10-Q
Table of Contents

 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
 
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2015
OR
¨
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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
ý
Accelerated filer
¨
Non-accelerated filer
¨
Smaller reporting company
¨

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, 2016, there were 171,914,720 shares of UGI Corporation Common Stock, without par value, outstanding.
 
 
 
 
 


Table of Contents

UGI CORPORATION AND SUBSIDIARIES
TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
41 
 
 
 
 
 

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES

 
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Millions of dollars)
 
 
December 31,
2015
 
September 30,
2015
 
December 31,
2014
ASSETS
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
Cash and cash equivalents
 
$
403.0

 
$
369.7

 
$
410.1

Restricted cash
 
55.5

 
69.3

 
54.6

Accounts receivable (less allowances for doubtful accounts of $30.6, $29.7 and $37.9, respectively)
 
803.1

 
619.7

 
960.6

Accrued utility revenues
 
30.8

 
12.1

 
52.7

Inventories
 
246.8

 
239.9

 
391.0

Deferred income taxes
 

 
7.8

 
46.1

Utility regulatory assets
 
3.9

 
4.1

 
16.8

Derivative instruments
 
29.1

 
23.3

 
19.7

Prepaid expenses and other current assets
 
101.8

 
113.9

 
88.0

Total current assets
 
1,674.0

 
1,459.8

 
2,039.6

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,896.9 $2,835.0 and $2,664.2, respectively)
 
5,012.9

 
4,994.1

 
4,552.7

Goodwill
 
2,965.1

 
2,953.4

 
2,806.8

Intangible assets, net
 
602.4

 
610.1

 
563.7

Utility regulatory assets
 
297.9

 
300.1

 
253.8

Derivative instruments
 
13.7

 
16.3

 
16.1

Deferred income taxes
 
5.6

 
5.1

 

Other assets
 
208.8

 
207.7

 
197.3

Total assets
 
$
10,780.4

 
$
10,546.6

 
$
10,430.0

LIABILITIES AND EQUITY
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
Current maturities of long-term debt
 
$
186.9

 
$
258.0

 
$
147.1

Short-term borrowings
 
456.8

 
189.9

 
458.5

Accounts payable
 
423.3

 
392.9

 
556.5

Derivative instruments
 
123.1

 
121.8

 
157.0

Other current liabilities
 
721.6

 
716.3

 
649.7

Total current liabilities
 
1,911.7

 
1,678.9

 
1,968.8

Long-term debt
 
3,422.4

 
3,441.8

 
3,341.2

Deferred income taxes
 
1,140.4

 
1,134.0

 
976.3

Deferred investment tax credits
 
3.5

 
3.6

 
3.8

Derivative instruments
 
33.6

 
31.2

 
39.9

Other noncurrent liabilities
 
676.3

 
684.7

 
545.3

Total liabilities
 
7,187.9

 
6,974.2

 
6,875.3

Commitments and contingencies (Note 9)
 

 

 

Equity:
 
 
 
 
 
 
UGI Corporation stockholders’ equity:
 
 
 
 
 
 
UGI Common Stock, without par value (authorized—450,000,000 shares; issued—173,825,741, 173,806,991 and 173,772,391 shares, respectively)
 
1,215.7

 
1,214.6

 
1,215.7

Retained earnings
 
1,712.3

 
1,636.9

 
1,506.0

Accumulated other comprehensive loss
 
(142.9
)
 
(114.6
)
 
(40.1
)
Treasury stock, at cost
 
(65.7
)
 
(44.9
)
 
(35.3
)
Total UGI Corporation stockholders’ equity
 
2,719.4

 
2,692.0

 
2,646.3

Noncontrolling interests, principally in AmeriGas Partners
 
873.1

 
880.4

 
908.4

Total equity
 
3,592.5

 
3,572.4

 
3,554.7

Total liabilities and equity
 
$
10,780.4

 
$
10,546.6

 
$
10,430.0

See accompanying notes to condensed consolidated financial statements.

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Millions of dollars, except per share amounts)
 
 
Three Months Ended
December 31,
 
 
2015
 
2014
Revenues
 
$
1,606.6

 
$
2,004.6

Costs and expenses:
 
 
 
 
Cost of sales (excluding depreciation shown below)
 
734.0

 
1,404.6

Operating and administrative expenses
 
464.1

 
435.7

Utility taxes other than income taxes
 
3.8

 
4.1

Depreciation
 
85.7

 
75.8

Amortization
 
14.9

 
15.2

Other operating income, net
 
(1.4
)
 
(14.1
)
 
 
1,301.1

 
1,921.3

Operating income
 
305.5

 
83.3

Loss from equity investees
 
(0.1
)
 
(1.0
)
Interest expense
 
(57.9
)
 
(59.0
)
Income before income taxes
 
247.5

 
23.3

Income tax expense
 
(79.6
)
 
(23.1
)
Net income including noncontrolling interests
 
167.9

 
0.2

(Deduct net income) add net loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
(53.3
)
 
33.9

Net income attributable to UGI Corporation
 
$
114.6

 
$
34.1

Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
 
Basic
 
$
0.66

 
$
0.20

Diluted
 
$
0.65

 
$
0.19

Weighted-average common shares outstanding (thousands):
 
 
 
 
Basic
 
172,862

 
172,945

Diluted
 
175,218

 
175,786

Dividends declared per common share
 
$
0.2275

 
$
0.2175

See accompanying notes to condensed consolidated financial statements.


