UGI CORP /PA/, 10-Q filed on 5/8/2015
Quarterly Report
Document and Entity Information
6 Months Ended
Mar. 31, 2015
Apr. 30, 2015
Document and Entity Information [Abstract]
 
 
Entity Registrant Name
UGI CORP /PA/ 
 
Entity Central Index Key
0000884614 
 
Document Type
10-Q 
 
Document Period End Date
Mar. 31, 2015 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2015 
 
Document Fiscal Period Focus
Q2 
 
Current Fiscal Year End Date
--09-30 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
172,497,596 
Condensed Consolidated Balance Sheets (unaudited) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Sep. 30, 2014
Mar. 31, 2014
Current assets:
 
 
 
Cash and cash equivalents
$ 445.5 
$ 419.5 
$ 493.6 
Restricted cash
56.7 
16.6 
4.4 
Accounts receivable (less allowances for doubtful accounts of $42.7, $39.1 and $57.9, respectively)
1,046.0 
684.7 
1,323.3 
Accrued utility revenues
42.1 
14.3 
49.7 
Inventories
201.5 
423.0 
324.4 
Deferred income taxes
49.6 
10.1 
10.8 
Utility regulatory assets
0.6 
13.2 
4.2 
Derivative instruments
33.1 
14.5 
22.2 
Prepaid expenses and other current assets
83.9 
67.1 
48.5 
Total current assets
1,959.0 
1,663.0 
2,281.1 
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,691.0, $2,633.0 and $2,637.8, respectively)
4,486.3 
4,543.7 
4,519.1 
Goodwill
2,731.2 
2,833.4 
2,886.0 
Intangible assets, net
537.5 
576.4 
608.2 
Derivative instruments
20.9 
12.5 
0.8 
Other assets
447.8 
464.0 
425.3 
Total assets
10,182.7 
10,093.0 
10,720.5 
Current liabilities:
 
 
 
Current maturities of long-term debt
470.5 
77.2 
65.0 
Short-term borrowings
89.9 
210.8 
260.1 
Accounts payable
440.8 
459.8 
634.1 
Derivative instruments
129.0 
40.2 
27.5 
Other current liabilities
719.5 
642.9 
668.6 
Total current liabilities
1,849.7 
1,430.9 
1,655.3 
Long-term debt
2,958.2 
3,433.6 
3,548.6 
Deferred income taxes
942.0 
1,005.1 
984.4 
Deferred investment tax credits
3.8 
3.9 
4.1 
Derivative instruments
34.3 
16.6 
29.2 
Other noncurrent liabilities
511.0 
539.7 
496.8 
Total liabilities
6,299.0 
6,429.8 
6,718.4 
Commitments and contingencies (Note 9)
   
   
   
UGI Corporation stockholders’ equity:
 
 
 
UGI Common Stock, without par value (authorized—450,000,000 shares; issued—173,788,741, 173,770,641 and 173,729,541 shares, respectively)
1,215.0 
1,215.6 
1,215.6 
Retained earnings
1,715.0 
1,509.4 
1,579.9 
Accumulated other comprehensive (loss) income
(85.4)
(21.2)
24.3 
Treasury stock, at cost
(41.6)
(44.7)
(24.6)
Total UGI Corporation stockholders’ equity
2,803.0 
2,659.1 
2,795.2 
Noncontrolling interests, principally in AmeriGas Partners
1,080.7 
1,004.1 
1,206.9 
Total equity
3,883.7 
3,663.2 
4,002.1 
Total liabilities and equity
$ 10,182.7 
$ 10,093.0 
$ 10,720.5 
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Mar. 31, 2015
Sep. 30, 2014
Mar. 31, 2014
Statement of Financial Position [Abstract]
 
 
 
Accounts receivable, allowances for doubtful accounts
$ 42.7 
$ 39.1 
$ 57.9 
Property, plant and equipment, accumulated depreciation and amortization
$ 2,691.0 
$ 2,633.0 
$ 2,637.8 
UGI Common Stock, without par value (in shares)
   
   
   
UGI Common Stock, without par value, shares authorized (in shares)
450,000,000 
450,000,000 
450,000,000 
UGI Common Stock, without par value, shares issued (in shares)
173,788,741 
173,770,641 
173,729,541 
Condensed Consolidated Statements of Income (unaudited) (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Income Statement [Abstract]
 
 
 
 
Revenues
$ 2,455.6 
$ 3,163.3 
$ 4,460.2 
$ 5,479.2 
Costs and expenses:
 
 
 
 
Cost of sales (excluding depreciation shown below)
1,205.4 
2,001.3 
2,610.0 
3,431.2 
Operating and administrative expenses
466.6 
492.0 
902.3 
923.5 
Utility taxes other than income taxes
4.8 
4.8 
8.9 
9.0 
Depreciation
73.8 
76.8 
149.6 
155.4 
Amortization
14.2 
10.9 
29.4 
26.3 
Other operating income, net
(11.3)
(11.1)
(25.4)
(18.5)
Total costs and expenses
1,753.5 
2,574.7 
3,674.8 
4,526.9 
Operating income
702.1 
588.6 
785.4 
952.3 
Loss from equity investees
(0.1)
0 
(1.1)
0 
Interest expense
(58.2)
(59.5)
(117.2)
(118.8)
Income before income taxes
643.8 
529.1 
667.1 
833.5 
Income tax expense
(161.6)
(141.3)
(184.7)
(228.2)
Net income
482.2 
387.8 
482.4 
605.3 
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners
(235.7)
(173.4)
(201.8)
(268.9)
Net income attributable to UGI Corporation
$ 246.5 
$ 214.4 
$ 280.6 
$ 336.4 
Earnings per common share attributable to UGI Corporation stockholders:
 
 
 
 
Basic (in dollars per share)
$ 1.42 
$ 1.24 
$ 1.62 
$ 1.95 
Diluted (in dollars per share)
$ 1.40 
$ 1.22 
$ 1.60 
$ 1.92 
Average common shares outstanding (thousands):
 
 
 
 
Basic (in shares)
173,154 
172,760 
173,055 
172,494 
Diluted (in shares)
175,628 
175,121 
175,715 
174,789 
Dividends declared per common share (in dollars per share)
$ 0.2175 
$ 0.1883 
$ 0.4350 
$ 0.3767 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net income
$ 482.2 
$ 387.8 
$ 482.4 
$ 605.3 
Other comprehensive income (loss):
 
 
 
 
Net gains on derivative instruments (net of tax of $(10.4), $0.4, $(14.3) and $(7.1), respectively)
20.2 
6.3 
27.9 
46.8 
Reclassifications of net losses (gains) on derivative instruments (net of tax of $1.1, $3.3, $(0.4) and $5.3, respectively)
(1.9)
(31.4)
0.2 
(45.2)
Foreign currency adjustments (net of tax of $35.0, $0.6, $50.6 and $(3.1), respectively)
(64.5)
(0.6)
(95.0)
11.7 
Benefit plans (net of tax of $(0.2), $(0.1), $(0.6) and $0.0, respectively)
0.4 
0.2 
1.0 
0.6 
Other comprehensive (loss) income
(45.8)
(25.5)
(65.9)
13.9 
Comprehensive income
436.4 
362.3 
416.5 
619.2 
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners
(235.1)
(155.8)
(200.1)
(266.9)
Comprehensive income attributable to UGI Corporation
$ 201.3 
$ 206.5 
$ 216.4 
$ 352.3 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
 
 
 
 
Tax on (loss) gain on derivative instruments
$ (10.4)
$ 0.4 
$ (14.3)
$ (7.1)
Tax on reclassification on derivative instruments
1.1 
3.3 
(0.4)
5.3 
Tax on foreign currency adjustments
35.0 
0.6 
50.6 
(3.1)
Tax on benefit plans
$ (0.2)
$ (0.1)
$ (0.6)
$ 0 
Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 482.4 
$ 605.3 
Adjustments to reconcile net income to net cash from operating activities:
 
 
Depreciation and amortization
179.0 
181.7 
Deferred income tax (benefit) expense, net
(33.7)
13.0 
Provision for uncollectible accounts
20.7 
31.4 
Unrealized losses on derivative instruments
125.2 
8.0 
Other, net
7.0 
(6.8)
Net change in:
 
 
Accounts receivable and accrued utility revenues
(469.7)
(632.5)
Inventories
208.0 
43.0 
Utility deferred fuel and power costs, net of changes in unsettled derivatives
55.8 
(10.2)
Accounts payable
31.8 
194.1 
Other current assets
(8.3)
3.6 
Other current liabilities
59.6 
52.4 
Net cash provided by operating activities
657.8 
483.0 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Expenditures for property, plant and equipment
(233.5)
(224.4)
Acquisitions of businesses, net of cash acquired
(7.3)
(21.3)
(Increase) decrease in restricted cash
(40.1)
3.9 
Other, net
15.1 
4.5 
Net cash used by investing activities
(265.8)
(237.3)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Dividends on UGI Common Stock
(75.0)
(64.8)
Distributions on AmeriGas Partners publicly held Common Units
(121.7)
(116.1)
Issuances of debt
0 
175.1 
Repayments of debt
(6.9)
(182.8)
(Decrease) increase in short-term borrowings
(112.2)
51.5 
Receivables Facility net repayments
(7.5)
(19.5)
Issuances of UGI Common Stock
5.0 
10.3 
Repurchases of UGI Common Stock
(17.3)
(4.5)
Other
(2.3)
5.4 
Net cash used by financing activities
(337.9)
(145.4)
EFFECT OF EXCHANGE RATE CHANGES ON CASH
(28.1)
4.0 
Cash and cash equivalents increase
26.0 
104.3 
Cash and cash equivalents:
 
 
End of period
445.5 
493.6 
Beginning of period
$ 419.5 
$ 389.3 
Condensed Consolidated Statements of Changes in Equity (unaudited) (USD $)
In Millions, unless otherwise specified
Total
Parent
Common Stock, Without Par Value
Retained Earnings
Accumulated Other Comprehensive (Loss) Income
Treasury Stock
Noncontrolling Interests
Balance, beginning of period at Sep. 30, 2013
 
 
$ 1,208.1 
$ 1,308.3 
$ 8.4 
$ (32.3)
$ 1,055.4 
Increase (Decrease) in Stockholders' Equity
 
 
 
 
 
 
 
Common Stock issued in connection with employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld
 
 
(5.2)
 
 
 
 
Excess tax benefits realized on equity-based compensation
 
 
5.9 
 
 
 
 
Equity-based compensation expense
 
 
6.8 
 
 
 
 
Net income
605.3 
 
 
336.4 
 
 
268.9 
Cash dividends on Common Stock
 
 
 
(64.8)
 
 
 
Net gains on derivative instruments, net of tax
46.8 
 
 
 
13.5 
 
 
Reclassification of net losses (gains) on derivative instruments, net of tax
(45.2)
 
 
 
(9.9)
 
 
Benefit plans, net of tax
0.6 
 
 
 
0.6 
 
 
Foreign currency, net of tax
11.7 
 
 
 
11.7 
 
 
Common stock issued in connection with employee and director plans, net of tax withheld
 
 
 
 
 
29.9 
 
Repurchases of Common Stock
 
 
 
 
 
(4.5)
 
Reacquired common stock - employee and director plans
 
 
 
 
 
(17.7)
 
Net gains on derivative instruments
 
 
 
 
 
 
33.3 
Reclassification of net gains on derivative instruments
 
 
 
 
 
 
(35.3)
Dividends and distributions
 
 
 
 
 
 
(116.1)
Other
 
 
 
 
 
 
0.7 
Balance, end of period at Mar. 31, 2014
4,002.1 
2,795.2 
1,215.6 
1,579.9 
24.3 
(24.6)
1,206.9 
Balance, beginning of period at Sep. 30, 2014
3,663.2 
 
1,215.6 
1,509.4 
(21.2)
(44.7)
1,004.1 
Increase (Decrease) in Stockholders' Equity
 
 
 
 
 
 
 
Common Stock issued in connection with employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld
 
 
(15.1)
 
 
 
 
Excess tax benefits realized on equity-based compensation
 
 
5.0 
 
 
 
 
Equity-based compensation expense
 
 
9.5 
 
 
 
 
Net income
482.4 
 
 
280.6 
 
 
201.8 
Cash dividends on Common Stock
 
 
 
(75.0)
 
 
 
Net gains on derivative instruments, net of tax
27.9 
 
 
 
27.9 
 
 
Reclassification of net losses (gains) on derivative instruments, net of tax
0.2 
 
 
 
1.9 
 
 
Benefit plans, net of tax
1.0 
 
 
 
1.0 
 
 
Foreign currency, net of tax
(95.0)
 
 
 
(95.0)
 
 
Common stock issued in connection with employee and director plans, net of tax withheld
 
 
 
 
 
24.7 
 
Repurchases of Common Stock
 
 
 
 
 
(17.3)
 
Reacquired common stock - employee and director plans
 
 
 
 
 
(4.3)
 
Net gains on derivative instruments
 
 
 
 
 
 
0 
Reclassification of net gains on derivative instruments
 
 
 
 
 
 
(1.7)
Dividends and distributions
 
 
 
 
 
 
(122.2)
Other
 
 
 
 
 
 
(1.3)
Balance, end of period at Mar. 31, 2015
$ 3,883.7 
$ 2,803.0 
$ 1,215.0 
$ 1,715.0 
$ (85.4)
$ (41.6)
$ 1,080.7 
Nature of Operations
Nature of Operations
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” or “we.”

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 March 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 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises 69,131,947 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, 2014 (the “Company’s 2014 Annual Report”). Incentive distributions received by the General Partner during the six months ended March 31, 2015 and 2014 were $13.1 and $10.8, respectively.

Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“Antargaz”); (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.

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.”
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Note 2 — Summary of Significant Accounting Policies

Our condensed consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the public’s limited partner interests in the Partnership, and outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests. We eliminate intercompany accounts and transactions when we consolidate. Entities in which we do not have control but have significant influence over operating and financial policies are accounted for by the equity method. Investments in business entities that are not publicly traded and in which we hold less than 20% of voting rights are accounted for using the cost method. Undivided interests in natural gas production assets and an electricity generation facility are consolidated on a proportionate basis.

