contracts	0.1			(0.1		)	0.2			(0.3		)	Interest expense/other operating income, net
Interest rate contracts	0.7			1.2			(0.5		)	(1.0		)	Interest expense
Total	$	(0.6	)	$	18.3		$	0.5		$	6.6

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

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

We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts that provide for the purchase and delivery, or sale, of energy products, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although certain of these contracts have the requisite elements of a derivative instrument, 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.

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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 14 — Accumulated Other Comprehensive Income

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



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

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

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

Note 15 — 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

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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.



Three Months Ended December 31, 2017	Total			Eliminations				AmeriGas Propane			UGI International			Midstream & Marketing				UGI Utilities			Corporate & Other (b)
Revenues	$	2,125.2		$	—			$	787.3		$	784.2		$	249.8			$	305.4		$	(1.5	)
Intersegment revenues	$	—		$	(97.1	)	(c)	$	—		$	—		$	78.2			$	17.7		$	1.2
Cost of sales	$	1,137.4		$	(96.0	)	(c)	$	366.1		$	484.8		$	239.0			$	151.8		$	(8.3	)
Segment profit:
Operating income	$	391.8		$	0.2			$	147.9		$	93.1		$	52.3			$	96.3		$	2.0
Income (loss) from equity investees	1.0			—				—			(0.2		)	1.2			(d)	—			—
Losses on foreign currency contracts, net	(4.8		)	—				—			(4.7		)	—				—			(0.1		)
Interest expense	(58.2		)	—				(40.6		)	(5.6		)	(0.9		)		(10.9		)	(0.2		)
Income before income taxes	$	329.8		$	0.2			$	107.3		$	82.6		$	52.6			$	85.4		$	1.7
Partnership Adjusted EBITDA (a)								$	194.1
Noncontrolling interests’ net income (loss)	$	68.3		$	—			$	68.0		$	(0.3	)	$	—			$	—		$	0.6
Depreciation and amortization	$	110.3		$	—			$	47.4		$	32.2		$	10.1			$	20.4		$	0.2
Capital expenditures (including the effects of accruals)	$	128.5		$	—			$	23.6		$	21.7		$	11.3			$	71.7		$	0.2
As of December 31, 2017
Total assets	$	12,343.9		$	(62.6	)		$	4,206.2		$	3,450.1		$	1,325.1			$	3,174.7		$	250.4
Short-term borrowings	$	586.1		$	—			$	263.5		$	41.1		$	100.0			$	181.5		$	—
Goodwill	$	3,185.5		$	—			$	2,001.3		$	990.6		$	11.5			$	182.1		$	—



Three Months Ended December 31, 2016	Total			Eliminations				AmeriGas Propane			UGI International			Midstream & Marketing			UGI Utilities			Corporate & Other (b)
Revenues	$	1,679.5		$	—			$	677.2		$	539.1		$	209.6		$	253.9		$	(0.3	)
Intersegment revenues	$	—		$	(68.5	)	(c)	$	—		$	—		$	60.2		$	7.5		$	0.8
Cost of sales	$	647.4		$	(67.7	)	(c)	$	260.7		$	258.0		$	191.8		$	109.5		$	(104.9	)
Segment profit:
Operating income	$	466.2		$	0.1			$	141.9		$	88.9		$	49.7		$	82.2		$	103.4
Loss from equity investees	(0.2		)	—				—			(0.2		)	—			—			—
Gains on foreign currency contracts, net	1.3			—				—			0.1			—			—			1.2
Loss on extinguishments of debt	(33.2		)	—				(33.2		)	—			—			—			—
Interest expense	(55.4		)	—				(40.0		)	(4.8		)	(0.6		)	(10.0		)	—
Income before income taxes	$	378.7		$	0.1			$	68.7		$	84.0		$	49.1		$	72.2		$	104.6
Partnership Adjusted EBITDA (a)								$	185.1
Noncontrolling interests’ net income	$	60.2		$	—			$	41.2		$	0.2		$	—		$	—		$	18.8
Depreciation and amortization	$	98.1		$	—			$	44.6		$	27.9		$	8.0		$	17.4		$	0.2
Capital expenditures (including the effects of accruals)	$	173.6		$	—			$	26.4		$	21.5		$	61.5		$	64.1		$	0.1
As of December 31, 2016
Total assets	$	11,300.5		$	(107.9	)		$	4,217.9		$	2,853.4		$	1,178.4		$	2,898.5		$	260.2
Short-term borrowings	$	234.4		$	—			$	77.5		$	3.5		$	55.0		$	98.4		$	—
Goodwill	$	2,935.8		$	—			$	1,978.5		$	763.7		$	11.5		$	182.1		$	—