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Table of Contents
UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(Millions of dollars)
 
 
Three Months Ended
December 31,
 
 
2015
 
2014
Net income including noncontrolling interests
 
$
167.9

 
$
0.2

Other comprehensive income (loss):
 
 
 
 
Net gains on derivative instruments (net of tax of $(4.2) and $(3.9), respectively)
 
6.8

 
7.7

Reclassifications of net (gains) losses on derivative instruments (net of tax of $3.2 and $(1.5), respectively)
 
(5.3
)
 
2.1

Foreign currency adjustments (net of tax of $0 and $15.6, respectively)
 
(30.2
)
 
(30.5
)
Benefit plans (net of tax of $(0.3) and $(0.4), respectively)
 
0.4

 
0.6

Other comprehensive loss
 
(28.3
)
 
(20.1
)
Comprehensive income (loss) including noncontrolling interests
 
139.6

 
(19.9
)
(Deduct comprehensive income) add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
(53.3
)
 
35.0

Comprehensive income attributable to UGI Corporation
 
$
86.3

 
$
15.1

See accompanying notes to condensed consolidated financial statements.


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Table of Contents
UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Millions of dollars)
 
 
Three Months Ended
December 31,
 
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
Net income including noncontrolling interests
 
$
167.9

 
$
0.2

Adjustments to reconcile net income to net cash from operating activities:
 
 
 
 
Depreciation and amortization
 
100.6

 
91.0

Deferred income tax benefit, net
 
(20.9
)
 
(59.8
)
Provision for uncollectible accounts
 
6.0

 
7.0

Unrealized (gains) losses on derivative instruments
 
(1.1
)
 
229.7

Other, net
 
5.9

 
(0.9
)
Net change in:
 
 
 
 
Accounts receivable and accrued utility revenues
 
(213.4
)
 
(341.8
)
Inventories
 
(9.1
)
 
27.6

Utility deferred fuel and power costs, net of changes in unsettled derivatives
 
(6.8
)
 
4.4

Accounts payable
 
33.7

 
119.3

Collateral deposits
 
2.5

 
(90.9
)
Other current assets
 
2.6

 
(14.9
)
Other current liabilities
 
59.6

 
48.1

Net cash provided by operating activities
 
127.5

 
19.0

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
Expenditures for property, plant and equipment
 
(132.0
)
 
(132.1
)
Acquisitions of businesses, net of cash acquired
 
(41.7
)
 
(7.2
)
Decrease (increase) in restricted cash
 
13.8

 
(38.0
)
Other, net
 
4.6

 
7.0

Net cash used by investing activities
 
(155.3
)
 
(170.3
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
Dividends on UGI Common Stock
 
(39.2
)
 
(37.5
)
Distributions on AmeriGas Partners publicly held Common Units
 
(63.6
)
 
(60.8
)
Repayments of debt
 
(74.5
)
 
(2.6
)
Increase in short-term borrowings
 
260.4

 
213.0

Receivables Facility net borrowings
 
6.5

 
35.5

Issuances of UGI Common Stock
 
2.0

 
5.5

Repurchases of UGI Common Stock
 
(23.6
)
 

Other
 
0.4

 
(3.3
)
Net cash provided by financing activities
 
68.4

 
149.8

EFFECT OF EXCHANGE RATE CHANGES ON CASH
 
(7.3
)
 
(7.9
)
Cash and cash equivalents increase (decrease)
 
$
33.3

 
$
(9.4
)
Cash and cash equivalents:
 
 
 
 
End of period
 
$
403.0

 
$
410.1

Beginning of period
 
369.7

 
419.5

Increase (decrease)
 
$
33.3

 
$
(9.4
)
See accompanying notes to condensed consolidated financial statements.

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(Millions of dollars)
 
Three Months Ended
December 31,
 
2015
 
2014
Common stock, without par value
 
 
 
Balance, beginning of period
$
1,214.6

 
$
1,215.6

Common Stock issued in connection with employee and director plans (including (losses) on treasury stock transactions), net of tax withheld
(0.9
)
 
(3.9
)
Excess tax benefits realized on equity-based compensation
0.4

 
1.8

Equity-based compensation expense
1.6

 
2.2

Balance, end of period
$
1,215.7

 
$
1,215.7

Retained earnings
 
 
 
Balance, beginning of period
$
1,636.9

 
$
1,509.4

Net income attributable to UGI Corporation
114.6

 
34.1

Cash dividends on Common Stock
(39.2
)
 
(37.5
)
Balance, end of period
$
1,712.3

 
$
1,506.0

Accumulated other comprehensive income (loss)
 
 
 
Balance, beginning of period
$
(114.6
)
 
$
(21.2
)
Net gains on derivative instruments, net of tax
6.8

 
7.7

Reclassification of net (gains) losses on derivative instruments, net of tax
(5.3
)
 
3.3

Benefit plans, net of tax
0.4

 
0.6

Foreign currency, net of tax
(30.2
)
 
(30.5
)
Balance, end of period
$
(142.9
)
 
$
(40.1
)
Treasury stock
 
 
 
Balance, beginning of period
$
(44.9
)
 
$
(44.7
)
Common stock issued in connection with employee and director plans, net of tax withheld
3.0