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, 2014, 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 2014 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
 
Shares used in computing basic and diluted earnings per share are as follows: 
 
 
Three Months Ended
March 31,
 
Six Months Ended
March 31,
 
 
2015
 
2014
 
2015
 
2014
Denominator (thousands of shares):
 
 
 
 
 
 
 
 
Average common shares outstanding for basic computation
 
173,154

 
172,760

 
173,055

 
172,494

Incremental shares issuable for stock options and awards
 
2,474

 
2,361

 
2,660

 
2,295

Average common shares outstanding for diluted computation
 
175,628

 
175,121

 
175,715

 
174,789



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 the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on certain 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 that on a prospective basis 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. For additional information on our derivative instruments, 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.
Accounting Changes
Accounting Changes
Note 3 — Accounting Changes

Accounting Standards Not Yet Adopted

Consolidation. In February 2015, the Financial Accounting Standards Board (“FASB”) issued new guidance regarding whether a reporting entity should consolidate certain types of legal entities. Among other things, 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.

Debt Issuance Costs. In April 2015, the 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. Early adoption is permitted. Entities would apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2015.

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 Accounting Standards Codification (“ASC”) 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 company 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, 2017 (Fiscal 2018) and allows for either full retrospective adoption or modified retrospective adoption. On April 29, 2015, the FASB issued for public comment a proposal to delay the effective date by one year. The Company is in the process of assessing the impact of the adoption of ASU 2014-09 on its results of operations, cash flows and financial position.
Inventories
Inventories
Note 4 — Inventories

Inventories comprise the following: 
 
 
March 31,
2015
 
September 30,
2014
 
March 31,
2014
Non-utility LPG and natural gas
 
$
135.8

 
$
283.6

 
$
251.4

Gas Utility natural gas
 
6.3

 
82.7

 
7.5

Materials, supplies and other
 
59.4

 
56.7

 
65.5

Total inventories
 
$
201.5

 
$
423.0

 
$
324.4



At March 31, 2015, UGI Utilities is a party to three 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 March 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 non-affiliates at March 31, 2015, September 30, 2014 and March 31, 2014, comprising 0.2 billion cubic feet (“bcf”), 3.9 bcf and 0.2 bcf of natural gas, was $0.7, $16.8 and $0.8, respectively.
Goodwill and Intangible Assets
Goodwill and Intangible Assets
Note 5 — Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following: 
 
 
March 31,
2015
 
September 30,
2014
 
March 31,
2014
Goodwill (not subject to amortization)
 
$
2,731.2

 
$
2,833.4

 
$
2,886.0

Intangible assets:
 
 
 
 
 
 
Customer relationships, noncompete agreements and other
 
$
670.2

 
$
712.0

 
$
727.5

Accumulated amortization
 
(254.1
)
 
(263.8
)
 
(251.6
)
Intangible assets, net (definite-lived)
 
416.1

 
448.2

 
475.9

Trademarks and tradenames (indefinite-lived)
 
121.4

 
128.2

 
132.3

Total intangible assets, net
 
$
537.5

 
$
576.4

 
$
608.2


The decrease in goodwill and intangible assets at March 31, 2015, includes the effects of currency translation. Amortization expense of intangible assets was $12.0 and $25.0 for the three and six months ended March 31, 2015, respectively. Amortization expense of intangible assets was $8.9 and $22.2 for the three and six months ended March 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 2015 and for the next four fiscal years is as follows: remainder of Fiscal 2015 — $24.7; Fiscal 2016 — $44.3; Fiscal 2017 — $38.1; Fiscal 2018 — $36.4; Fiscal 2019 — $34.8.
Utility Regulatory Assets and Liabilities and Regulatory Matters
Utility Regulatory Assets and Liabilities and Regulatory Matters
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 2014 Annual Report. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Utilities are included in our accompanying Condensed Consolidated Balance Sheets:
 
 
March 31,
2015
 
September 30,
2014
 
March 31,
2014
Regulatory assets (a):
 
 
 
 
 
 
Income taxes recoverable
 
$
111.5

 
$
110.7

 
$
106.8

Underfunded pension and postretirement plans
 
105.5

 
110.1

 
91.0

Environmental costs
 
14.1

 
14.6

 
14.5

Deferred fuel and power costs
 
—

 
11.8

 
4.3

Removal costs, net
 
18.4

 
16.8

 
14.4

Other
 
3.1

 
4.2

 
4.9

Total regulatory assets
 
$
252.6

 
$
268.2

 
$
235.9

Regulatory liabilities (a):
 
 
 
 
 
 
Postretirement benefits
 
$
19.3

 
$
18.6

 
$
17.2

Environmental overcollections
 
—

 
0.3

 
1.9

Deferred fuel and power refunds
 
40.6

 
0.3

 
3.2

State tax benefits—distribution system repairs
 
10.6

 
10.1

 
9.0

Other
 
2.1

 
3.2

 
1.8

Total regulatory liabilities
 
$
72.6

 
$
32.5

 
$
33.1



(a) Noncurrent regulatory assets are recorded in other assets and 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 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 March 31, 2015, September 30, 2014 and March 31, 2014 were $(3.4), $(1.4) and $2.4, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. We have chosen not to elect the NPNS exception under GAAP related to these derivative instruments for all forward electricity purchase contracts entered into prior to March 1, 2015. These electricity supply contracts are recognized on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At March 31, 2015, September 30, 2014, and March 31, 2014, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(1.2), $0.3 and $0.4, 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 electricity purchase contracts entered into beginning March 1, 2015, Electric Utility will elect the NPNS exception under GAAP and, as a result, the fair values of such contracts will not be 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 March 31, 2015, September 30, 2014, and March 31, 2014, were not material.
Energy Services Accounts Receivable Securitization Facility
Energy Services Accounts Receivable Securitization Facility
Note 7 — Energy Services Accounts Receivable Securitization Facility

Energy Services has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2015. The Receivables Facility provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November to May and up to $75 of eligible receivables during the period June to 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 or the commercial paper conduit. The Company records interest expense on amounts owed to the bank or the commercial paper conduit. Energy Services continues to service, administer and collect trade receivables on behalf of the bank or commercial paper issuer, as applicable.

During the six months ended March 31, 2015 and 2014, Energy Services transferred trade receivables to ESFC totaling $692.0 and $820.7, respectively. During the six months ended March 31, 2015 and 2014, ESFC sold an aggregate $216.5 and $251.0, respectively, of undivided interests in its trade receivables to the bank. At March 31, 2015, the outstanding balance of ESFC receivables was $96.9 and there were no amounts sold to the bank. At March 31, 2014, the outstanding balance of ESFC receivables was $124.1 of which $10.5 was sold to the bank. Losses on sales of receivables to the bank during the six months ended March 31, 2015 and 2014, which are included in interest expense on the Condensed Consolidated Statements of Income, were not material.
Debt
Debt
Note 8 — Debt

On March 27, 2015, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2015 Credit Agreement”) with a group of banks providing for borrowings up to $300 (including a $100 sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2015 Credit Agreement, UGI Utilities terminated its then-existing $300 revolving credit agreement dated as of May 25, 2011. Under the UGI Utilities 2015 Credit Agreement, 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 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2015 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.0. The UGI Utilities 2015 Credit Agreement is currently scheduled to expire in March 2016, but may be extended by UGI Utilities to March 2020 if on or before March 25, 2016, the Company satisfies certain requirements relating to approval by the PUC. The Company intends to seek such regulatory approval.
In anticipation of the Company’s pending acquisition of Total’s retail LPG distribution business in France (“Totalgaz”) expected to occur during the third quarter of Fiscal 2015, on April 30, 2015, UGI France, an indirect wholly owned subsidiary of UGI, entered into a new Senior Facilities Agreement with a consortium of banks (the “2015 Senior Facilities Agreement”) having a final maturity date of April 30, 2020. UGI France expects to draw under the Senior Facilities Agreement substantially concurrent with the closing of the pending Totalgaz acquisition. The 2015 Senior Facilities Agreement, when drawn, will consist of a €600 variable-rate term loan and also a €60 revolving credit facility. The term loan proceeds from the 2015 Senior Facilities Agreement will be used to (1) fund a portion of the acquisition of Totalgaz, including related fees and expenses; (2) prepay €342 principal amount, plus accrued interest, outstanding under Antargaz’ 2011 Senior Facilities Agreement due March 2016 (the “2011 Senior Facilities Agreement”); (3) settle Antargaz’ existing pay-fixed, receive-variable interest rate swaps associated with the 2011 Senior Facilities Agreement; and (4) for general corporate purposes. As of March 31, 2015, the fair value of the interest rate swaps was a loss of $10.3. UGI France does not intend to draw on either the term loan or the revolving credit facility until the closing date of the Totalgaz acquisition, which is required to occur no later than June 30, 2015, pursuant to the terms of the 2015 Senior Facilities Agreement.
Borrowings under the 2015 Senior Facilities Agreement €600 term loan and the €60 revolving credit facility will bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate. The margin on such borrowings (which ranges from 1.60% to 2.70% for the term loan, and 1.45% to 2.55% for the revolving credit facility) will be dependent upon the ratio of UGI France’s consolidated total net debt to earnings before interest expense, income taxes, depreciation, and amortization (“EBITDA”), each as defined in the 2015 Senior Facilities Agreement. UGI France expects to enter into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan.
Principal amounts to be outstanding under the 2015 Senior Facilities Agreement term loan will be due as follows: €60 due April 30, 2018; €60 due April 30, 2019; and €480 million due April 30, 2020.The 2015 Senior Facilities Agreement restricts the ability of UGI France to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires UGI France and its consolidated subsidiaries to maintain a ratio of total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement, that shall not exceed (a) 3.75 to 1.00 from the closing date of the pending Totalgaz acquisition to September 30, 2015, and (b) 3.50 to 1.00 from October 1, 2015, to the final maturity date. UGI France will generally be permitted to make restricted payments, such as dividends, if no event of default exists or would exist upon payment of such dividend.
Commitments and Contingencies
Commitments and Contingencies
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 March 31, 2015 and 2014, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $9.6 and $11.1, 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. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, 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 are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At March 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 Western District of Missouri.  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 consolidated financial position, results of operations or cash flows.
Defined Benefit Pension and Other Postretirement Plans
Defined Benefit Pension and Other Postretirement Plans
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, Antargaz employees 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 March 31,
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
2.5

 
$
2.3

 
$
0.1

 
$
0.1

Interest cost
 
6.3

 
6.5

 
0.2

 
0.2

Expected return on assets
 
(8.0
)
 
(7.3
)
 
(0.1
)
 
(0.1
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
0.1

 
0.1

 
(0.1
)
 
(0.1
)
Actuarial loss
 
2.5

 
1.9

 
—

 
—

Net benefit cost
 
3.4

 
3.5

 
0.1

 
0.1

Change in associated regulatory liabilities
 
—

 
—

 
1.0

 
0.9

Net expense
 
$
3.4

 
$
3.5

 
$
1.1

 
$
1.0

 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
Six Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
4.9

 
$
4.7

 
$
0.3

 
$
0.3

Interest cost
 
12.6

 
12.9

 
0.4

 
0.5

Expected return on assets
 
(15.9
)
 
(14.7
)
 
(0.3
)
 
(0.3
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
0.2

 
0.2

 
(0.2
)
 
(0.2
)
Actuarial loss
 
5.0

 
3.8

 
—

 
—

Net benefit cost
 
6.8

 
6.9

 
0.2

 
0.3

Change in associated regulatory liabilities
 
—

 
—

 
1.9

 
1.8

Net expense
 
$
6.8

 
$
6.9

 
$
2.1

 
$
2.1



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, 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 six months ended March 31, 2015 and 2014, the Company made cash contributions to the U.S. Pension Plan of $5.6 and $7.0, respectively. The Company expects to make additional discretionary cash contributions of approximately $5.6 to the U.S. Pension Plan during the remainder of Fiscal 2015.

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 six months ended March 31, 2015 and 2014.

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans (“Supplemental Defined Benefit Plans”). We recorded pre-tax expense associated with these plans of $0.6 and $0.9 in the three months ended March 31, 2015 and 2014, respectively. We recorded pre-tax expense associated with these plans of $1.3 and $1.7 in the six months ended March 31, 2015 and 2014, respectively.
Fair Value Measurements
Fair Value Measurements
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 March 31, 2015, September 30, 2014 and March 31, 2014:  
 
 
Asset (Liability)
 
 
Level 1
 
Level 2
 
Level 3
 
Total
March 31, 2015:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
13.9

 
$
8.3

 
$
—

 
$
22.2

Foreign currency contracts
 
$
—

 
$
35.8

 
$
—

 
$
35.8

Interest rate contracts
 
$
—

 
$
0.1

 
$
—

 
$
0.1

Cross-currency swaps
 
$
—

 
$
9.7

 
$
—

 
$
9.7

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(64.0
)
 
$
(104.3
)
 
$
—

 
$
(168.3
)
Interest rate contracts
 
$
—

 
$
(12.5
)
 
$
—

 
$
(12.5
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
31.8

 
$
—

 
$
—

 
$
31.8

September 30, 2014:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
10.6

 
$
19.8

 
$
—

 
$
30.4

Foreign currency contracts
 
$
—

 
$
12.8

 
$
—

 
$
12.8

Interest rate contracts
 
$
—

 
$
0.1

 
$
—

 
$
0.1

Cross-currency swaps
 
$
—

 
$
2.1

 
$
—

 
$
2.1

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(21.2
)
 
$
(32.9
)
 
$
—

 
$
(54.1
)
Foreign currency contracts
 
$
—

 
$
(0.1
)
 
$
—

 
$
(0.1
)
Interest rate contracts
 
$
—

 
$
(21.0
)
 
$
—

 
$
(21.0
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
30.0

 
$
—

 
$
—

 
$
30.0

March 31, 2014 (b):
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
17.5

 
$
14.0

 
$
—

 
$
31.5

Foreign currency contracts
 
$
—

 
$
0.1

 
$
—

 
$
0.1

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(10.0
)
 
$
(19.7
)
 
$
—

 
$
(29.7
)
Foreign currency contracts
 
$
—

 
$
(5.6
)
 
$
—

 
$
(5.6
)
Interest rate contracts
 
$
—

 
$
(27.8
)
 
$
—

 
$
(27.8
)
Cross-currency swaps
 
$
—

 
$
(2.2
)
 
$
—

 
$
(2.2
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
29.8

 
$
—

 
$
—

 
$
29.8



(a)
Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.
(b)
Certain immaterial amounts have been revised to correct the classification of derivatives.
 