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


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


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


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


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

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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 December 31, 2017 (“2017 three-month period”) with the three months ended December 31, 2016 (“2016 three-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 transactions and (2) other significant discrete items that management believes affect the comparison of period-over-period results (as such items are further described below). UGI does not designate its commodity and certain foreign currency derivative

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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 currency derivatives reduce volatility in anticipated future earnings associated with our foreign operations, we expect that such gains or losses will be largely offset by gains or losses on anticipated future energy commodity transactions or mitigate the volatility in anticipated future earnings. For further information, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share” below.

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

EXECUTIVE OVERVIEW

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



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


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



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

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


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

(c)

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


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

(e)

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

N.M. — Variance is not meaningful.

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

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

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

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

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

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

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



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

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

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


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


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


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

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

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

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

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

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

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

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

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

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

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


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


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

RESULTS OF OPERATIONS

2017 three-month period compared to the 2016 three-month period

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.

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AmeriGas Propane



For the three months ended December 31,	2017			2016			Increase (Decrease)
(Dollars in millions)
Revenues	$	787.3		$	677.2		$	110.1		16.3	%
Total margin (a)	$	421.2		$	416.5		$	4.7		1.1	%
Partnership operating and administrative expenses	$	230.3		$	226.8		$	3.5		1.5	%
Partnership Adjusted EBITDA (b)(c)	$	194.1		$	185.1		$	9.0		4.9	%
Operating income (c) (d)	$	147.9		$	141.9		$	6.0		4.2	%
Retail gallons sold (millions)	305.0			305.7			$	(0.7	)	(0.2	)%
Heating degree days—% (warmer) than normal (e)	(1.4		)%	(10.3		)%	—			—


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


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


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


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


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

AmeriGas Propane’s retail gallons sold during the 2017 three-month period were approximately equal to the prior-year period. Average temperatures based upon heating degree days during the 2017 three-month period were 1.4% warmer than normal but 9.9% colder than the prior-year period. Average temperatures during the 2017 three-month period were significantly influenced by much colder than normal temperatures that occurred during the last week of December which was nearly 60% colder than the prior year. Excluding the last week of December 2017, average temperatures during the 2017 three-month period were approximately 6.6% warmer than normal and 3.8% colder than the prior-year period.

AmeriGas Propane’s retail propane revenues increased $99.2 million during the 2017 three-month period reflecting the effects of higher average retail selling prices ($100.6 million) partially offset by the lower retail volumes sold ($1.4 million). Wholesale propane revenues increased $8.2 million during the 2017 three-month period reflecting the effects of higher average wholesale selling prices ($5.6 million) and higher wholesale volumes sold ($2.6 million). Average daily wholesale propane commodity prices during the 2017 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 64% higher than such prices during the 2016 three-month period. Other revenues in the 2017 three-month period were slightly higher than in the prior-year period. AmeriGas Propane total cost of sales increased $105.4 million principally reflecting the effects of higher average propane product costs ($103.0 million) and, to a much lesser extent, the effects of the higher wholesale propane volumes sold.

AmeriGas Propane total margin increased $4.7 million in the 2017 three-month period principally reflecting slightly higher retail propane total margin ($2.6 million) and slightly higher non-propane total margin ($2.1 million). The increase in retail propane total margin reflects slightly higher average retail unit margin.