 
9.8

Repurchases of Common Stock
(23.6
)
 

Reacquired common stock - employee and director plans
(0.2
)
 
(0.4
)
Balance, end of period
$
(65.7
)
 
$
(35.3
)
Total UGI Corporation stockholders’ equity
$
2,719.4

 
$
2,646.3

Noncontrolling interests
 
 
 
Balance, beginning of period
$
880.4

 
$
1,004.1

Net income attributable to noncontrolling interests, principally in AmeriGas Partners
53.3

 
(33.9
)
Reclassification of net gains on derivative instruments

 
(1.2
)
Dividends and distributions
(63.6
)
 
(60.8
)
Other
3.0

 
0.2

Balance, end of period
$
873.1

 
$
908.4

Total equity
$
3,592.5

 
$
3,554.7

See accompanying notes to condensed consolidated financial statements.


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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)


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; (3) own all or a portion of electricity generation facilities; and (4) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe and China. 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”), which is referred to herein as the “Operating Partnership.” 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, 2015, the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.1% 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 15 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2015 (the “Company’s 2015 Annual Report”). Incentive distributions received by the General Partner during the three months ended December 31, 2015 and 2014 were $8.6 and $6.5, respectively.

Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“UGI France”); (2) an LPG distribution business in central, northern and eastern Europe (“Flaga”); (3) an LPG distribution business in the United Kingdom (“AvantiGas”); and (4) an LPG distribution business in the Nantong region of China. We refer to our foreign LPG operations collectively as “UGI International.”

Enterprises, through UGI Energy Services, LLC and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic and Northeast U.S. In addition, UGI Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. These businesses are referred to herein collectively as “Midstream & Marketing.” UGI Energy Services, LLC is referred to herein as “Energy Services.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries (“HVAC”).

Our natural gas distribution utility business (“Gas Utility”) is conducted through our wholly owned subsidiary, UGI Utilities, Inc. (“UGI Utilities”), and its 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, northeastern 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. Gas Utility and Electric Utility are collectively referred to as “Utilities.”


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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

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 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, 2015, 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 2015 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
 
Shares used in computing basic and diluted earnings per share are as follows: 
 
 
Three Months Ended
December 31,
 
 
2015
 
2014
Denominator (thousands of shares):
 
 
 
 
Weighted-average common shares outstanding for basic computation
 
172,862

 
172,945

Incremental shares issuable for stock options and awards
 
2,356

 
2,841

Weighted-average common shares outstanding for diluted computation
 
175,218

 
175,786


Derivative Instruments. Derivative instruments are reported in the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. 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 or net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, 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 Gas Utility and Electric Utility are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers.

Effective October 1, 2014, UGI International determined on a prospective basis that it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Substantially all realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues, as appropriate, 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 are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows. Cash flows

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

from the interest portion of our cross-currency hedges are included in cash flow from operating activities while cash flows from the currency portion of such hedges are included in the cash flow from financing activities.

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 12.

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

Consolidated Effective Income Tax Rate. UGI’s consolidated effective income tax rate, defined as total income tax (expense) or benefit 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.

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

Correction of Prior Period Error in Other Comprehensive Income
During the three months ended June 30, 2015, the Company recorded an adjustment to decrease other comprehensive income related to prior periods by reducing the amount of net deferred tax assets that had been previously recognized for (1) foreign currency adjustments related to foreign subsidiaries whose undistributed earnings are considered indefinitely reinvested, and (2) foreign currency adjustments related to intercompany loans between a U.S. domiciled entity and its foreign branch that is considered disregarded for tax purposes and for which income taxes will not be payable. Accounting Standards Codification (“ASC”) No. 740, “Income Taxes,” provides an exception to recording deferred tax attributes associated with these components of comprehensive income. Previously, the Company had incorrectly recorded deferred taxes on these currency adjustments. During the three months ended June 30, 2015, the Company evaluated the effects of the errors, both qualitatively and quantitatively, and concluded that they did not have a material impact on any prior period financial statement and recorded the cumulative effect of the error as of April 1, 2015. If the Company had corrected the error in all of the periods prior to April 1, 2015, other comprehensive loss for the three months ended December 31, 2014, would have increased by $14.4.

Note 3 — Accounting Changes

Adoption of New Accounting Standard

Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. We applied this guidance prospectively and, as a result, prior period amounts have not been adjusted.
Accounting Standards Not Yet Adopted

Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015 (Fiscal 2017). Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance effective September 30, 2016. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements.

Consolidation. In February 2015, the FASB issued ASU No. 2015-02, “Amendments to the Consolidation Analysis.” This ASU provides new guidance regarding whether a reporting entity should consolidate certain types of legal entities. Among other things,

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

the new guidance modifies the evaluation of whether limited partnerships and similar entities are variable interest entities (“VIEs”) or voting interest entities, and also eliminates the presumption that a general partner should consolidate a limited partnership. The new guidance also affects the consolidation analysis of reporting entities that are involved with VIEs including those that have fee arrangements and related party relationships. The new guidance is effective for the Company beginning in Fiscal 2017. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements, if any, from the adoption of the new guidance.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard 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. This standard is effective for the Company for interim and annual periods beginning October 1, 2018 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our financial statements.