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 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 which are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts and foreign currency contracts 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 March 31, 2015, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,428.7 and $3,664.2, respectively. At March 31, 2014, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,613.6 and $3,864.4, 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 which 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.
Derivative Instruments and Hedging Activities
Derivative Instruments and Hedging Activities
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 March 31, 2015 and 2014, total volumes associated with LPG commodity derivative instruments totaled 362.5 million gallons and 121.9 million gallons, respectively. At March 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 March 31, 2015 and 2014, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.7 million dekatherms and 9.0 million dekatherms, respectively. At March 31, 2015, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 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 will elect the NPNS exception under GAAP and, as a result, the fair values of such contracts will not be recognized on the balance sheet. At March 31, 2015 and 2014, the volumes of Electric Utility’s forward electricity purchase contracts were 384.4 million kilowatt hours and 207.0 million kilowatt hours, respectively. At March 31, 2015, the maximum period over which these contracts extend is 14 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 March 31, 2015 and 2014, the total volumes associated with FTRs and NYISO capacity contracts totaled 124.6 million kilowatt hours and 482.5 million kilowatt hours, respectively. At March 31, 2015, the maximum period over which we are economically hedging electricity congestion and locational basis differences is 2 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, IntercontinentalExchange (“ICE”) natural gas basis swap contracts, and electricity futures 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 March 31, 2015 and 2014, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 61.6 million dekatherms and 65.1 million dekatherms, respectively. At March 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 42 months. At March 31, 2015 and 2014, total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 356.0 million kilowatt hours and 315.4 million kilowatt hours, and 603.1 million kilowatt hours and 346.1 million kilowatt hours, respectively. At March 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 24 months for electricity call contracts and 18 months for electricity put contracts. At March 31, 2015, the volumes associated with Midstream & Marketing’s natural gas storage NYMEX contracts totaled 0.6 million dekatherms and there were no propane storage NYMEX contracts. At March 31, 2014, the volumes associated with Midstream & Marketing’s natural gas storage NYMEX contracts totaled 0.1 million dekatherms and there were no propane storage NYMEX contracts.
 
At March 31, 2015, the amount of net gains associated with commodity derivative instruments previously designated and qualified as cash flow hedges expected to be reclassified into earnings during the next twelve months is not material.
Interest Rate Risk

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz 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 March 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 €401.1 and €439.8, 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 March 31, 2015 and 2014, we had no unsettled IRPAs.

We account for interest rate swaps and IRPAs as cash flow hedges. At March 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 $2.6.

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz 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 March 31, 2015 and 2014, we were hedging a total of $223.5 and $199.4 of U.S. dollar-denominated LPG purchases, respectively. At March 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 35 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 March 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 March 31, 2015, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $19.5.

Cross-Currency Swaps

During Fiscal 2013, Flaga entered into a cross-currency swap to hedge its exposure to the variability in expected future cash flows associated with foreign currency and interest rate risk resulting from the issuance of $52 of U.S. dollar-denominated variable-rate debt. The 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. The cross-currency swap also includes an interest rate swap of a fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We have designated this cross-currency swap as a cash flow hedge. At March 31, 2015, the amount of net gains associated with this cross-currency swap expected to be reclassified into earnings over 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 form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2015 and 2014, restricted cash in brokerage accounts totaled $56.7 and $4.4, 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 March 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 March 31, 2015, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

Fair Value of Derivative Instruments
 
The following table presents the Company’s derivative assets and liabilities on a gross basis as of March 31, 2015 and 2014:
 
 
March 31,
2015
 
March 31,
2014 (a)
Derivative assets:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Commodity contracts
 
$
—

 
$
10.9

Foreign currency contracts
 
35.8

 
0.1

Cross-currency contracts
 
9.7

 
—

Interest rate contracts
 
0.1

 
—

 
 
45.6

 
11.0

Derivatives subject to utility rate regulation:
 
 
 
 
Commodity contracts
 
—

 
3.5

Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 
22.2

 
17.1

Total derivative assets
 
$
67.8

 
$
31.6

Derivative liabilities:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Commodity contracts
 
$
—

 
$
(1.1
)
Foreign currency contracts
 
—

 
(5.6
)
Cross-currency contracts
 
—

 
(2.2
)
Interest rate contracts
 
(12.5
)
 
(27.8
)
 
 
(12.5
)
 
(36.7
)
Derivatives subject to utility rate regulation:
 
 
 
 
Commodity contracts
 
(5.2
)
 
(0.7
)
Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 
(163.1
)
 
(27.9
)
Total derivative liabilities
 
$
(180.8
)
 
$
(65.3
)


(a)
Certain immaterial amounts have been revised to correct the classification of derivatives.

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.

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of March 31, 2015 and 2014:
 
 
Gross Amounts Recognized
 
Gross Amounts Offset in Balance Sheet
 
Net Amounts Recognized
 
Cash Collateral (Received) Pledged
 
Net Amounts Recognized in Balance Sheet
March 31, 2015
 
 
 
 
 

 
 
 
 
Derivative assets
 
$
67.8

 
$
(13.8
)
 
$
54.0

 
$
—

 
$
54.0

Derivative liabilities
 
$
(180.8
)
 
$
13.8

 
$
(167.0
)
 
$
3.7

 
$
(163.3
)
March 31, 2014
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
31.6

 
$
(8.6
)
 
$
23.0

 
$
—

 
$
23.0

Derivative liabilities
 
$
(65.3
)
 
$
8.6

 
$
(56.7
)
 
$
—

 
$
(56.7
)


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 and six months ended March 31, 2015 and 2014:
 
 
Gain (Loss)
Recognized in
AOCI and
Noncontrolling Interests
 
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 March 31,
 
2015
 
2014
 
2015
 
2014
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
—

 
$
7.8

 
$
0.1

 
$
39.9

 
Cost of sales
Foreign currency contracts
 
23.7

 
(0.2
)
 
6.5

 
(1.4
)
 
Cost of sales
Cross-currency contracts
 
5.4

 
0.1

 
(0.1
)
 
0.2

 
Interest expense
Interest rate contracts
 
1.6

 
(1.8
)
 
(3.5
)
 
(4.0
)
 
Interest expense
Total
 
$
30.7

 
$
5.9

 
$
3.0

 
$
34.7

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
 

Three Months Ended March 31,
 
2015
 
2014
 
 
 
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(12.3
)
 
$
(22.2
)
 
Cost of sales
 

Commodity contracts
 
(4.6
)
 
—

 
Revenues
 
 
Commodity contracts
 
—

 
—

 
Operating expenses / other
operating income, net
 

Total
 
$
(16.9
)
 
$
(22.2
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in
AOCI and
Noncontrolling Interests
 
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of Gain (Loss) Reclassified from
AOCI and Noncontrolling
Interests into Income
Six Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
—

 
$
61.2

 
$
(2.3
)
 
$
62.2

 
Cost of sales
Foreign currency contracts
 
32.4

 
(2.7
)
 
9.2

 
(3.5
)
 
Cost of sales
Cross-currency contracts
 
7.5

 
(1.1
)
 
(0.1
)
 
(0.1
)
 
Interest expense
Interest rate contracts
 
2.4

 
(3.5
)
 
(7.4
)
 
(8.1
)
 
Interest expense
Total
 
$
42.3

 
$
53.9

 
$
(0.6
)
 
$
50.5

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
 
 
Six Months Ended March 31,
 
2015
 
2014
 
 
 
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(304.8
)
 
$
(9.4
)
 
Cost of sales
 
 
Commodity contracts
 
(0.8
)
 
—

 
Revenues
 
 
Commodity contracts
 
(0.5
)
 
0.1

 
Operating expenses / other
operating income, net
 
 
Total
 
$
(306.1
)
 
$
(9.3
)
 
 
 
 
 
 

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 for the three and six months ended March 31, 2015 and 2014.

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 which 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.
Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income
Note 13 — Accumulated Other Comprehensive Income

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

Three Months Ended March 31, 2015
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - December 31, 2014
 
$
(20.0
)
 
$
1.7

 
$
(21.8
)
 
$
(40.1
)
Other comprehensive income (loss) before reclassification adjustments (after-tax)
 
—

 
20.2

 
(64.5
)
 
(44.3
)
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.6

 
(3.0
)
 
—

 
(2.4
)
Reclassification adjustments tax expense
 
(0.2
)
 
1.1

 
—

 
0.9

Reclassification adjustments (after-tax)
 
0.4

 
(1.9
)
 
—

 
(1.5
)
Other comprehensive income (loss)
 
0.4

 
18.3

 
(64.5
)
 
(45.8
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
0.5

 
—

 
0.5

Other comprehensive income (loss) attributable to UGI
 
0.4

 
18.8

 
(64.5
)
 
(45.3
)
AOCI - March 31, 2015
 
$
(19.6
)
 
$
20.5

 
$
(86.3
)
 
$
(85.4
)
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2014
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - December 31, 2013
 
$
(16.0
)
 
$
(15.8
)
 
$
64.0

 
$
32.2

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

 
6.3

 
(0.6
)
 
5.7

Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.3

 
(34.7
)
 
—

 
(34.4
)
Reclassification adjustments tax benefit
 
(0.1
)
 
3.3

 
—

 
3.2

Reclassification adjustments (after-tax)
 
0.2

 
(31.4
)
 
—

 
(31.2
)
Other comprehensive income (loss)
 
0.2

 
(25.1
)
 
(0.6
)
 
(25.5
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
17.6

 
—

 
17.6

Other comprehensive income (loss) attributable to UGI
 
0.2

 
(7.5
)
 
(0.6
)
 
(7.9
)
AOCI - March 31, 2014
 
$
(15.8
)
 
$
(23.3
)
 
$
63.4

 
$
24.3


Six Months Ended March 31, 2015
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - September 30, 2014
 
$
(20.6
)
 
$
(9.3
)
 
$
8.7

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

 
27.9

 
(95.0
)
 
(67.1
)
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
1.6

 
0.6

 
—

 
2.2

Reclassification adjustments tax expense
 
(0.6
)
 
(0.4
)
 
—

 
(1.0
)
Reclassification adjustments (after-tax)
 
1.0

 
0.2

 
—

 
1.2

Other comprehensive income (loss)
 
1.0

 
28.1

 
(95.0
)
 
(65.9
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
1.7

 
—

 
1.7

Other comprehensive income (loss) attributable to UGI
 
1.0

 
29.8

 
(95.0
)
 
(64.2
)
AOCI - March 31, 2015
 
$
(19.6
)
 
$
20.5

 
$
(86.3
)
 
$
(85.4
)
 
 
 
 
 
 
 
 
 
Six Months Ended March 31, 2014
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - September 30, 2013
 
$
(16.4
)
 
$
(26.9
)
 
$
51.7

 
$
8.4

Other comprehensive income before reclassification adjustments (after-tax)
 
—

 
46.8

 
11.7

 
58.5

Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.6

 
(50.5
)
 
—

 
(49.9
)
Reclassification adjustments tax benefit
 
—

 
5.3

 
—

 
5.3

Reclassification adjustments (after-tax)
 
0.6

 
(45.2
)
 
—

 
(44.6
)
Other comprehensive income
 
0.6

 
1.6

 
11.7

 
13.9

Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
2.0

 
—

 
2.0

Other comprehensive income attributable to UGI
 
0.6

 
3.6

 
11.7

 
15.9

AOCI - March 31, 2014
 
$
(15.8
)
 
$
(23.3
)
 
$
63.4

 
$
24.3


For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 12.
Segment Information
Segment Information
Note 14 — Segment Information

Our operations comprise six reportable segments generally based upon products sold, geographic location and regulatory environment. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) Gas Utility; (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.”

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 2014 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 chief operating decision maker does not consider such items when evaluating the financial performance of our reportable segments.
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas
Utility
 
Energy Services
 
Electric Generation
 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Three Months Ended
March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
2,455.6

 
$
(114.7
)
(c)
$
1,100.3

 
$
468.0

 
$
409.4

 
$
24.8

 
$
347.2

 
$
172.9

 
$
47.7

Cost of sales
 
$
1,205.4

 
$
(114.0
)
(c)
$
505.2

 
$
258.2

 
$
296.5

 
$
9.4

 
$
200.3

 
$
123.3

 
$
(73.5
)
Segment profit:
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
Operating income
 
$
702.1

 
$
0.1

 
$
296.9

 
$
139.3

 
$
93.9

 
$
8.0

 
$
53.2

 
$
11.5

 
$
99.2

Loss from equity investees
 
(0.1
)
 
—

 
—

 
—

 
—

 
—

 
(0.1
)
 
—

 
—

Interest expense
 
(58.2
)
 
—

 
(41.1
)
 
(10.1
)
 
(0.5
)
 
—

 
(4.9
)
 
(0.9
)
 
(0.7
)
Income before income taxes
 
$
643.8

 
$
0.1

 
$
255.8

 
$
129.2

 
$
93.4

 
$
8.0

 
$
48.2

 
$
10.6

 
$
98.5

Partnership Adjusted EBITDA (a)
 

 
 
 
$
342.1

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
235.7

 
$
—

 
$
88.3

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

 
$
147.1

Depreciation and amortization
 
$
88.0

 
$
(0.1
)
 
$
48.1

 
$
14.5

 
$
3.6

 
$
3.3

 
$
11.8

 
$
5.2

 
$
1.6

Capital expenditures
 
$
91.4

 
$
—

 
$
26.8

 
$
39.2

 
$
5.9

 
$
2.3

 
$
9.6

 
$
5.4

 
$
2.2

 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas
Utility
 
Energy
Services
 
Electric
Generation
 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Three Months Ended
March 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
3,163.3

 
$
(164.7
)
(c)
$
1,493.7

 
$
480.1

 
$
588.9

 
$
25.1

 
$
412.0

 
$
277.2

 
$
51.0

Cost of sales
 
$
2,001.3

 
$
(164.0
)
(c)
$
885.5

 
$
278.8

 
$
457.9

 
$
9.4

 
$
266.7

 
$
222.7

 
$
44.3

Segment profit:
 
 
 
 
 
 
 
 
 

 

 
 
 
 
 
 
Operating income (loss)
 
$
588.6

 
$
0.2

 
$
284.8

 
$
134.5

 
$
111.5

 
$
9.9

 
$
52.9

 
$
10.9

 
$
(16.1
)
Income from equity investees
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Interest expense
 