Partnership Adjusted EBITDA increased $9.0 million in the 2017 three-month period principally reflecting the effects of the higher total margin ($4.7 million) and higher other operating income ($7.8 million) partially offset by slightly higher Partnership operating and administrative expenses ($3.5 million). The increase in other operating income reflects the absence of an $8.8 million adjustment recorded in the prior-year period to correct previously recorded gains on sales of fixed assets acquired with the Heritage Propane acquisition in 2012. The increase in operating and administrative expenses principally reflects higher vehicle ($2.9 million), outside services ($2.0 million) and compensation and benefits ($1.9 million) expenses partially offset by lower general insurance and self-insured casualty and liability expense.

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

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

UGI International



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


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


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


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


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

Average temperatures during the 2017 three-month period were approximately 0.9% warmer than normal and 7.0% warmer than the prior-year period. Total retail gallons sold during the 2017 three-month period were higher than the prior-year period as incremental retail gallons sold as a result of our October 2017 acquisition of Total’s retail LPG business in Italy (now known as “UniverGas”) were partially offset by the effects of the warmer weather on bulk sales and lower crop-drying volumes. During the 2017 three-month period, average wholesale commodity prices for propane and butane in northwest Europe were approximately 37% and 25% higher than in the prior-year period, respectively.

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 2017 and 2016 three-month periods, the average un-weighted euro-to-dollar translation rates were approximately $1.18 and $1.08, respectively, and the average un-weighted British pound sterling-to-dollar translation rates were approximately $1.33 and $1.25, respectively. Although the euro and British pound sterling were stronger during the 2017 three-month period and impact the comparison of line item amounts presented 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 $245.1 million during the 2017 three-month period reflecting approximately $137.0 million of combined incremental revenues from UniverGas and our August 2017 acquisition of an electricity and natural gas marketing business in the Netherlands (“DVEP”), the effects of higher LPG selling prices resulting from the higher LPG product costs, and the translation effects on local currency revenues of the stronger euro and British pound sterling. UGI International cost of sales increased $226.8 million during the 2017 three-month period reflecting approximately $119.0 million of incremental cost of sales associated with UniverGas and DVEP, higher average LPG commodity costs, and the translation effects of the stronger euro and British pound sterling.

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

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

The $4.2 million increase in UGI International operating income principally reflects the previously mentioned $18.3 million increase in total margin partially offset by an $8.3 million increase in operating and administrative costs and a $4.3 million increase in depreciation and amortization expense. The increase in operating and administrative costs principally reflects the translation effects of the stronger euro and British pound sterling on local currency expenses and approximately $10.0 million of incremental expenses from UniverGas and DVEP. These increases in operating and administrative expenses were partially offset by lower local currency operating expenses at our legacy LPG business reflecting, in large part, expense synergies from Finagaz integration activities and lower repairs and maintenance, LPG distribution and Finagaz integration expenses. Operating and administrative expenses in the 2017 and 2016 three-month periods include $1.9 million and $8.1 million of Finagaz integration costs, respectively. The higher depreciation and amortization reflects UniverGas and DVEP ($2.8 million) and the translation effects of the stronger currencies. UGI International income before income taxes decreased $1.4 million principally reflecting the previously mentioned $4.2 million increase in UGI International operating income reduced by realized losses on foreign currency exchange contracts ($4.7 million) and slightly higher interest expense ($0.8 million) due to the stronger euro.