Note 4 — Inventories

Inventories comprise the following: 
 
 
December 31,
2015
 
September 30,
2015
 
December 31,
2014
Non-utility LPG and natural gas
 
$
148.6

 
$
140.7

 
$
260.4

Gas Utility natural gas
 
35.9

 
37.5

 
72.4

Materials, supplies and other
 
62.3

 
61.7

 
58.2

Total inventories
 
$
246.8

 
$
239.9

 
$
391.0


At December 31, 2015, UGI Utilities is a party to two principal storage contract administrative agreements (“SCAAs”) having terms of 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, 2015, UGI Utilities has SCAAs with Energy Services and a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at December 31, 2015, September 30, 2015 and December 31, 2014, comprising 3.8 billion cubic feet (“bcf”), 4.0 bcf and 3.4 bcf of natural gas, was $9.4, $9.8 and $14.4, respectively.


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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Note 5 — Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following: 
 
 
December 31,
2015
 
September 30,
2015
 
December 31,
2014
Goodwill (not subject to amortization)
 
$
2,965.1

 
$
2,953.4

 
$
2,806.8

Intangible assets:
 
 
 
 
 
 
Customer relationships, noncompete agreements and other
 
$
764.6

 
$
761.1

 
$
709.3

Accumulated amortization
 
(292.2
)
 
(282.4
)
 
(271.9
)
Intangible assets, net (definite-lived)
 
472.4

 
478.7

 
437.4

Trademarks and tradenames (indefinite-lived)
 
130.0

 
131.4

 
126.3

Total intangible assets, net
 
$
602.4

 
$
610.1

 
$
563.7

The changes in goodwill and intangible assets are primarily due to acquisitions and the effects of currency translation. Amortization expense of intangible assets was $12.8 and $13.0 for the three months ended December 31, 2015 and December 31, 2014, respectively. Amortization expense included in cost of sales in the Condensed Consolidated Statements of Income is not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2016 and for the next four fiscal years is as follows: remainder of Fiscal 2016$39.0; Fiscal 2017$46.1; Fiscal 2018$44.6; Fiscal 2019$42.9; Fiscal 2020$41.6.

Note 6 — Utility Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 9 in the Company’s 2015 Annual Report. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:
 
 
December 31,
2015
 
September 30,
2015
 
December 31,
2014
Regulatory assets:
 
 
 
 
 
 
Income taxes recoverable
 
$
117.4

 
$
115.9

 
$
111.1

Underfunded pension and postretirement plans
 
138.3

 
140.8

 
107.8

Environmental costs
 
17.6

 
20.0

 
14.7

Deferred fuel and power costs
 

 

 
16.7

Removal costs, net
 
22.3

 
21.2

 
17.6

Other
 
6.2

 
6.3

 
2.7

Total regulatory assets
 
$
301.8

 
$
304.2

 
$
270.6

Regulatory liabilities (a):
 
 
 
 
 
 
Postretirement benefits
 
$
20.3

 
$
20.0

 
$
19.0

Deferred fuel and power refunds
 
28.1

 
36.6

 

State tax benefits—distribution system repairs
 
13.7

 
13.3

 
10.3

Other
 
1.1

 
1.1

 
3.6

Total regulatory liabilities
 
$
63.2

 
$
71.0

 
$
32.9


(a) Regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.

Deferred fuel and power—costs and refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses which 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

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at December 31, 2015September 30, 2015 and December 31, 2014 were $(4.5), $(3.3) and $(6.8), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Prior to March 1, 2015, we did not elect the NPNS exception under GAAP for these contracts. Therefore, we recognized the fair value of these contracts on the balance sheet with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At December 31, 2015September 30, 2015, and December 31, 2014, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(0.5), $(0.5) and $(2.4), respectively. These amounts are reflected in current and noncurrent derivative assets and current and noncurrent derivative liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above. Effective with Electric Utility forward contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet (see Note 12).

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, 2015September 30, 2015, and December 31, 2014, were not material.

UGI Gas Base Rate Filing. On January 19, 2016, UGI Utilities filed a request with the PUC to increase UGI Gas base operating revenues for residential, commercial and industrial customers by $58.6 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. UGI Utilities is requesting that the new gas rates become effective March 19, 2016. However, 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 approximately nine months, however, the Company cannot predict the timing or the ultimate outcome of the rate case review process.

Note 7 — Energy Services Accounts Receivable Securitization Facility

Energy Services has an accounts receivable securitization facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2016. The Receivables Facility provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November through April and up to $75 of eligible receivables during the period May through October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.

Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, 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. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable.

During the three months ended December 31, 2015 and 2014, Energy Services transferred trade receivables to ESFC totaling $199.3 and $286.4, respectively. During the three months ended December 31, 2015 and 2014, ESFC sold an aggregate $61.5 and $105.0, respectively, of undivided interests in its trade receivables to the bank. At December 31, 2015, the outstanding balance of ESFC receivables was $55.4 of which $26.0 was sold to the bank. At December 31, 2014, the outstanding balance of ESFC receivables was $96.5 of which $43.0 was sold to the bank. Losses on sales of receivables to the bank during the three months

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

ended December 31, 2015 and 2014, which are included in interest expense on the Condensed Consolidated Statements of Income, were not material.