(59.5
)
 
—

 
(42.0
)
 
(8.4
)
 
(1.0
)
 
—

 
(6.4
)
 
(1.1
)
 
(0.6
)
Income (loss) before income taxes
 
$
529.1

 
$
0.2

 
$
242.8

 
$
126.1

 
$
110.5

 
$
9.9

 
$
46.5

 
$
9.8

 
$
(16.7
)
Partnership Adjusted EBITDA (a)
 

 
 
 
$
331.2

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
173.4

 
$
—

 
$
173.2

 
$
—

 
$
—

 
$
—

 
$
0.2

 
$
—

 
$
—

Depreciation and amortization
 
$
87.7

 
$
(0.1
)
 
$
49.2

 
$
13.6

 
$
3.2

 
$
2.7

 
$
10.3

 
$
7.2

 
$
1.6

Capital expenditures
 
$
85.3

 
$
—

 
$
27.7

 
$
30.0

 
$
8.4

 
$
1.8

 
$
11.3

 
$
4.2

 
$
1.9


 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas
Utility
 
Energy
Services
 
Electric
Generation
 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Six Months Ended
March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
4,460.2

 
$
(182.4
)
(c)
$
1,989.1

 
$
728.5

 
$
706.4

 
$
41.3

 
$
685.1

 
$
397.5

 
$
94.7

Cost of sales
 
$
2,610.0

 
$
(181.0
)
(c)
$
967.6

 
$
385.4

 
$
530.9

 
$
17.4

 
$
409.6

 
$
295.9

 
$
184.2

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
785.4

 
$
0.1

 
$
436.6

 
$
211.1

 
$
140.1

 
$
7.3

 
$
91.6

 
$
26.6

 
$
(128.0
)
Loss from equity investees
 
(1.1
)
 
—

 
—

 
—

 
—

 
—

 
(1.1
)
 
—

 
—

Interest expense
 
(117.2
)
 
—

 
(82.1
)
 
(20.2
)
 
(1.1
)
 
—

 
(10.5
)
 
(1.9
)
 
(1.4
)
Income (loss) before income taxes
 
$
667.1

 
$
0.1

 
$
354.5

 
$
190.9

 
$
139.0

 
$
7.3

 
$
80.0

 
$
24.7

 
$
(129.4
)
Partnership Adjusted EBITDA (a)
 

 
 
 
$
530.6

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
201.8

 
$
—

 
$
155.1

 
$
—

 
$
—

 
$
—

 
$
0.4

 
$
—

 
$
46.3

Depreciation and amortization
 
$
179.0

 
$
(0.1
)
 
$
97.5

 
$
28.8

 
$
7.2

 
$
6.0

 
$
25.1

 
$
11.3

 
$
3.2

Capital expenditures
 
$
214.9

 
$
—

 
$
57.2

 
$
92.7

 
$
18.7

 
$
8.9

 
$
21.7

 
$
11.8

 
$
3.9

As of March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
10,182.7

 
$
(109.5
)
 
$
4,423.8

 
$
2,359.1

 
$
690.8

 
$
281.2

 
$
1,569.2

 
$
539.7

 
$
428.4

Short-term borrowings
 
$
89.9

 
$
—

 
$
55.0

 
$
30.5

 
$
—

 
$
—

 
$
0.1

 
$
4.3

 
$
—

Goodwill
 
$
2,731.2

 
$
—

 
$
1,949.7

 
$
182.1

 
$
5.6

 
$
—

 
$
510.9

 
$
76.7

 
$
6.2


 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas
Utility
 
Energy
Services
 
Electric
Generation
 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Six Months Ended
March 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
5,479.2

 
$
(230.2
)
(c)
$
2,539.5

 
$
751.7

 
$
861.6

 
$
45.9

 
$
837.3

 
$
570.5

 
$
102.9

Cost of sales
 
$
3,431.2

 
$
(228.4
)
(c)
$
1,468.2

 
$
414.3

 
$
685.0

 
$
20.0

 
$
549.2

 
$
454.4

 
$
68.5

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
952.3

 
$
0.1

 
$
464.5

 
$
216.6

 
$
143.3

 
$
14.3

 
$
96.1

 
$
24.6

 
$
(7.2
)
Income from equity investees
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Interest expense
 
(118.8
)
 
—

 
(83.6
)
 
(16.8
)
 
(2.0
)
 
—

 
(12.8
)
 
(2.4
)
 
(1.2
)
Income (loss) before income taxes
 
$
833.5

 
$
0.1

 
$
380.9

 
$
199.8

 
$
141.3

 
$
14.3

 
$
83.3

 
$
22.2

 
$
(8.4
)
Partnership EBITDA (a)
 
 
 
 
 
$
561.5

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
268.9

 
$
—

 
$
268.6

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

 
$
—

Depreciation and amortization
 
$
181.7

 
$
(0.1
)
 
$
101.5

 
$
27.0

 
$
5.8

 
$
5.3

 
$
25.3

 
$
13.8

 
$
3.1

Capital expenditures
 
$
188.1

 
$
(1.2
)
 
$
51.0

 
$
62.9

 
$
30.1

 
$
11.1

 
$
21.1

 
$
8.8

 
$
4.3

As of March 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
10,720.5

 
$
(116.3
)
 
$
4,692.3

 
$
2,195.4

 
$
643.2

 
$
283.9

 
$
1,923.2

 
$
660.4

 
$
438.4

Short-term borrowings
 
$
260.1

 
$
—

 
$
198.0

 
$
6.5

 
$
51.5

 
$
—

 
$
—

 
$
4.1

 
$
—

Goodwill
 
$
2,886.0

 
$
—

 
$
1,939.0

 
$
182.1

 
$
2.8

 
$
—

 
$
655.3

 
$
99.8

 
$
7.0


(a)
The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income:
 
 
Three Months Ended
March 31,
 
Six Months Ended
March 31,
 
 
2015
 
2014
 
2015
 
2014
Partnership Adjusted EBITDA
 
$
342.1

 
$
331.2

 
$
530.6

 
$
561.5

Depreciation and amortization
 
(48.1
)
 
(49.2
)
 
(97.5
)
 
(101.5
)
Noncontrolling interests (i)
 
2.9

 
2.8

 
3.5

 
4.5

Operating income
 
$
296.9

 
$
284.8

 
$
436.6

 
$
464.5

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

(b)
Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include net gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $102.2 and $(13.2) during the three months ended March 31, 2015 and 2014, respectively, and $(127.5) and $(6.0) during the six months ended March 31, 2015 and 2014, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and, in the three and six months ended March 31, 2014, an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
(c)
Represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Summary of Significant Accounting Policies (Policies)
Earnings Per Common Share 
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.
Derivatives Instruments 
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 the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on certain 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 that on a prospective basis 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. For additional information on our derivative instruments, see Note 12.
Use of Estimates 
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.
Accounting Standards Not Yet Adopted 
Accounting Standards Not Yet Adopted

Consolidation. In February 2015, the Financial Accounting Standards Board (“FASB”) issued new guidance regarding whether a reporting entity should consolidate certain types of legal entities. Among other things, 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.

Debt Issuance Costs. In April 2015, the 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. Early adoption is permitted. Entities would apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2015.

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 Accounting Standards Codification (“ASC”) 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 company 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, 2017 (Fiscal 2018) and allows for either full retrospective adoption or modified retrospective adoption. On April 29, 2015, the FASB issued for public comment a proposal to delay the effective date by one year. The Company is in the process of assessing the impact of the adoption of ASU 2014-09 on its results of operations, cash flows and financial position.
Summary of Significant Accounting Policies (Tables)
Shares Used in Computing Basic and Diluted Earnings Per Share
Shares used in computing basic and diluted earnings per share are as follows: 
 
 
Three Months Ended
March 31,
 
Six Months Ended
March 31,
 
 
2015
 
2014
 
2015
 
2014
Denominator (thousands of shares):
 
 
 
 
 
 
 
 
Average common shares outstanding for basic computation
 
173,154

 
172,760

 
173,055

 
172,494

Incremental shares issuable for stock options and awards
 
2,474

 
2,361

 
2,660

 
2,295

Average common shares outstanding for diluted computation
 
175,628

 
175,121

 
175,715

 
174,789

Inventories (Tables)
Components of Inventories
Inventories comprise the following: 
 
 
March 31,
2015
 
September 30,
2014
 
March 31,
2014
Non-utility LPG and natural gas
 
$
135.8

 
$
283.6

 
$
251.4

Gas Utility natural gas
 
6.3

 
82.7

 
7.5

Materials, supplies and other
 
59.4

 
56.7

 
65.5

Total inventories
 
$
201.5

 
$
423.0

 
$
324.4

Goodwill and Intangible Assets (Tables)
Components of Company's Intangible Assets
Goodwill and intangible assets comprise the following: 
 
 
March 31,
2015
 
September 30,
2014
 
March 31,
2014
Goodwill (not subject to amortization)
 
$
2,731.2

 
$
2,833.4

 
$
2,886.0

Intangible assets:
 
 
 
 
 
 
Customer relationships, noncompete agreements and other
 
$
670.2

 
$
712.0

 
$
727.5

Accumulated amortization
 
(254.1
)
 
(263.8
)
 
(251.6
)
Intangible assets, net (definite-lived)
 
416.1

 
448.2

 
475.9

Trademarks and tradenames (indefinite-lived)
 
121.4

 
128.2

 
132.3

Total intangible assets, net
 
$
537.5

 
$
576.4

 
$
608.2

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)
Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility
The following regulatory assets and liabilities associated with Utilities are included in our accompanying Condensed Consolidated Balance Sheets:
 
 
March 31,
2015
 
September 30,
2014
 
March 31,
2014
Regulatory assets (a):
 
 
 
 
 
 
Income taxes recoverable
 
$
111.5

 
$
110.7

 
$
106.8

Underfunded pension and postretirement plans
 
105.5

 
110.1

 
91.0

Environmental costs
 
14.1

 
14.6

 
14.5

Deferred fuel and power costs
 
—

 
11.8

 
4.3

Removal costs, net
 
18.4

 
16.8

 
14.4

Other
 
3.1

 
4.2

 
4.9

Total regulatory assets
 
$
252.6

 
$
268.2

 
$
235.9

Regulatory liabilities (a):
 
 
 
 
 
 
Postretirement benefits
 
$
19.3

 
$
18.6

 
$
17.2

Environmental overcollections
 
—

 
0.3

 
1.9

Deferred fuel and power refunds
 
40.6

 
0.3

 
3.2

State tax benefits—distribution system repairs
 
10.6

 
10.1

 
9.0

Other
 
2.1

 
3.2

 
1.8

Total regulatory liabilities
 
$
72.6

 
$
32.5

 
$
33.1



(a) Noncurrent regulatory assets are recorded in other assets and regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.
Defined Benefit Pension and Other Postretirement Plans (Tables)
Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs
Net periodic pension expense and other postretirement benefit costs include the following components:
 
 
Pension Benefits
 
Other Postretirement Benefits
Three Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
2.5

 
$
2.3

 
$
0.1

 
$
0.1

Interest cost
 
6.3

 
6.5

 
0.2

 
0.2

Expected return on assets
 
(8.0
)
 
(7.3
)
 
(0.1
)
 
(0.1
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
0.1

 
0.1

 
(0.1
)
 
(0.1
)
Actuarial loss
 
2.5

 
1.9

 
—

 
—

Net benefit cost
 
3.4

 
3.5

 
0.1

 
0.1

Change in associated regulatory liabilities
 
—

 
—

 
1.0

 
0.9

Net expense
 
$
3.4

 
$
3.5

 
$
1.1

 
$
1.0

 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
Six Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
4.9

 
$
4.7

 
$
0.3

 
$
0.3

Interest cost
 
12.6

 
12.9

 
0.4

 
0.5

Expected return on assets
 
(15.9
)
 
(14.7
)
 
(0.3
)
 
(0.3
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
0.2

 
0.2

 
(0.2
)
 
(0.2
)
Actuarial loss
 
5.0

 
3.8

 
—

 
—

Net benefit cost
 
6.8

 
6.9

 
0.2

 
0.3

Change in associated regulatory liabilities
 
—

 
—

 
1.9

 
1.8

Net expense
 
$
6.8

 
$
6.9

 
$
2.1

 
$
2.1

Fair Value Measurement (Tables)
Financial Assets and Financial Liabilities that are Measured at Fair Value on a Recurring Basis
The following table presents on a gross basis our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of March 31, 2015, September 30, 2014 and March 31, 2014:  
 
 
Asset (Liability)
 
 
Level 1
 
Level 2
 
Level 3
 
Total
March 31, 2015:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
13.9

 
$
8.3

 
$
—

 
$
22.2

Foreign currency contracts
 
$
—

 
$
35.8

 
$
—

 
$
35.8

Interest rate contracts
 
$
—

 
$
0.1

 
$
—

 
$
0.1

Cross-currency swaps
 
$
—

 
$
9.7

 
$
—

 
$
9.7

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(64.0
)
 
$
(104.3
)
 
$
—

 
$
(168.3
)
Interest rate contracts
 
$
—

 
$
(12.5
)
 
$
—

 
$
(12.5
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
31.8

 
$
—

 
$
—

 
$
31.8

September 30, 2014:
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
10.6

 
$
19.8

 
$
—

 
$
30.4

Foreign currency contracts
 
$
—

 
$
12.8

 
$
—

 
$
12.8

Interest rate contracts
 
$
—

 
$
0.1

 
$
—

 
$
0.1

Cross-currency swaps
 
$
—

 
$
2.1

 
$
—

 
$
2.1

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(21.2
)
 
$
(32.9
)
 
$
—

 
$
(54.1
)
Foreign currency contracts
 
$
—

 
$
(0.1
)
 
$
—

 
$
(0.1
)
Interest rate contracts
 
$
—

 
$
(21.0
)
 
$
—

 
$
(21.0
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
30.0

 
$
—

 
$
—

 
$
30.0

March 31, 2014 (b):
 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
17.5

 
$
14.0

 
$
—

 
$
31.5

Foreign currency contracts
 
$
—

 
$
0.1

 
$
—

 
$
0.1

Liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(10.0
)
 
$
(19.7
)
 
$
—

 
$
(29.7
)
Foreign currency contracts
 
$
—

 
$
(5.6
)
 