Midstream & Marketing



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


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

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

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

Midstream & Marketing operating income and income before income taxes during the 2017 three-month period increased $2.6 million and $3.5 million, respectively. The increase in operating income principally reflects the previously mentioned increase in total margin ($11.0 million) partially offset by higher operating and administrative expenses ($3.7 million), higher depreciation expense ($2.1 million), and a $2.7 million decrease in other operating income primarily from the absence of AFUDC income associated with the Sunbury Pipeline project recorded in the prior-year period. The $3.7 million increase in operating and administrative expenses reflects higher wage and benefits expense and higher expenses associated with greater peaking and gas gathering activities, while the increase in depreciation expense principally reflects incremental depreciation from the expansion

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

UGI Utilities



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


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


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

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

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

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

UGI Utilities operating income increased $14.1 million, principally reflecting the increase in total margin ($19.4 million) partially offset by higher operating and administrative expenses ($2.4 million) and greater depreciation and amortization expense ($3.0 million) associated with increased capital expenditure activity. The increase in UGI Utilities operating and administrative expenses reflects higher distribution expenses ($1.8 million), higher uncollectible accounts expense ($1.0 million) and higher information technology expenses ($0.7 million) partially offset by a favorable payroll tax adjustment related to prior periods ($2.1 million).

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

Interest Expense and Income Taxes

Our consolidated interest expense during the 2017 three-month period was $58.2 million, $2.8 million higher than the $55.4 million of interest expense recorded during the 2016 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 December 31, 2017, were significantly impacted by the enactment of the TCJA and the December 2017 French Finance Bills. Accordingly, the effective tax rate as calculated based upon amounts on our condensed consolidated statement of income for the 2017 three-month period includes the effects of one-time discrete adjustments to deferred income tax assets and liabilities, accrued income taxes and deferred tax valuation allowances which reduced income tax expense by $183.3 million.

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

Excluding the impacts of the one-time discrete adjustments from the TCJA and French tax rate changes in both periods as noted above, our effective income tax rate for the 2017 three-month period was lower than in the prior-year period principally reflecting the lower blended U.S. tax rate of 24.5% in Fiscal 2018 resulting from the enactment of the TCJA.

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 $446.4 million at December 31, 2017, compared with $558.4 million at September 30, 2017. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at December 31, 2017 and September 30, 2017, UGI had $162.0 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.

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Long-term Debt and Short-term Borrowings

Long-term Debt

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



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

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


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

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

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

Credit Facilities

Additional information related to the Company’s credit agreements can be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Note 5 to the Consolidated Financial Statements in the Company’s 2017 Annual Report.

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



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


(a)	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 three months ended December 31, 2017 and 2016 are as follows:



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

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

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

Midstream & Marketing. 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 December 31, 2017, the outstanding balance of ESFC trade receivables was $101.0 million, of which $45.0 million was sold to the bank. At December 31, 2016, the

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outstanding balance of ESFC trade receivables was $81.4 million and there were $35.0 million amounts sold to the bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. During the three months ended December 31, 2017 and 2016, peak sales of receivables were $45.0 million and $36.5 million, respectively, and average daily amounts sold were $28.6 million and $23.7 million, respectively. For additional information regarding the Receivables Facility, see Note 8 to the condensed consolidated financial statements.

Dividends and Distributions

On November 29, 2017, UGI’s Board of Directors declared a cash dividend equal to $0.25 per common share. The dividend was paid on January 1, 2018, to shareholders of record on December 15, 2017. On January 25, 2018, UGI’s Board of Directors declared a quarterly dividend of $0.25 per common share. The dividend is payable April 1, 2018, to shareholders of record on March 15, 2018.

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

Repurchase of Common Stock

In January 2014, UGI’s Board of Directors authorized a share repurchase program for up to 15 million shares of UGI Corporation Common Stock. The authorization permitted the execution of the share repurchase program over a four-year period, expiring in January 2018. On January 25, 2018, 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.

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 $31.4 million in the 2017 three-month period compared to $126.6 million in the 2016 three-month period. Cash flow from operating activities before changes in operating working capital was $384.6 million in the 2017 three-month period compared to $333.9 million in the prior-year period. The higher cash flow from operating activities before changes in operating working capital reflects the positive effects on cash flow of higher net income (after adjusting net income for the previously mentioned one-time impacts of the enactment of the TCJA and changes in French tax laws on tax-related accounts in 2017 ($183.3 million) and in 2016 ($27.4 million); the non-cash effects of changes in unrealized gains and losses on derivative instruments; and the loss on extinguishments of debt at AmeriGas Partners, the cash flow effects of which are reflected in cash flows from financing activities). Cash used to fund changes in operating working capital totaled $353.2 million in the 2017 three-month period compared to $207.3 million in the prior-year period. The higher cash required to fund changes in accounts receivable and inventories reflects, in large part, the impact of higher LPG and natural gas costs during the current-year period.