Note 8 — Debt
In October 2015, Flaga entered into a €100.8 Credit Facility Agreement (“Flaga Credit Facility Agreement”) with a bank. The Flaga Credit Facility Agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility, a €25 guarantee facility and a €45.8 variable-rate term loan facility. Borrowings under the Flaga Credit Facility Agreement’s €45.8 term loan facility were used to refinance its €19.1 term loan due October 2016 and its €26.7 term loan due August 2016. Concurrent with entering into the Flaga Credit Facility Agreement, Flaga terminated its then-existing €46 multi-currency working capital facility.
The Flaga Credit Facility Agreement revolving credit facility borrowings bear interest at market rates (generally one, three or six-month euribor rates) plus margins. The margins on revolving facility borrowings, which range from 1.45% to 3.65%, are based upon the actual currency borrowed and certain consolidated equity, return on assets and debt to EBITDA ratios, as defined in the Flaga Credit Facility Agreement. Facility fees on the unused amount of the revolving credit facility are 30% of the lowest applicable margin. The Flaga Credit Facility Agreement terminates in October 2020.
The €45.8 term loan matures in October 2020. The €45.8 term bears interest at three-month euribor rates, plus a margin. The margin on such borrowings ranges from 0.40% to 1.80% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined. Flaga has entered into pay-fixed, receive-variable interest rate swaps that generally fix the underlying euribor rate on the term loan borrowings at 2.18% through September 2016 and 0.23% from October 2016 through October 2020.
Because the cash flows associated with the refinancing of the then-existing term loans were with the same bank, such cash flows have been reflected “net” on the Condensed Consolidated Statement of Cash Flows.

Note 9 — Commitments and Contingencies

Environmental Matters

UGI Utilities

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA is scheduled to terminate at the end of 2018. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At December 31, 2015 and 2014, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11.7 and $11.2, respectively. We have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs, and (2) CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At December 31, 2015, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

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 its former subsidiaries. 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 former subsidiaries 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.

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 Corporation 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 its 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.  In July 2015, the Court dismissed all claims brought by direct customers and all claims other than those for injunctive relief brought by indirect customers.  The direct customers filed an appeal with the United States Court of Appeals for the Eighth Circuit, which is still pending. The indirect customers filed an amended complaint claiming injunctive relief and state law claims under Wisconsin, Maine and Vermont law. In January 2016, the District Court dismissed the remaining injunctive relief claims for the indirect purchasers. As a result, the only claims remaining with respect to indirect purchasers involve alleged violations of Wisconsin, Maine and Vermont state antitrust laws. 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 position, results of operations or cash flows.

Note 10 — 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 active employees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, UGI France employees are covered by certain defined benefit pension and postretirement plans.
 

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Net periodic pension expense and other postretirement benefit costs include the following components:
 
 
Pension Benefits
 
Other Postretirement Benefits
Three Months Ended December 31,
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
2.5

 
$
2.4

 
$
0.2

 
$
0.2

Interest cost
 
6.6

 
6.3

 
0.2

 
0.2

Expected return on assets
 
(8.0
)
 
(7.9
)
 
(0.2
)
 
(0.2
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
0.1

 
0.1

 
(0.1
)
 
(0.1
)
Actuarial loss
 
2.7

 
2.5

 

 

Net benefit cost
 
3.9

 
3.4

 
0.1

 
0.1

Change in associated regulatory liabilities
 

 

 
0.9

 
0.9

Net expense
 
$
3.9

 
$
3.4

 
$
1.0

 
$
1.0


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, smallcap common stocks and 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, 2015 and 2014, the Company made cash contributions to the U.S. Pension Plan of $2.5 and $2.8, respectively. The Company expects to make additional discretionary cash contributions of approximately $7.4 to the U.S. Pension Plan during the remainder of Fiscal 2016.

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, determined under GAAP. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates 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, 2015 and 2014.

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, 2015 and 2014 were not material.

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Note 11 — 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, 2015September 30, 2015 and December 31, 2014:  
 
 
Asset (Liability)
 
 
Level 1
 
Level 2
 
Level 3
 
Total
December 31, 2015:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
19.7

 
$
10.8

 
$

 
$
30.5

Foreign currency contracts
 
$

 
$
25.4

 
$

 
$
25.4

Interest rate contracts
 
$

 
$
0.6

 
$

 
$
0.6

Cross-currency swaps
 
$

 
$
1.9

 
$

 
$
1.9

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(70.5
)
 
$
(97.5
)
 
$

 
$
(168.0
)
Interest rate contracts
 
$

 
$
(9.8
)
 
$

 
$
(9.8
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
31.7

 
$

 
$

 
$
31.7

September 30, 2015:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
17.4

 
$
11.6

 
$

 
$
29.0

Foreign currency contracts
 
$

 
$
29.1

 
$

 
$
29.1

Cross-currency swaps
 
$

 
$
0.4

 
$

 
$
0.4

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(70.0
)
 
$
(99.0
)
 
$

 
$
(169.0
)
Foreign currency contracts
 
$

 
$
(0.1
)
 
$

 
$
(0.1
)
Interest rate contracts
 
$

 
$
(10.8
)
 
$

 
$
(10.8
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
30.3

 
$

 
$

 
$
30.3

December 31, 2014:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
14.1

 
$
26.1

 
$

 
$
40.2

Foreign currency contracts
 
$

 
$
18.7

 
$

 
$
18.7

Interest rate contracts
 
$

 
$
0.1

 
$

 
$
0.1

Cross-currency swaps
 
$

 
$
4.3

 
$

 
$
4.3

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(69.4
)
 
$
(228.5
)
 
$

 
$
(297.9
)
Interest rate contracts
 
$

 
$
(17.0
)
 
$

 
$
(17.0
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
31.4

 
$

 
$

 
$
31.4


(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

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

our derivative instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. 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. At December 31, 2015, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,609.3 and $3,590.4, respectively. At December 31, 2014, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,488.3 and $3,640.7, respectively. 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).