$
—

 
$
(5.6
)
Interest rate contracts
 
$
—

 
$
(27.8
)
 
$
—

 
$
(27.8
)
Cross-currency swaps
 
$
—

 
$
(2.2
)
 
$
—

 
$
(2.2
)
Non-qualified supplemental postretirement grantor trust investments (a)
 
$
29.8

 
$
—

 
$
—

 
$
29.8



(a)
Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.
(b)
Certain immaterial amounts have been revised to correct the classification of derivatives.
Derivative Instruments and Hedging Activities (Tables)
Balance Sheet Location and Fair Value of Derivative Assets and Liabilities 
The following table presents the Company’s derivative assets and liabilities on a gross basis as of March 31, 2015 and 2014:
 
 
March 31,
2015
 
March 31,
2014 (a)
Derivative assets:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Commodity contracts
 
$
—

 
$
10.9

Foreign currency contracts
 
35.8

 
0.1

Cross-currency contracts
 
9.7

 
—

Interest rate contracts
 
0.1

 
—

 
 
45.6

 
11.0

Derivatives subject to utility rate regulation:
 
 
 
 
Commodity contracts
 
—

 
3.5

Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 
22.2

 
17.1

Total derivative assets
 
$
67.8

 
$
31.6

Derivative liabilities:
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
Commodity contracts
 
$
—

 
$
(1.1
)
Foreign currency contracts
 
—

 
(5.6
)
Cross-currency contracts
 
—

 
(2.2
)
Interest rate contracts
 
(12.5
)
 
(27.8
)
 
 
(12.5
)
 
(36.7
)
Derivatives subject to utility rate regulation:
 
 
 
 
Commodity contracts
 
(5.2
)
 
(0.7
)
Derivatives not designated as hedging instruments:
 
 
 
 
Commodity contracts
 
(163.1
)
 
(27.9
)
Total derivative liabilities
 
$
(180.8
)
 
$
(65.3
)


(a)
Certain immaterial amounts have been revised to correct the classification of derivatives.
Derivative Assets and Liabilities and the Effects of Offsetting 
The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of March 31, 2015 and 2014:
 
 
Gross Amounts Recognized
 
Gross Amounts Offset in Balance Sheet
 
Net Amounts Recognized
 
Cash Collateral (Received) Pledged
 
Net Amounts Recognized in Balance Sheet
March 31, 2015
 
 
 
 
 

 
 
 
 
Derivative assets
 
$
67.8

 
$
(13.8
)
 
$
54.0

 
$
—

 
$
54.0

Derivative liabilities
 
$
(180.8
)
 
$
13.8

 
$
(167.0
)
 
$
3.7

 
$
(163.3
)
March 31, 2014
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
31.6

 
$
(8.6
)
 
$
23.0

 
$
—

 
$
23.0

Derivative liabilities
 
$
(65.3
)
 
$
8.6

 
$
(56.7
)
 
$
—

 
$
(56.7
)
Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest 
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 and six months ended March 31, 2015 and 2014:
 
 
Gain (Loss)
Recognized in
AOCI and
Noncontrolling Interests
 
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 March 31,
 
2015
 
2014
 
2015
 
2014
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
—

 
$
7.8

 
$
0.1

 
$
39.9

 
Cost of sales
Foreign currency contracts
 
23.7

 
(0.2
)
 
6.5

 
(1.4
)
 
Cost of sales
Cross-currency contracts
 
5.4

 
0.1

 
(0.1
)
 
0.2

 
Interest expense
Interest rate contracts
 
1.6

 
(1.8
)
 
(3.5
)
 
(4.0
)
 
Interest expense
Total
 
$
30.7

 
$
5.9

 
$
3.0

 
$
34.7

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
 

Three Months Ended March 31,
 
2015
 
2014
 
 
 
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(12.3
)
 
$
(22.2
)
 
Cost of sales
 

Commodity contracts
 
(4.6
)
 
—

 
Revenues
 
 
Commodity contracts
 
—

 
—

 
Operating expenses / other
operating income, net
 

Total
 
$
(16.9
)
 
$
(22.2
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in
AOCI and
Noncontrolling Interests
 
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
 
Location of Gain (Loss) Reclassified from
AOCI and Noncontrolling
Interests into Income
Six Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
—

 
$
61.2

 
$
(2.3
)
 
$
62.2

 
Cost of sales
Foreign currency contracts
 
32.4

 
(2.7
)
 
9.2

 
(3.5
)
 
Cost of sales
Cross-currency contracts
 
7.5

 
(1.1
)
 
(0.1
)
 
(0.1
)
 
Interest expense
Interest rate contracts
 
2.4

 
(3.5
)
 
(7.4
)
 
(8.1
)
 
Interest expense
Total
 
$
42.3

 
$
53.9

 
$
(0.6
)
 
$
50.5

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss)
Recognized in Income
 
Location of Gain (Loss)
Recognized in Income
 
 
Six Months Ended March 31,
 
2015
 
2014
 
 
 
Derivatives Not Designated as Hedging Instruments:
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
(304.8
)
 
$
(9.4
)
 
Cost of sales
 
 
Commodity contracts
 
(0.8
)
 
—

 
Revenues
 
 
Commodity contracts
 
(0.5
)
 
0.1

 
Operating expenses / other
operating income, net
 
 
Total
 
$
(306.1
)
 
$
(9.3
)
 
 
 
 
 
 

Accumulated Other Comprehensive Income (Tables)
Schedule of Accumulated Other Comprehensive Income
The tables below present changes in AOCI during the three and six months ended March 31, 2015 and 2014:

Three Months Ended March 31, 2015
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - December 31, 2014
 
$
(20.0
)
 
$
1.7

 
$
(21.8
)
 
$
(40.1
)
Other comprehensive income (loss) before reclassification adjustments (after-tax)
 
—

 
20.2

 
(64.5
)
 
(44.3
)
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.6

 
(3.0
)
 
—

 
(2.4
)
Reclassification adjustments tax expense
 
(0.2
)
 
1.1

 
—

 
0.9

Reclassification adjustments (after-tax)
 
0.4

 
(1.9
)
 
—

 
(1.5
)
Other comprehensive income (loss)
 
0.4

 
18.3

 
(64.5
)
 
(45.8
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
0.5

 
—

 
0.5

Other comprehensive income (loss) attributable to UGI
 
0.4

 
18.8

 
(64.5
)
 
(45.3
)
AOCI - March 31, 2015
 
$
(19.6
)
 
$
20.5

 
$
(86.3
)
 
$
(85.4
)
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2014
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - December 31, 2013
 
$
(16.0
)
 
$
(15.8
)
 
$
64.0

 
$
32.2

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

 
6.3

 
(0.6
)
 
5.7

Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.3

 
(34.7
)
 
—

 
(34.4
)
Reclassification adjustments tax benefit
 
(0.1
)
 
3.3

 
—

 
3.2

Reclassification adjustments (after-tax)
 
0.2

 
(31.4
)
 
—

 
(31.2
)
Other comprehensive income (loss)
 
0.2

 
(25.1
)
 
(0.6
)
 
(25.5
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
17.6

 
—

 
17.6

Other comprehensive income (loss) attributable to UGI
 
0.2

 
(7.5
)
 
(0.6
)
 
(7.9
)
AOCI - March 31, 2014
 
$
(15.8
)
 
$
(23.3
)
 
$
63.4

 
$
24.3


Six Months Ended March 31, 2015
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - September 30, 2014
 
$
(20.6
)
 
$
(9.3
)
 
$
8.7

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

 
27.9

 
(95.0
)
 
(67.1
)
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
1.6

 
0.6

 
—

 
2.2

Reclassification adjustments tax expense
 
(0.6
)
 
(0.4
)
 
—

 
(1.0
)
Reclassification adjustments (after-tax)
 
1.0

 
0.2

 
—

 
1.2

Other comprehensive income (loss)
 
1.0

 
28.1

 
(95.0
)
 
(65.9
)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
1.7

 
—

 
1.7

Other comprehensive income (loss) attributable to UGI
 
1.0

 
29.8

 
(95.0
)
 
(64.2
)
AOCI - March 31, 2015
 
$
(19.6
)
 
$
20.5

 
$
(86.3
)
 
$
(85.4
)
 
 
 
 
 
 
 
 
 
Six Months Ended March 31, 2014
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Foreign Currency
 
Total
AOCI - September 30, 2013
 
$
(16.4
)
 
$
(26.9
)
 
$
51.7

 
$
8.4

Other comprehensive income before reclassification adjustments (after-tax)
 
—

 
46.8

 
11.7

 
58.5

Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
 
 
 
 
Reclassification adjustments (pre-tax)
 
0.6

 
(50.5
)
 
—

 
(49.9
)
Reclassification adjustments tax benefit
 
—

 
5.3

 
—

 
5.3

Reclassification adjustments (after-tax)
 
0.6

 
(45.2
)
 
—

 
(44.6
)
Other comprehensive income
 
0.6

 
1.6

 
11.7

 
13.9

Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
 
—

 
2.0

 
—

 
2.0

Other comprehensive income attributable to UGI
 
0.6

 
3.6

 
11.7

 
15.9

AOCI - March 31, 2014
 
$
(15.8
)
 
$
(23.3
)
 
$
63.4

 
$
24.3

Segment Information (Tables)
Schedule of Segment Reporting Information
 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas
Utility
 
Energy Services
 
Electric Generation
 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Three Months Ended
March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
2,455.6

 
$
(114.7
)
(c)
$
1,100.3

 
$
468.0

 
$
409.4

 
$
24.8

 
$
347.2

 
$
172.9

 
$
47.7

Cost of sales
 
$
1,205.4

 
$
(114.0
)
(c)
$
505.2

 
$
258.2

 
$
296.5

 
$
9.4

 
$
200.3

 
$
123.3

 
$
(73.5
)
Segment profit:
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
Operating income
 
$
702.1

 
$
0.1

 
$
296.9

 
$
139.3

 
$
93.9

 
$
8.0

 
$
53.2

 
$
11.5

 
$
99.2

Loss from equity investees
 
(0.1
)
 
—

 
—

 
—

 
—

 
—

 
(0.1
)
 
—

 
—

Interest expense
 
(58.2
)
 
—

 
(41.1
)
 
(10.1
)
 
(0.5
)
 
—

 
(4.9
)
 
(0.9
)
 
(0.7
)
Income before income taxes
 
$
643.8

 
$
0.1

 
$
255.8

 
$
129.2

 
$
93.4

 
$
8.0

 
$
48.2

 
$
10.6

 
$
98.5

Partnership Adjusted EBITDA (a)
 

 
 
 
$
342.1

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
235.7

 
$
—

 
$
88.3

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

 
$
147.1

Depreciation and amortization
 
$
88.0

 
$
(0.1
)
 
$
48.1

 
$
14.5

 
$
3.6

 
$
3.3

 
$
11.8

 
$
5.2

 
$
1.6

Capital expenditures
 
$
91.4

 
$
—

 
$
26.8

 
$
39.2

 
$
5.9

 
$
2.3

 
$
9.6

 
$
5.4

 
$
2.2

 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas
Utility
 
Energy
Services
 
Electric
Generation
 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Three Months Ended
March 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
3,163.3

 
$
(164.7
)
(c)
$
1,493.7

 
$
480.1

 
$
588.9

 
$
25.1

 
$
412.0

 
$
277.2

 
$
51.0

Cost of sales
 
$
2,001.3

 
$
(164.0
)
(c)
$
885.5

 
$
278.8

 
$
457.9

 
$
9.4

 
$
266.7

 
$
222.7

 
$
44.3

Segment profit:
 
 
 
 
 
 
 
 
 

 

 
 
 
 
 
 
Operating income (loss)
 
$
588.6

 
$
0.2

 
$
284.8

 
$
134.5

 
$
111.5

 
$
9.9

 
$
52.9

 
$
10.9

 
$
(16.1
)
Income from equity investees
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Interest expense
 
(59.5
)
 
—

 
(42.0
)
 
(8.4
)
 
(1.0
)
 
—

 
(6.4
)
 
(1.1
)
 
(0.6
)
Income (loss) before income taxes
 
$
529.1

 
$
0.2

 
$
242.8

 
$
126.1

 
$
110.5

 
$
9.9

 
$
46.5

 
$
9.8

 
$
(16.7
)
Partnership Adjusted EBITDA (a)
 

 
 
 
$
331.2

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
173.4

 
$
—

 
$
173.2

 
$
—

 
$
—

 
$
—

 
$
0.2

 
$
—

 
$
—

Depreciation and amortization
 
$
87.7

 
$
(0.1
)
 
$
49.2

 
$
13.6

 
$
3.2

 
$
2.7

 
$
10.3

 
$
7.2

 
$
1.6

Capital expenditures
 
$
85.3

 
$
—

 
$
27.7

 
$
30.0

 
$
8.4

 
$
1.8

 
$
11.3

 
$
4.2

 
$
1.9


 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas
Utility
 
Energy
Services
 
Electric
Generation
 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Six Months Ended
March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
4,460.2

 
$
(182.4
)
(c)
$
1,989.1

 
$
728.5

 
$
706.4

 
$
41.3

 
$
685.1

 
$
397.5

 
$
94.7

Cost of sales
 
$
2,610.0

 
$
(181.0
)
(c)
$
967.6

 
$
385.4

 
$
530.9

 
$
17.4

 
$
409.6

 
$
295.9

 
$
184.2

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
785.4

 
$
0.1

 
$
436.6

 
$
211.1

 
$
140.1

 
$
7.3

 
$
91.6

 
$
26.6

 
$
(128.0
)
Loss from equity investees
 
(1.1
)
 
—

 
—

 
—

 
—

 
—

 
(1.1
)
 
—

 
—

Interest expense
 
(117.2
)
 
—

 
(82.1
)
 
(20.2
)
 
(1.1
)
 
—

 
(10.5
)
 
(1.9
)
 
(1.4
)
Income (loss) before income taxes
 
$
667.1

 
$
0.1

 
$
354.5

 
$
190.9

 
$
139.0

 
$
7.3

 
$
80.0

 
$
24.7

 
$
(129.4
)
Partnership Adjusted EBITDA (a)
 

 
 
 
$
530.6

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
201.8

 
$
—

 
$
155.1

 
$
—

 
$
—

 
$
—

 
$
0.4

 
$
—

 
$
46.3

Depreciation and amortization
 
$
179.0

 
$
(0.1
)
 