Investing Activities. Cash flow used by investing activities was $327.5 million in the 2017 three-month period compared with $192.4 million in the prior-year period. Investing activity cash flow is principally affected by 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 $147.5 million in the 2017 three-month period compared to $197.1 million in the prior-year period. Cash payments in the prior-year included capital expenditures associated with the Sunbury Pipeline project at Midstream & Marketing. Cash used for acquisitions of businesses and assets in the 2017 three-month period principally reflects the acquisition of UniverGas at UGI International and the acquisition of a natural gas gathering system in northern Pennsylvania at Midstream & Marketing.

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

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UGI Utilities issued $125 million of unsecured notes and used the proceeds principally to reduce short-term borrowings and for general corporate purposes.

UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units

On November 7, 2017, UGI entered into 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.

IMPACT OF TAX REFORM

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

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

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


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


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


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

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

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estimated annual effective tax rate is based on this 24.5% blended rate for fiscal year 2018. For the three months ended December 31, 2017, 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 $20.4 million. Regarding UGI Utilities, the PUC has not issued any orders with respect to the lower income tax rate. Our estimated annual effective tax rate for Fiscal 2018 does not reflect the impact of any regulatory action that may be taken by the PUC with respect to the TCJA.

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

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

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

UTILITY REGULATORY MATTERS

Base Rate Filings. 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, although the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. This review process is expected to last up to nine months; 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.

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.

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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 December 31, 2017, the fair values of Gas Utility’s natural gas futures and option contracts were net losses of $1.7 million.

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

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

In order to manage market price risk relating to substantially all of Midstream & Marketing’s fixed-price sales 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 December 31, 2017 (excluding those Gas Utility and Electric Utility commodity derivative instruments that are refundable to, or recoverable from, customers) was a gain of $77.0 million. A hypothetical 10% adverse change in the market price of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges would result in a decrease in fair value of approximately $77.3 million at December 31, 2017.

Interest Rate Risk

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

Our variable-rate debt at December 31, 2017, 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 December 31, 2017, combined borrowings outstanding under variable-rate debt agreements, excluding UGI France SAS’s and Flaga’s effectively fixed-rate debt, totaled $711.1 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 December 31, 2017 (including pay-fixed, receive-variable interest rate swaps) was a loss of $2.1 million. A 50 basis point adverse change in the three-month euribor rate and three-month LIBOR would result in a decrease in fair value of approximately $1.7 million.

Foreign Currency Exchange Rate Risk

Our primary currency exchange rate risk is associated with the U.S. dollar 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 December 31, 2017, by approximately $135.0 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 December 31, 2017, 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 December 31, 2017, including the fair value of Flaga’s cross-currency swap, was a loss of $29.2 million. A hypothetical 10% adverse change in the value of the euro and the British pound sterling versus the U.S. dollar would result in a decrease in fair value of approximately $56.6 million.

Derivative Instrument Credit Risk

Certain of these derivative instrument agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2017, restricted cash in brokerage accounts totaled $19.8 million. Although 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 December 31, 2017. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At December 31, 2017, 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 December 31, 2017.



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

(1)

In January 2014, the UGI Board of Directors authorized a share repurchase program for up to 15 million shares of UGI Corporation Common Stock. The authorization permitted the execution of the share repurchase program over a four-year period, expiring in January 2018. On January 25, 2018, the UGI Board of Directors authorized an extension of the share repurchase program for up to 8 million shares of UGI Corporation Common Stock for an additional four-year period.

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

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

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

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

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

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

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

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

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

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


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

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