Financial instruments other than derivative instruments, such as our short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit our 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 12. 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 12 — 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.
 
Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units 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. At December 31, 2015 and 2014, total volumes associated with LPG commodity derivative instruments totaled 481.9 million gallons and 429.6 million gallons, respectively. At December 31, 2015, the maximum period over which we are economically hedging our exposure to LPG commodity price risk is 45 months.

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 purchased gas costs. 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. At December 31, 2015 and 2014, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 12.4 million dekatherms and 11.2 million dekatherms, respectively. At December 31, 2015, the maximum period over which Gas Utility is economically hedging natural gas market price

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

risk is 9 months. Gains and losses on natural gas futures contracts and any gains on 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 6).

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. For such contracts entered into by Electric Utility prior to March 1, 2015, Electric Utility chose not to elect the NPNS exception under GAAP related to these derivative instruments and the fair values of these contracts are reflected in current and noncurrent derivative instrument assets and liabilities in the accompanying Condensed Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Condensed Consolidated Balance Sheets in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet. At December 31, 2015 and 2014, the volumes of Electric Utility’s forward electricity purchase contracts were 333.3 million kilowatt hours and 486.2 million kilowatt hours, respectively. At December 31, 2015, the maximum period over which these contracts extend is 11 months.

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. 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. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). At December 31, 2015 and 2014, the total volumes associated with FTRs and NYISO capacity contracts totaled 223.7 million kilowatt hours and 331.8 million kilowatt hours, respectively. At December 31, 2015, the maximum period over which we are economically hedging electricity congestion and locational basis differences is 5 months.
In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures contracts, Intercontinental Exchange (“ICE”) natural gas basis swap contracts, and electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. 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 or propane. Because it could no longer assert the NPNS exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation, beginning in the second quarter of Fiscal 2014 Energy Services began recording these contracts at fair value with changes in fair value reflected in cost of sales.

At December 31, 2015 and 2014, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 104.9 million dekatherms and 127.8 million dekatherms, respectively. At December 31, 2015 and 2014, total volumes associated with Midstream & Marketing’s natural gas basis swap contracts totaled 86.1 million dekatherms and 37.1 million dekatherms, respectively. At December 31, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk is 39 months. At December 31, 2015 and 2014, total volumes associated with Midstream & Marketing’s electricity long forward and futures contracts and electricity short forward and futures contracts totaled 547.8 million kilowatt hours and 252.9 million kilowatt hours, and 350.0 million kilowatt hours and 184.1 million kilowatt hours, respectively. At December 31, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity commodity price risk (excluding Electric Utility) is 39 months for electricity call contracts and 37 months for electricity put contracts. At December 31, 2015, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 1.6 million dekatherms and 1.8 million gallons, respectively. At December 31, 2014, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 0.6 million dekatherms and 2.6 million gallons, respectively.
 
At December 31, 2015, there were no amounts remaining in AOCI related to commodity derivative hedges.

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Interest Rate Risk

UGI France’s and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. UGI France and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on their variable-rate term loans through the respective scheduled maturity dates. As of December 31, 2015 and 2014, the total notional amounts of variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) were €645.8 and €401.1, respectively.

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”). At December 31, 2015, the total notional amount of unsettled IRPAs was $290.0. At December 31, 2014, we had no unsettled IRPAs. Our December 31, 2015, unsettled IRPA contracts hedge forecasted interest payments expected to occur over ten- and thirty-year periods beginning in Fiscal 2016.

We account for interest rate swaps and IRPAs as cash flow hedges. At December 31, 2015, 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 approximately $2.2.

Foreign Currency Exchange Rate Risk

In order to reduce volatility, UGI France hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases during the heating-season months of October through March through the use of forward foreign currency exchange contracts. At December 31, 2015 and 2014, we were hedging a total of $280.5 and $225.8 of U.S. dollar-denominated LPG purchases, respectively. At December 31, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with U.S. dollar-denominated purchases of LPG is 39 months. From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At December 31, 2015 and 2014, we had no euro-denominated net investment hedges.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At December 31, 2015, the amount of net gains associated with currency rate risk expected to be reclassified into earnings during the next twelve months based upon current fair values is $16.0.

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 foreign currency and interest rate risk. 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 fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We designate these cross-currency swaps as cash flow hedges. At December 31, 2015 and 2014, cross-currency swaps were hedging foreign currency risk associated with interest and principal payments on $59.1 and $52.0 of Flaga U.S. dollar-denominated debt, respectively.

At December 31, 2015, the amount of net gains associated with this cross-currency swap expected to be reclassified into earnings during the next twelve months is not material.
 
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-

- 18 -

Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

traded futures contracts generally require cash deposits in margin accounts. At December 31, 2015 and 2014, restricted cash in brokerage accounts totaled $55.5 and $54.6, respectively. 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, 2015. 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, 2015, 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 our Condensed Consolidated Balance Sheets if the right of offset exists. 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 our Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.