$
97.5

 
$
28.8

 
$
7.2

 
$
6.0

 
$
25.1

 
$
11.3

 
$
3.2

Capital expenditures
 
$
214.9

 
$
—

 
$
57.2

 
$
92.7

 
$
18.7

 
$
8.9

 
$
21.7

 
$
11.8

 
$
3.9

As of March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
10,182.7

 
$
(109.5
)
 
$
4,423.8

 
$
2,359.1

 
$
690.8

 
$
281.2

 
$
1,569.2

 
$
539.7

 
$
428.4

Short-term borrowings
 
$
89.9

 
$
—

 
$
55.0

 
$
30.5

 
$
—

 
$
—

 
$
0.1

 
$
4.3

 
$
—

Goodwill
 
$
2,731.2

 
$
—

 
$
1,949.7

 
$
182.1

 
$
5.6

 
$
—

 
$
510.9

 
$
76.7

 
$
6.2


 
 
 
 
 
 
 
 
 
 
Midstream & Marketing
 
UGI International
 
 
 
 
Total
 
Elim-
inations
 
AmeriGas
Propane
 
Gas
Utility
 
Energy
Services
 
Electric
Generation
 
Antargaz
 
Flaga &
Other
 
Corporate
& Other (b)
Six Months Ended
March 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
5,479.2

 
$
(230.2
)
(c)
$
2,539.5

 
$
751.7

 
$
861.6

 
$
45.9

 
$
837.3

 
$
570.5

 
$
102.9

Cost of sales
 
$
3,431.2

 
$
(228.4
)
(c)
$
1,468.2

 
$
414.3

 
$
685.0

 
$
20.0

 
$
549.2

 
$
454.4

 
$
68.5

Segment profit:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
952.3

 
$
0.1

 
$
464.5

 
$
216.6

 
$
143.3

 
$
14.3

 
$
96.1

 
$
24.6

 
$
(7.2
)
Income from equity investees
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Interest expense
 
(118.8
)
 
—

 
(83.6
)
 
(16.8
)
 
(2.0
)
 
—

 
(12.8
)
 
(2.4
)
 
(1.2
)
Income (loss) before income taxes
 
$
833.5

 
$
0.1

 
$
380.9

 
$
199.8

 
$
141.3

 
$
14.3

 
$
83.3

 
$
22.2

 
$
(8.4
)
Partnership EBITDA (a)
 
 
 
 
 
$
561.5

 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interests’ net income
 
$
268.9

 
$
—

 
$
268.6

 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
—

 
$
—

Depreciation and amortization
 
$
181.7

 
$
(0.1
)
 
$
101.5

 
$
27.0

 
$
5.8

 
$
5.3

 
$
25.3

 
$
13.8

 
$
3.1

Capital expenditures
 
$
188.1

 
$
(1.2
)
 
$
51.0

 
$
62.9

 
$
30.1

 
$
11.1

 
$
21.1

 
$
8.8

 
$
4.3

As of March 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
10,720.5

 
$
(116.3
)
 
$
4,692.3

 
$
2,195.4

 
$
643.2

 
$
283.9

 
$
1,923.2

 
$
660.4

 
$
438.4

Short-term borrowings
 
$
260.1

 
$
—

 
$
198.0

 
$
6.5

 
$
51.5

 
$
—

 
$
—

 
$
4.1

 
$
—

Goodwill
 
$
2,886.0

 
$
—

 
$
1,939.0

 
$
182.1

 
$
2.8

 
$
—

 
$
655.3

 
$
99.8

 
$
7.0


(a)
The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income:
 
 
Three Months Ended
March 31,
 
Six Months Ended
March 31,
 
 
2015
 
2014
 
2015
 
2014
Partnership Adjusted EBITDA
 
$
342.1

 
$
331.2

 
$
530.6

 
$
561.5

Depreciation and amortization
 
(48.1
)
 
(49.2
)
 
(97.5
)
 
(101.5
)
Noncontrolling interests (i)
 
2.9

 
2.8

 
3.5

 
4.5

Operating income
 
$
296.9

 
$
284.8

 
$
436.6

 
$
464.5

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

(b)
Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include net gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $102.2 and $(13.2) during the three months ended March 31, 2015 and 2014, respectively, and $(127.5) and $(6.0) during the six months ended March 31, 2015 and 2014, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and, in the three and six months ended March 31, 2014, an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
(c)
Represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income:
 
 
Three Months Ended
March 31,
 
Six Months Ended
March 31,
 
 
2015
 
2014
 
2015
 
2014
Partnership Adjusted EBITDA
 
$
342.1

 
$
331.2

 
$
530.6

 
$
561.5

Depreciation and amortization
 
(48.1
)
 
(49.2
)
 
(97.5
)
 
(101.5
)
Noncontrolling interests (i)
 
2.9

 
2.8

 
3.5

 
4.5

Operating income
 
$
296.9

 
$
284.8

 
$
436.6

 
$
464.5

(i)
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
Nature of Operations (Details) (USD $)
In Millions, except Share data, unless otherwise specified
6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
 
 
General Partner held a general partner interest in AmeriGas Partners
1.00% 
 
Percentage of limited partnership interest in AmeriGas Partners
25.30% 
 
Effective ownership interest in AmeriGas OLP
27.10% 
 
Limited Partnership Common Units held in AmeriGas Partners (in units)
23,756,882 
 
General public as limited partner interests in AmeriGas Partners
73.70% 
 
Common Units owned by public (in units)
69,131,947 
 
General Partner incentive distribution
$ 13.1 
$ 10.8 
Summary of Significant Accounting Policies (Details)
6 Months Ended
Mar. 31, 2015
Accounting Policies [Abstract]
 
Ownership interests in certain subsidiaries under equity method investment, maximum
100.00% 
Voting rights in investment businesses not traded publicly accounted for under the cost method, Maximum
20.00% 
Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Denominator (thousands of shares):
 
 
 
 
Average common shares outstanding for basic computation
173,154 
172,760 
173,055 
172,494 
Incremental shares issuable for stock options and awards
2,474 
2,361 
2,660 
2,295 
Average common shares outstanding for diluted computation
175,628 
175,121 
175,715 
174,789 
Inventories (Details) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Mar. 31, 2015
Bcf
Storage_Agreement
Sep. 30, 2014
Bcf
Mar. 31, 2014
Bcf
Inventory Disclosure [Abstract]
 
 
 
Number of storage agreements
3 
 
 
SCAA contract term (in years)
3 years 
 
 
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet)
0.2 
3.9 
0.2 
Carrying value of gas storage inventories released under SCAAs with non-affiliates
$ 0.7 
$ 16.8 
$ 0.8 
Inventories - Components of Inventories (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Sep. 30, 2014
Mar. 31, 2014
Inventory
 
 
 
Inventory, net
$ 201.5 
$ 423.0 
$ 324.4 
Non-utility LPG and Natural Gas
 
 
 
Inventory
 
 
 
Inventory, net
135.8 
283.6 
251.4 
Gas Utility Natural Gas
 
 
 
Inventory
 
 
 
Inventory, net
6.3 
82.7 
7.5 
Materials, Supplies and Other
 
 
 
Inventory
 
 
 
Inventory, net
$ 59.4 
$ 56.7 
$ 65.5 
Goodwill and Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
 
 
 
 
Amortization expense of intangible assets
$ 12.0 
$ 8.9 
$ 25.0 
$ 22.2 
Remainder of Fiscal 2015
24.7 
 
24.7 
 
Fiscal 2016
44.3 
 
44.3 
 
Fiscal 2017
38.1 
 
38.1 
 
Fiscal 2018
36.4 
 
36.4 
 
Fiscal 2019
$ 34.8 
 
$ 34.8 
 
Goodwill and Intangible Assets - Components of Company's Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Sep. 30, 2014
Mar. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
 
 
 
Goodwill (not subject to amortization)
$ 2,731.2 
$ 2,833.4 
$ 2,886.0 
Intangible assets:
 
 
 
Customer relationships, noncompete agreements and other
670.2 
712.0 
727.5 
Accumulated amortization
(254.1)
(263.8)
(251.6)
Intangible assets, net (definite-lived)
416.1 
448.2 
475.9 
Trademarks and tradenames (indefinite-lived)
121.4 
128.2 
132.3 
Total intangible assets, net
$ 537.5 
$ 576.4 
$ 608.2 
Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Sep. 30, 2014
Mar. 31, 2014
Gas Utility
 
 
 
Regulatory Assets
 
 
 
Fair value of unrealized gains (losses)
$ (3.4)
$ (1.4)
$ 2.4 
Electric Utility Electric Supply Contracts
 
 
 
Regulatory Assets
 
 
 
Fair value of unrealized gains (losses)
$ (1.2)
$ 0.3 
$ 0.4 
Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Sep. 30, 2014
Mar. 31, 2014
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
$ 252.6 1
$ 268.2 1
$ 235.9 1
Regulatory liabilities
72.6 1
32.5 1
33.1 1
Postretirement Benefits
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory liabilities
19.3 1
18.6 1
17.2 1
Environmental Overcollections
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory liabilities
0 1
0.3 1
1.9 1
Deferred Fuel and Power Refunds
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory liabilities
40.6 1
0.3 1
3.2 1
State Tax Benefits—Distribution System Repairs
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory liabilities
10.6 1
10.1 1
9.0 1
Other
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory liabilities
2.1 1
3.2 1
1.8 1
Income Taxes Recoverable
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
111.5 1
110.7 1
106.8 1
Underfunded Pension and Postretirement Plans
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
105.5 1
110.1 1
91.0 1
Environmental Costs
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
14.1 1
14.6 1
14.5 1
Deferred Fuel and Power Costs
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
0 1
11.8 1
4.3 1
Removal Costs, Net
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
18.4 1
16.8 1
14.4 1
Other
 
 
 
Regulatory Assets And Liabilities
 
 
 
Regulatory assets
$ 3.1 1
$ 4.2 1
$ 4.9 1
Energy Services Accounts Receivable Securitization Facility (Details) (USD $)
6 Months Ended 5 Months Ended 7 Months Ended
Mar. 31, 2015
Energy Services
Mar. 31, 2014
Energy Services
Mar. 31, 2015
Energy Services Funding Corporation
Mar. 31, 2014
Energy Services Funding Corporation
Oct. 31, 2015
Forecast
Maximum
May 31, 2015
Forecast
Maximum
Accounts, Notes, Loans and Financing Receivable
 
 
 
 
 
 
Receivables facility
 
 
 
 
$ 75,000,000 
$ 150,000,000 
Sale of trade receivables
692,000,000 
820,700,000 
 
 
 
 
Sale of undivided interests in its trade receivables to the commercial paper conduit
 
 
216,500,000 
251,000,000 
 
 
Outstanding balance of trade receivables
 
 
96,900,000 
124,100,000 
 
 
Outstanding balance of trade receivables sold
 
 
$ 0 
$ 10,500,000 
 
 
Debt (Details)
0 Months Ended 0 Months Ended 55 Months Ended 0 Months Ended 5 Months Ended
Mar. 31, 2015
USD ($)
Mar. 31, 2014
USD ($)
Mar. 27, 2015
UGI Utilities 2015 Credit Agreement
USD ($)
Mar. 27, 2015
UGI Utilities 2015 Credit Agreement
Minimum
Mar. 27, 2015
UGI Utilities 2015 Credit Agreement
Maximum
Mar. 27, 2015
UGI Utilities 2015 Credit Agreement
Letter of Credit
USD ($)
Mar. 27, 2015
UGI Utilities 2011 Credit Agreement
USD ($)
Apr. 30, 2015
UGI France 2015 Senior Facilities Agreement
Subsequent Event
Apr. 30, 2020
UGI France 2015 Senior Facilities Agreement
Subsequent Event
Maximum
Apr. 30, 2015
UGI France 2015 Senior Facilities Agreement
Term Loan
Subsequent Event
EUR (€)
Apr. 30, 2015
UGI France 2015 Senior Facilities Agreement
Revolving Credit Facility
Subsequent Event
EUR (€)
Apr. 30, 2015
UGI France 2015 Senior Facilities Agreement
Revolving Credit Facility
Subsequent Event
Minimum
Apr. 30, 2015
UGI France 2015 Senior Facilities Agreement
Revolving Credit Facility
Subsequent Event
Maximum
Apr. 30, 2015
UGI France 2015 Senior Facilities Agreement
Term Loan Borrowing [Member]
Subsequent Event
Minimum
Apr. 30, 2015
UGI France 2015 Senior Facilities Agreement
Term Loan Borrowing [Member]
Subsequent Event
Maximum
Sep. 30, 2015
Forecast
Antargaz 2011 Senior Facilities Agreement
Subsequent Event
EUR (€)
Mar. 31, 2015
Antargaz 2011 Senior Facilities Agreement
USD ($)
Line of Credit Facility
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maximum borrowing capacity
 
 
$ 300,000,000 
 
 
$ 100,000,000 
$ 300,000,000 
 
 
 
 
 
 
 
 
 
 
Basis spread on variable rate
 
 
 
0.00% 
1.75% 
 
 
 
 
 
 
1.45% 
2.55% 
1.60% 
2.70% 
 
 
Ratio of consolidated debt to consolidated capital
 
 
 
 
0.65 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt
3,428,700,000 
3,613,600,000 
 
 
 
 
 
 
 
600,000,000 
 
 
 
 
 
 
 
Maximum borrowing capacity
 
 
 
 
 
 
 
 
 
 
60,000,000 
 
 
 
 
 
 
Repayments of debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
342,000,000 
 
Derivative Instruments and Hedges, Liabilities, Noncurrent
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10,300,000 
Repayments of principal in 2018
 
 
 
 
 
 
 
 
 
60,000,000 
 
 
 
 
 
 
 
Repayments of principal in 2019
 
 
 
 
 
 
 
 
 
60,000,000 
 
 
 
 
 
 
 
Repayments of Principal in 2020
 
 
 
 
 
 
 
 
 
€ 480,000,000 
 
 
 
 
 
 
 
Ratio of net debt to EBITDA
 
 
 
 
 
 
 
3.75 
3.50 
 
 
 
 
 
 
 
 
Commitments and Contingencies (Details) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Mar. 31, 2015
lb
Oct. 31, 2014
lawsuit
Mar. 31, 2015
PNG MGP
Mar. 31, 2015
Environmental Matters
CPG MGP
Mar. 31, 2015
Environmental Matters
PNG MGP
Mar. 31, 2015
Environmental Matters
UGI Utilities
Mar. 31, 2015
CPG and PNG COAs
UGI Utilities
Mar. 31, 2014
CPG and PNG COAs
UGI Utilities
Commitments and Contingencies
 
 
 
 
 
 
 
 
Environmental expenditures cap during calendar year
 
 
 
$ 1.8 
$ 1.1 
 
 
 
Loss contingency, settlement agreement, terms
 
 
2 years 
 
 
 
 
 
Accrual for environmental loss contingencies
 
 
 
 
 
 
$ 9.6 
$ 11.1 
Base year for determination of investigation and remediation cost (in years)
 
 
 
 
 
5 years 
 
 
Class action lawsuits (more than 35)
 
35 
 
 
 
 
 
 
Amount of propane in cylinders before reduction
17 
 
 
 
 
 
 
 
Amount of propane in cylinders after reduction
15 
 
 
 
 
 
 
 
Defined Benefit Pension and Other Postretirement Plans (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
 
 
 
 
Contribution made to Pension Plan
 
 
$ 5.6 
$ 7.0 
Expected contribution to pensions plans during remainder of fiscal year
 
 
5.6 
 
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans
$ 0.6 
$ 0.9 
$ 1.3 
$ 1.7 
Defined Benefit Pension and Other Postretirement Plans - Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Pension Benefits
 
 
 
 
Defined Benefit Plan Disclosure
 
 
 
 
Service cost
$ 2.5 
$ 2.3 
$ 4.9 
$ 4.7 
Interest cost
6.3 
6.5 
12.6 
12.9 
Expected return on assets
(8.0)
(7.3)
(15.9)
(14.7)
Amortization of:
 
 
 
 
Prior service cost (benefit)
0.1 
0.1 
0.2 
0.2 
Actuarial loss
2.5 
1.9 
5.0 
3.8 
Net benefit cost
3.4 
3.5 
6.8 
6.9 
Change in associated regulatory liabilities
0 
0 
0 
0 
Net expense
3.4 
3.5 
6.8 
6.9 
Other Postretirement Benefits
 
 
 
 
Defined Benefit Plan Disclosure
 
 
 
 
Service cost
0.1 
0.1 
0.3 
0.3 
Interest cost
0.2 
0.2 
0.4 
0.5 
Expected return on assets
(0.1)
(0.1)
(0.3)
(0.3)
Amortization of:
 
 
 
 
Prior service cost (benefit)
(0.1)
(0.1)
(0.2)
(0.2)
Actuarial loss
0 
0 
0 
0 
Net benefit cost
0.1 
0.1 
0.2 
0.3 
Change in associated regulatory liabilities
1.0 
0.9 
1.9 
1.8 
Net expense
$ 1.1 
$ 1.0 
$ 2.1 
$ 2.1 
Fair Value Measurements (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Mar. 31, 2014
Fair Value Disclosures [Abstract]
 
 
Carrying value of long-term debt
$ 3,428.7 
$ 3,613.6 
Estimated fair value of long-term debt
$ 3,664.2 
$ 3,864.4 
Fair Value Measurements - Financial Assets and Liabilities that are Measured at Fair Value on a Recurring Basis (Details) (Fair Value, Measurements, Recurring, USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Sep. 30, 2014
Mar. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Non-qualified supplemental postretirement grantor trust investments
$ 31.8 1
$ 30.0 1
$ 29.8 1 2
Commodity Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
22.2 
30.4 
31.5 2
Derivative financial instruments, liabilities
(168.3)
(54.1)
(29.7)2
Foreign Currency Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
35.8 
12.8 
0.1 2
Derivative financial instruments, liabilities
 
(0.1)
(5.6)2
Interest Rate Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0.1 
0.1 
 
Derivative financial instruments, liabilities
(12.5)
(21.0)
(27.8)2
Cross-Currency Swaps
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
9.7 
2.1 
 
Derivative financial instruments, liabilities
 
 
(2.2)2
Level 1
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Non-qualified supplemental postretirement grantor trust investments
31.8 1
30.0 1
29.8 1 2
Level 1 |
Commodity Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
13.9 
10.6 
17.5 2
Derivative financial instruments, liabilities
(64.0)
(21.2)
(10.0)2
Level 1 |
Foreign Currency Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0 
0 
0 2
Derivative financial instruments, liabilities
 
0 
0 2
Level 1 |
Interest Rate Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0 
0 
 
Derivative financial instruments, liabilities
0 
0 
0 2
Level 1 |
Cross-Currency Swaps
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0 
0 
 
Derivative financial instruments, liabilities
 
 
0 2
Level 2
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Non-qualified supplemental postretirement grantor trust investments
0 1
0 1
0 1 2
Level 2 |
Commodity Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
8.3 
19.8 
14.0 2
Derivative financial instruments, liabilities
(104.3)
(32.9)
(19.7)2
Level 2 |
Foreign Currency Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
35.8 
12.8 
0.1 2
Derivative financial instruments, liabilities
 
(0.1)
(5.6)2
Level 2 |
Interest Rate Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0.1 
0.1 
 
Derivative financial instruments, liabilities
(12.5)
(21.0)
(27.8)2
Level 2 |
Cross-Currency Swaps
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
9.7 
2.1 
 
Derivative financial instruments, liabilities
 
 
(2.2)2
Level 3
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Non-qualified supplemental postretirement grantor trust investments
0 1
0 1
0 1 2
Level 3 |
Commodity Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0 
0 
0 2
Derivative financial instruments, liabilities
0 
0 
0 2
Level 3 |
Foreign Currency Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0 
0 
0 2
Derivative financial instruments, liabilities
 
0 
0 2
Level 3 |
Interest Rate Contracts
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0 
0 
 
Derivative financial instruments, liabilities
0 
0 
0 2
Level 3 |
Cross-Currency Swaps
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
 
 
 
Derivative financial instruments, assets
0 
0 
 
Derivative financial instruments, liabilities
 
 
$ 0 2
Derivative Instruments and Hedging Activities (Details)
6 Months Ended 6 Months Ended 6 Months Ended
Mar. 31, 2015
USD ($)
gal
Mar. 31, 2014
USD ($)
gal
Sep. 30, 2014
USD ($)
Mar. 31, 2015
Brokerage Accounts
USD ($)
Mar. 31, 2014
Brokerage Accounts
USD ($)
Mar. 31, 2015
Interest Rate Swaps
EUR (€)
Mar. 31, 2014
Interest Rate Swaps
EUR (€)
Mar. 31, 2015
Interest Rate Protection Agreements
USD ($)
Mar. 31, 2014
Interest Rate Protection Agreements
USD ($)
Mar. 31, 2015
Foreign Currency
USD ($)
Mar. 31, 2014
Foreign Currency
USD ($)
Sep. 30, 2013
Cross Currency Contracts
USD ($)
Mar. 31, 2015
Gas Utility
MMBTU
Mar. 31, 2014
Gas Utility
MMBTU
Mar. 31, 2015
Electric Utility
kWh
Mar. 31, 2014
Electric Utility
kWh
Mar. 31, 2015
Midstream & Marketing
Electricity (millions of kilowatt-hours)
Forward Purchase Contracts
kWh
Mar. 31, 2014
Midstream & Marketing
Electricity (millions of kilowatt-hours)
Forward Purchase Contracts
kWh
Mar. 31, 2015
Midstream & Marketing
Electricity (millions of kilowatt-hours)
Forward Sales Contracts
kWh
Mar. 31, 2014
Midstream & Marketing
Electricity (millions of kilowatt-hours)
Forward Sales Contracts
kWh
Mar. 31, 2015
Midstream & Marketing
Propane Storage (millions of dekatherms)
Forward Sales Contracts
gal
Mar. 31, 2014
Midstream & Marketing
Propane Storage (millions of dekatherms)
Forward Sales Contracts
gal
Mar. 31, 2015
Midstream & Marketing
Gas Utility Natural Gas
Forward Purchase Contracts
MMBTU
Mar. 31, 2014
Midstream & Marketing
Gas Utility Natural Gas
Forward Purchase Contracts
MMBTU
Mar. 31, 2015
Midstream & Marketing
Natural Gas Storage
Forward Sales Contracts
MMBTU
Mar. 31, 2014
Midstream & Marketing
Natural Gas Storage
Forward Sales Contracts
MMBTU
Mar. 31, 2015
Midstream & Marketing
FTR and NYISO Contracts
Electric transmission congestion (excluding Electric Utility)
kWh
Mar. 31, 2014
Midstream & Marketing
FTR and NYISO Contracts
Electric transmission congestion (excluding Electric Utility)
kWh
Mar. 31, 2015
Net Investment Hedging
EUR (€)
Mar. 31, 2014
Net Investment Hedging
EUR (€)
Derivative
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Volume of LPG commodity derivatives (in gallons)
362,500,000 
121,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
0 
 
 
 
 
 
 
 
 
Derivative, Notional Amount
 
 
 
 
 
€ 401,100,000 
€ 439,800,000 
$ 0 
$ 0 
$ 223,500,000 
$ 199,400,000 
$ 52,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
€ 0 
€ 0 
Maximum length of time hedging exposure to LPG commodity price risk
45 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional amount
 
 
 
 
 
 
 
 
 
 
 
 
9,700,000 
9,000,000 
384,400,000 
207,000,000 
356,000,000 
603,100,000 
315,400,000 
346,100,000 
 
 
61,600,000 
65,100,000 
600,000 
100,000 
124,600,000 
482,500,000 
 
 
Maximum length of time hedged in price risk cash flow hedges
 
 
 
 
 
 
 
 
 
35 months 
 
 
12 months 
 
14 months 
 
24 months 
 
18 months 
 
 
 
42 months 
 
 
 
2 months 
 
 
 
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months
2,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months
19,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted cash
$ 56,700,000 
$ 4,400,000 
$ 16,600,000 
$ 56,700,000 
$ 4,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative Instruments and Hedging Activities - Fair Value of Derivative Assets and Liabilities (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Mar. 31, 2014
Derivative assets:
 
 
Derivative asset, gross
$ 67.8 
$ 31.6 1
Derivative liabilities:
 
 
Derivative liability, gross
(180.8)
(65.3)1
Designated as Hedging Instrument
 
 
Derivative assets:
 
 
Derivative asset, gross
45.6 
11.0 1
Derivative liabilities:
 
 
Derivative liability, gross
(12.5)
(36.7)1
Designated as Hedging Instrument |
Commodity Contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
0 
10.9 1
Derivative liabilities:
 
 
Derivative liability, gross
0 
(1.1)1
Designated as Hedging Instrument |
Foreign Currency Contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
35.8 
0.1 1
Derivative liabilities:
 
 
Derivative liability, gross
0 
(5.6)1
Designated as Hedging Instrument |
Cross Currency Contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
9.7 
0 1
Derivative liabilities:
 
 
Derivative liability, gross
0 
(2.2)1
Designated as Hedging Instrument |
Interest Rate Contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
0.1 
0 1
Derivative liabilities:
 
 
Derivative liability, gross
(12.5)
(27.8)1
Derivatives Subject to Utility Rate Regulation |
Commodity Contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
0 
3.5 1
Derivative liabilities:
 
 
Derivative liability, gross
(5.2)
(0.7)1
Derivatives Not Designated as Hedging Instruments |
Commodity Contracts
 
 
Derivative assets:
 
 
Derivative asset, gross
22.2 
17.1 1
Derivative liabilities:
 
 
Derivative liability, gross
$ (163.1)
$ (27.9)1
Derivative Instruments and Hedging Activities - Offsetting Derivative Assets and Liabilities (Details) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
 
 
Document Period End Date
Mar. 31, 2015 
 
Derivative asset, gross
$ 67.8 
$ 31.6 1
Derivative asset, gross liability
(13.8)
(8.6)
Derivative asset, net
54.0 
23.0 
Cash collateral (received) pledged
0 
0 
Derivative asset, net amount recognized in balance sheet
54.0 
23.0 
Derivative liability, gross
(180.8)
(65.3)1
Derivative liability, gross asset
13.8 
8.6 
Derivative liability, net
(167.0)
(56.7)
Cash collateral (received) pledged
3.7 
0 
Derivative liability, net amount recognized in balance sheet
$ (163.3)
$ (56.7)
Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Derivative Instruments, Gain (Loss)
 
 
 
 
Document Period End Date
 
 
Mar. 31, 2015 
 
Derivatives Not Designated as Hedging Instruments
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) recognized in income
$ (16.9)
$ (22.2)
$ (306.1)
$ (9.3)
Cash Flow Hedges
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (loss) recognized in AOCI and Noncontrolling Interests
30.7 
5.9 
42.3 
53.9 
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income
3.0 
34.7 
(0.6)
50.5 
Commodity Contracts |
Derivatives Not Designated as Hedging Instruments |
Cost of Sales
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) recognized in income
(12.3)
(22.2)
(304.8)
(9.4)
Commodity Contracts |
Derivatives Not Designated as Hedging Instruments |
Revenues
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) recognized in income
(4.6)
0 
(0.8)
0 
Commodity Contracts |
Derivatives Not Designated as Hedging Instruments |
Operating Expenses / Other Operating Income, Net
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (Loss) recognized in income
0 
0 
(0.5)
0.1 
Commodity Contracts |
Cash Flow Hedges
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (loss) recognized in AOCI and Noncontrolling Interests
0 
7.8 
0 
61.2 
Commodity Contracts |
Cash Flow Hedges |
Cost of Sales
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income
0.1 
39.9 
(2.3)
62.2 
Foreign Currency Contracts |
Cash Flow Hedges
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (loss) recognized in AOCI and Noncontrolling Interests
23.7 
(0.2)
32.4 
(2.7)
Foreign Currency Contracts |
Cash Flow Hedges |
Cost of Sales
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income
6.5 
(1.4)
9.2 
(3.5)
Cross Currency Contracts |
Cash Flow Hedges
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (loss) recognized in AOCI and Noncontrolling Interests
5.4 
0.1 
7.5 
(1.1)
Cross Currency Contracts |
Cash Flow Hedges |
Interest Expense
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income
(0.1)
0.2 
(0.1)
(0.1)
Interest Rate Contracts |
Cash Flow Hedges
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (loss) recognized in AOCI and Noncontrolling Interests
1.6 
(1.8)
2.4 
(3.5)
Interest Rate Contracts |
Cash Flow Hedges |
Interest Expense / Other Operating Income, Net
 