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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Fair Value of Derivative Instruments
 
The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of December 31, 2015 and 2014:
 
 
December 31,
2015
 
December 31,
2014
Derivative assets:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Foreign currency contracts
 
$
25.4

 
$
18.7

Cross-currency contracts
 
1.9

 
4.3

Interest rate contracts
 
0.6

 
0.1

 
 
27.9

 
23.1

Derivatives subject to PGC and DS mechanisms:
 
 
 
 
Commodity contracts
 
0.2

 
0.2

Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 
30.3

 
40.0

Total derivative assets - gross
 
58.4

 
63.3

Gross amounts offset in the balance sheet
 
(15.6
)
 
(27.5
)
Total derivative assets - net
 
$
42.8

 
$
35.8

Derivative liabilities:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Interest rate contracts
 
$
(9.8
)
 
$
(17.0
)
Derivatives subject to PGC and DS mechanisms:
 
 
 
 
Commodity contracts
 
(6.3
)
 
(9.4
)
Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 
(161.7
)
 
(288.5
)
Total derivative liabilities - gross
 
(177.8
)
 
(314.9
)
Gross amounts offset in the balance sheet
 
15.6

 
27.5

Cash collateral pledged
 
5.5

 
90.5

Total derivative liabilities - net
 
$
(156.7
)
 
$
(196.9
)


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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Effect of Derivative Instruments

The following tables provide information on the effects of derivative instruments in the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three months ended December 31, 2015 and 2014:
 
 
Gain (Loss)
Recognized in
AOCI
 
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of Gain (Loss) Reclassified from
AOCI and Noncontrolling
Interests into Income
Three Months Ended December 31,
 
2015
 
2014
 
2015
 
2014
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$

 
$

 
$

 
$
(2.4
)
 
Cost of sales
Foreign currency contracts
 
5.4

 
8.7

 
9.1

 
2.7

 
Cost of sales
Cross-currency contracts
 

 
2.1

 

 

 
Interest expense/other operating income, net
Interest rate contracts
 
5.6

 
0.8

 
(0.6
)
 
(3.9
)
 
Interest expense
Total
 
$
11.0

 
$
11.6

 
$
8.5

 
$
(3.6
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
 
 
Three Months Ended December 31,
 
2015
 
2014
 
 
 
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(46.2
)
 
$
(292.5
)
 
Cost of sales
 
 
Commodity contracts
 
1.6

 
3.8

 
Revenues
 
 
Commodity contracts
 
(0.1
)
 
(0.5
)
 
Operating expenses/other
operating income, net
 
 
Total
 
$
(44.7
)
 
$
(289.2
)
 
 
 
 
 
 

For the three months ended December 31, 2015, the amount of derivative gains or losses representing ineffectiveness, and the amount of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, was a loss of $3.4 which amount is recorded in other operating income, net, on the Condensed Consolidated Statements of Income and is related to interest rate contracts at UGI France. For the three months ended December 31, 2014, the amount of derivative gains or losses representing ineffectiveness, and the amount of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, was 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 many of these contracts have the requisite elements of a derivative instrument, certain of these contracts qualify for NPNS exception accounting under GAAP 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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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Note 13 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI during the three months ended December 31, 2015 and 2014:

 
 
 
 
 
 
 
 
 
Three Months Ended December 31, 2015
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - September 30, 2015
 
$
(20.4
)
 
$
11.2

 
$
(105.4
)
 
$
(114.6
)
Other comprehensive income (loss) before reclassification adjustments (after-tax)
 

 
6.8

 
(30.2
)
 
(23.4
)
Amounts reclassified from AOCI:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.7

 
(8.5
)
 

 
(7.8
)
Reclassification adjustments tax expense
 
(0.3
)
 
3.2

 

 
2.9

Reclassification adjustments (after-tax)
 
0.4

 
(5.3
)
 

 
(4.9
)
Other comprehensive income (loss) attributable to UGI
 
0.4

 
1.5

 
(30.2
)
 
(28.3
)
AOCI - December 31, 2015
 
$
(20.0
)
 
$
12.7

 
$
(135.6
)
 
$
(142.9
)
 
 
 
 
 
 
 
 
 
Three Months Ended December 31, 2014
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency (a)
 
Total
AOCI - September 30, 2014
 
$
(20.6
)
 
$
(9.3
)
 
$
8.7

 
$
(21.2
)
Other comprehensive income (loss) before reclassification adjustments (after-tax)
 

 
7.7

 
(30.5
)
 
(22.8
)
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
1.0

 
3.6

 

 
4.6

Reclassification adjustments tax benefit
 
(0.4
)
 
(1.5
)
 

 
(1.9
)
Reclassification adjustments (after-tax)
 
0.6

 
2.1

 

 
2.7

Other comprehensive income (loss)
 
0.6

 
9.8

 
(30.5
)
 
(20.1
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 

 
1.2

 

 
1.2

Other comprehensive income (loss) attributable to UGI
 
0.6

 
11.0

 
(30.5
)
 
(18.9
)
AOCI - December 31, 2014
 
$
(20.0
)
 
$
1.7

 
$
(21.8
)
 
$
(40.1
)

(a)
See Note 2 relating to correction of prior period error in other comprehensive income.
For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 12.