 
 
 
Derivative Instruments, Gain (Loss)
 
 
 
 
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income
$ (3.5)
$ (4.0)
$ (7.4)
$ (8.1)
Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax
 
 
 
 
AOCI - balance at beginning of period
$ (40.1)
$ 32.2 
$ (21.2)
$ 8.4 
Other comprehensive income (loss) before reclassification adjustments (after-tax)
(44.3)
5.7 
(67.1)
58.5 
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
Reclassification adjustments (pre-tax)
(2.4)
(34.4)
2.2 
(49.9)
Reclassification adjustments tax benefit
0.9 
3.2 
(1.0)
5.3 
Reclassification adjustments (after-tax)
(1.5)
(31.2)
1.2 
(44.6)
Other comprehensive (loss) income
(45.8)
(25.5)
(65.9)
13.9 
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
0.5 
17.6 
1.7 
2.0 
Other comprehensive income (loss) attributable to UGI
(45.3)
(7.9)
(64.2)
15.9 
AOCI - balance at end of period
(85.4)
24.3 
(85.4)
24.3 
Postretirement Benefit Plans
 
 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax
 
 
 
 
AOCI - balance at beginning of period
(20.0)
(16.0)
(20.6)
(16.4)
Other comprehensive income (loss) before reclassification adjustments (after-tax)
0 
0 
0 
0 
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
Reclassification adjustments (pre-tax)
0.6 
0.3 
1.6 
0.6 
Reclassification adjustments tax benefit
(0.2)
(0.1)
(0.6)
0 
Reclassification adjustments (after-tax)
0.4 
0.2 
1.0 
0.6 
Other comprehensive (loss) income
0.4 
0.2 
1.0 
0.6 
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
0 
0 
0 
0 
Other comprehensive income (loss) attributable to UGI
0.4 
0.2 
1.0 
0.6 
AOCI - balance at end of period
(19.6)
(15.8)
(19.6)
(15.8)
Derivative Instruments
 
 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax
 
 
 
 
AOCI - balance at beginning of period
1.7 
(15.8)
(9.3)
(26.9)
Other comprehensive income (loss) before reclassification adjustments (after-tax)
20.2 
6.3 
27.9 
46.8 
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
Reclassification adjustments (pre-tax)
(3.0)
(34.7)
0.6 
(50.5)
Reclassification adjustments tax benefit
1.1 
3.3 
(0.4)
5.3 
Reclassification adjustments (after-tax)
(1.9)
(31.4)
0.2 
(45.2)
Other comprehensive (loss) income
18.3 
(25.1)
28.1 
1.6 
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
0.5 
17.6 
1.7 
2.0 
Other comprehensive income (loss) attributable to UGI
18.8 
(7.5)
29.8 
3.6 
AOCI - balance at end of period
20.5 
(23.3)
20.5 
(23.3)
Foreign Currency
 
 
 
 
Accumulated Other Comprehensive Income (Loss), Net of Tax
 
 
 
 
AOCI - balance at beginning of period
(21.8)
64.0 
8.7 
51.7 
Other comprehensive income (loss) before reclassification adjustments (after-tax)
(64.5)
(0.6)
(95.0)
11.7 
Amounts reclassified from AOCI and noncontrolling interests:
 
 
 
 
Reclassification adjustments (pre-tax)
0 
0 
0 
0 
Reclassification adjustments tax benefit
0 
0 
0 
0 
Reclassification adjustments (after-tax)
0 
0 
0 
0 
Other comprehensive (loss) income
(64.5)
(0.6)
(95.0)
11.7 
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners
0 
0 
0 
0 
Other comprehensive income (loss) attributable to UGI
(64.5)
(0.6)
(95.0)
11.7 
AOCI - balance at end of period
$ (86.3)
$ 63.4 
$ (86.3)
$ 63.4 
Segment Information (Details)
6 Months Ended
Mar. 31, 2015
segment
Segment Reporting [Abstract]
 
Number of reportable segments (in reportable segments)
6 
Segment Information - Schedule of Segment Reporting Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Sep. 30, 2014
Segment Reporting Information
 
 
 
 
 
Revenues
$ 2,455.6 
$ 3,163.3 
$ 4,460.2 
$ 5,479.2 
 
Cost of sales
1,205.4 
2,001.3 
2,610.0 
3,431.2 
 
Segment profit:
 
 
 
 
 
Operating income
702.1 
588.6 
785.4 
952.3 
 
Loss from equity investees
(0.1)
0 
(1.1)
0 
 
Interest expense
(58.2)
(59.5)
(117.2)
(118.8)
 
Income before income taxes
643.8 
529.1 
667.1 
833.5 
 
Noncontrolling interests’ net income
235.7 
173.4 
201.8 
268.9 
 
Depreciation and amortization
88.0 
87.7 
179.0 
181.7 
 
Capital expenditures
(91.4)
(85.3)
(214.9)
(188.1)
 
Total assets
10,182.7 
10,720.5 
10,182.7 
10,720.5 
10,093.0 
Short-term borrowings
89.9 
260.1 
89.9 
260.1 
210.8 
Goodwill
2,731.2 
2,886.0 
2,731.2 
2,886.0 
2,833.4 
Gains (losses) on unsettled commodity derivative instruments, net
102.2 
(13.2)
(127.5)
(6.0)
 
Eliminations
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
(114.7)1
(164.7)1
(182.4)1
(230.2)1
 
Cost of sales
(114.0)1
(164.0)1
(181.0)1
(228.4)1
 
Segment profit:
 
 
 
 
 
Operating income
0.1 
0.2 
0.1 
0.1 
 
Loss from equity investees
0 
0 
0 
0 
 
Interest expense
0 
0 
0 
0 
 
Income before income taxes
0.1 
0.2 
0.1 
0.1 
 
Noncontrolling interests’ net income
0 
0 
0 
0 
 
Depreciation and amortization
(0.1)
(0.1)
(0.1)
(0.1)
 
Capital expenditures
0 
0 
0 
1.2 
 
Total assets
(109.5)
(116.3)
(109.5)
(116.3)
 
Short-term borrowings
0 
0 
0 
0 
 
Goodwill
0 
0 
0 
0 
 
AmeriGas Propane
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
1,100.3 
1,493.7 
1,989.1 
2,539.5 
 
Cost of sales
505.2 
885.5 
967.6 
1,468.2 
 
Segment profit:
 
 
 
 
 
Operating income
296.9 
284.8 
436.6 
464.5 
 
Loss from equity investees
0 
0 
0 
0 
 
Interest expense
(41.1)
(42.0)
(82.1)
(83.6)
 
Income before income taxes
255.8 
242.8 
354.5 
380.9 
 
Partnership Adjusted EBITDA
342.1 2
331.2 2
530.6 2
561.5 2
 
Noncontrolling interests’ net income
88.3 
173.2 
155.1 
268.6 
 
Depreciation and amortization
48.1 
49.2 
97.5 
101.5 
 
Capital expenditures
(26.8)
(27.7)
(57.2)
(51.0)
 
Total assets
4,423.8 
4,692.3 
4,423.8 
4,692.3 
 
Short-term borrowings
55.0 
198.0 
55.0 
198.0 
 
Goodwill
1,949.7 
1,939.0 
1,949.7 
1,939.0 
 
Noncontrolling interests
2.9 3
2.8 3
3.5 3
4.5 3
 
Gas Utility
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
468.0 
480.1 
728.5 
751.7 
 
Cost of sales
258.2 
278.8 
385.4 
414.3 
 
Segment profit:
 
 
 
 
 
Operating income
139.3 
134.5 
211.1 
216.6 
 
Loss from equity investees
0 
0 
0 
0 
 
Interest expense
(10.1)
(8.4)
(20.2)
(16.8)
 
Income before income taxes
129.2 
126.1 
190.9 
199.8 
 
Noncontrolling interests’ net income
0 
0 
0 
0 
 
Depreciation and amortization
14.5 
13.6 
28.8 
27.0 
 
Capital expenditures
(39.2)
(30.0)
(92.7)
(62.9)
 
Total assets
2,359.1 
2,195.4 
2,359.1 
2,195.4 
 
Short-term borrowings
30.5 
6.5 
30.5 
6.5 
 
Goodwill
182.1 
182.1 
182.1 
182.1 
 
Midstream & Marketing, Energy Services
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
409.4 
588.9 
706.4 
861.6 
 
Cost of sales
296.5 
457.9 
530.9 
685.0 
 
Segment profit:
 
 
 
 
 
Operating income
93.9 
111.5 
140.1 
143.3 
 
Loss from equity investees
0 
0 
0 
0 
 
Interest expense
(0.5)
(1.0)
(1.1)
(2.0)
 
Income before income taxes
93.4 
110.5 
139.0 
141.3 
 
Noncontrolling interests’ net income
0 
0 
0 
0 
 
Depreciation and amortization
3.6 
3.2 
7.2 
5.8 
 
Capital expenditures
(5.9)
(8.4)
(18.7)
(30.1)
 
Total assets
690.8 
643.2 
690.8 
643.2 
 
Short-term borrowings
0 
51.5 
0 
51.5 
 
Goodwill
5.6 
2.8 
5.6 
2.8 
 
Midstream & Marketing, Electric Generation
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
24.8 
25.1 
41.3 
45.9 
 
Cost of sales
9.4 
9.4 
17.4 
20.0 
 
Segment profit:
 
 
 
 
 
Operating income
8.0 
9.9 
7.3 
14.3 
 
Loss from equity investees
0 
0 
0 
0 
 
Interest expense
0 
0 
0 
0 
 
Income before income taxes
8.0 
9.9 
7.3 
14.3 
 
Noncontrolling interests’ net income
0 
0 
0 
0 
 
Depreciation and amortization
3.3 
2.7 
6.0 
5.3 
 
Capital expenditures
(2.3)
(1.8)
(8.9)
(11.1)
 
Total assets
281.2 
283.9 
281.2 
283.9 
 
Short-term borrowings
0 
0 
0 
0 
 
Goodwill
0 
0 
0 
0 
 
UGI International, Antargaz
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
347.2 
412.0 
685.1 
837.3 
 
Cost of sales
200.3 
266.7 
409.6 
549.2 
 
Segment profit:
 
 
 
 
 
Operating income
53.2 
52.9 
91.6 
96.1 
 
Loss from equity investees
(0.1)
0 
(1.1)
0 
 
Interest expense
(4.9)
(6.4)
(10.5)
(12.8)
 
Income before income taxes
48.2 
46.5 
80.0 
83.3 
 
Noncontrolling interests’ net income
0.3 
0.2 
0.4 
0.3 
 
Depreciation and amortization
11.8 
10.3 
25.1 
25.3 
 
Capital expenditures
(9.6)
(11.3)
(21.7)
(21.1)
 
Total assets
1,569.2 
1,923.2 
1,569.2 
1,923.2 
 
Short-term borrowings
0.1 
0 
0.1 
0 
 
Goodwill
510.9 
655.3 
510.9 
655.3 
 
UGI International, Flaga & Other
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
172.9 
277.2 
397.5 
570.5 
 
Cost of sales
123.3 
222.7 
295.9 
454.4 
 
Segment profit:
 
 
 
 
 
Operating income
11.5 
10.9 
26.6 
24.6 
 
Loss from equity investees
0 
0 
0 
0 
 
Interest expense
(0.9)
(1.1)
(1.9)
(2.4)
 
Income before income taxes
10.6 
9.8 
24.7 
22.2 
 
Noncontrolling interests’ net income
0 
0 
0 
0 
 
Depreciation and amortization
5.2 
7.2 
11.3 
13.8 
 
Capital expenditures
(5.4)
(4.2)
(11.8)
(8.8)
 
Total assets
539.7 
660.4 
539.7 
660.4 
 
Short-term borrowings
4.3 
4.1 
4.3 
4.1 
 
Goodwill
76.7 
99.8 
76.7 
99.8 
 
Corporate & Other
 
 
 
 
 
Segment Reporting Information
 
 
 
 
 
Revenues
47.7 4
51.0 4
94.7 4
102.9 4
 
Cost of sales
(73.5)4
44.3 4
184.2 4
68.5 4
 
Segment profit:
 
 
 
 
 
Operating income
99.2 4
(16.1)4
(128.0)4
(7.2)4
 
Loss from equity investees
0 4
0 4
0 4
0 4
 
Interest expense
(0.7)4
(0.6)4
(1.4)4
(1.2)4
 
Income before income taxes
98.5 4
(16.7)4
(129.4)4
(8.4)4
 
Noncontrolling interests’ net income
147.1 4
0 4
46.3 4
0 4
 
Depreciation and amortization
1.6 4
1.6 4
3.2 4
3.1 4
 
Capital expenditures
(2.2)4
(1.9)4
(3.9)4
(4.3)4
 
Total assets
428.4 4
438.4 4
428.4 4
438.4 4
 
Short-term borrowings
0 4
0 4
0 4
0 4
 
Goodwill
$ 6.2 4
$ 7.0 4
$ 6.2 4
$ 7.0 4
 
[4] Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include net gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $102.2 and $(13.2) during the three months ended March 31, 2015 and 2014, respectively, and $(127.5) and $(6.0) during the six months ended March 31, 2015 and 2014, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and, in the three and six months ended March 31, 2014, an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
Segment Information Segment Information - Reconciliation of Partnership Adjusted EBITDA (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Mar. 31, 2014
Segment Reporting Information
 
 
 
 
Depreciation and amortization
$ 88.0 
$ 87.7 
$ 179.0 
$ 181.7 
Operating income
702.1 
588.6 
785.4 
952.3 
General Partnership interest in AmeriGas OLP (percentage)
1.01% 
1.01% 
 
 
Amerigas Propane
 
 
 
 
Segment Reporting Information
 
 
 
 
Partnership Adjusted EBITDA
342.1 1
331.2 1
530.6 1
561.5 1
Depreciation and amortization
48.1 
49.2 
97.5 
101.5 
Noncontrolling interests
2.9 2
2.8 2
3.5 2
4.5 2
Operating income
$ 296.9 
$ 284.8 
$ 436.6 
$ 464.5