Note 14 — Segment Information

Our operations comprise six reportable segments generally based upon products sold, geographic location and regulatory environment. As more fully described below, effective October 1, 2015, the composition of our UGI Utilities (formerly Gas Utility) and Energy Services reportable segments changed to include certain operating segments previously included in Corporate & Other. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising UGI France; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) UGI Utilities; (5) Energy Services; and (6) Electric Generation. We refer to both international segments together as “UGI International” and Energy Services and Electric Generation together as “Midstream & Marketing.”


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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

As a result of changes in the composition of information reported to our chief operating decision maker (“CODM”) associated with our regulated utility operations, effective October 1, 2015, we began including our Electric Utility operating segment with our Gas Utility reportable segment now referred to as “UGI Utilities.” Also, as a result of changes in segment management and reporting for HVAC, effective October 1, 2015, we began including HVAC operating segment within our Energy Services reportable segment. Previously, these two business units, neither of which meet the quantitative threshold for presentation as a reportable segment under GAAP, were included within “Corporate & Other” in our segment information. In accordance with GAAP, prior-period amounts for these reportable segments have been restated to reflect these changes.

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 2015 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 net gains and losses on commodity derivative instruments not associated with current-period transactions (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies. We evaluate the performance of our other reportable segments principally based upon their income before income taxes as adjusted for gains and losses on commodity derivative instruments not associated with current-period transactions. Net gains and losses on commodity derivative instruments not associated with current-period transactions are reflected in Corporate & Other because the Company’s CODM does not consider such items when evaluating the financial performance of our reportable segments.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
UGI
Utilities
 
Energy
Services
 
Electric
Generation
 
UGI France
 
Flaga &
Other
 
Corporate
& Other (b)
Three Months Ended
December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
1,606.6

 
$
(45.4
)
(c)
$
644.1

 
$
198.0

 
$
214.8

 
$
14.8

 
$
408.7

 
$
169.5

 
$
2.1

Cost of sales
 
$
734.0

 
$
(44.5
)
(c)
$
243.2

 
$
75.4

 
$
151.2

 
$
6.0

 
$
192.6

 
$
110.2

 
$
(0.1
)
Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
305.5

 
$
0.1

 
$
129.6

 
$
48.3

 
$
41.3

 
$
1.6

 
$
68.7

 
$
16.4

 
$
(0.5
)
Loss from equity investees
 
(0.1
)
 

 

 

 

 

 
(0.1
)
 

 

Interest expense
 
(57.9
)
 

 
(41.0
)
 
(9.5
)
 
(0.8
)
 

 
(5.6
)
 
(0.9
)
 
(0.1
)
Income (loss) before income taxes
 
$
247.5

 
$
0.1

 
$
88.6

 
$
38.8

 
$
40.5

 
$
1.6

 
$
63.0

 
$
15.5

 
$
(0.6
)
Partnership Adjusted EBITDA (a)
 

 
 
 
$
177.7

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
53.3

 
$

 
$
57.3

 
$

 
$

 
$

 
$
0.1

 
$

 
$
(4.1
)
Depreciation and amortization
 
$
100.6

 
$

 
$
49.2

 
$
16.7

 
$
4.1

 
$
3.3

 
$
21.6

 
$
5.6

 
$
0.1

Capital expenditures
 
$
132.9

 
$

 
$
28.0

 
$
61.5

 
$
21.9

 
$
0.5

 
$
16.3

 
$
4.7

 
$

As of December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
10,780.4

 
$
(106.2
)
 
$
4,242.6

 
$
2,606.3

 
$
721.0

 
$
279.0

 
$
2,378.9

 
$
534.8

 
$
124.0

Short-term borrowings
 
$
456.8

 
$

 
$
182.0

 
$
217.7

 
$
56.0

 
$

 
$
1.1

 
$

 
$

Goodwill
 
$
2,965.1

 
$

 
$
1,971.3

 
$
182.1

 
$
11.5

 
$

 
$
700.9

 
$
99.3

 
$


- 23 -

Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)


 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
UGI
Utilities
 
Energy
Services
 
Electric
Generation
 
UGI France
 
Flaga &
Other
 
Corporate
& Other (b)
Three Months Ended
December 31, 2014 (d)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
2,004.6

 
$
(67.7
)
(c)
$
888.8

 
$
287.3

 
$
314.1

 
$
16.5

 
$
337.9

 
$
224.6

 
$
3.1

Cost of sales
 
$
1,404.6

 
$
(67.0
)
(c)
$
462.4

 
$
143.1

 
$
244.6

 
$
8.0

 
$
209.3

 
$
172.6

 
$
231.6

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
83.3

 
$

 
$
139.7

 
$
75.6

 
$
46.3

 
$
(0.7
)
 
$
38.4

 
$
15.1

 
$
(231.1
)
Loss from equity investees
 
(1.0
)
 

 

 

 

 

 
(1.0
)
 

 

Interest expense
 
(59.0
)
 

 
(41.0
)
 
(10.6
)
 
(0.6
)
 

 
(5.6
)
 
(1.0
)
 
(0.2
)
Income (loss) before income taxes
 
$
23.3

 
$

 
$
98.7

 
$
65.0

 
$
45.7

 
$
(0.7
)
 
$
31.8

 
$
14.1

 
$
(231.3
)
Partnership EBITDA (a)
 
 
 
 
 
$
188.5

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income (loss)
 
$
(33.9
)
 
$

 
$
66.8