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1. |
Nature of Operations |
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes and markets energy products and related services. In the United States, we own and operate (1) a retail propane marketing and distribution business; (2) natural gas and electric distribution utilities; (3) electricity generation facilities; and (4) an energy marketing, midstream infrastructure, storage 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”), a publicly traded limited partnership, and its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP” or “the Operating Partnership”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At December 31, 2011, the General Partner held a 1% general partner interest and 42.8% limited partner interest in AmeriGas Partners and an effective 44.4% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common Units (“Common Units”). The remaining 56.2% interest in AmeriGas Partners comprises 32,436,587 Common Units held by the general public as limited partner interests (see Note 15).
Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries (1) conducts LPG distribution businesses in France and, subsequent to the Shell Acquisition described below, in Belgium, the Netherlands and Luxembourg (collectively “Antargaz”); (2) conducts LPG distribution businesses in 11 central and eastern European countries including, subsequent to the Shell Acquisition, in Norway, Sweden and Finland (collectively referred to as “Flaga”); (3) subsequent to the Shell Acquisition conducts an LPG distribution business in the United Kingdom; and (4) conducts an LPG distribution business in the Nantong region of China. On October 14, 2011, UGI, through subsidiaries, acquired Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden for approximately €130 in cash subject to working capital adjustments (the “Shell Acquisition”). We refer to our foreign LPG operations collectively as “International Propane.” Enterprises, through UGI Energy Services, Inc. (“Energy Services”) and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage and energy services business primarily in the Mid-Atlantic region of the United States. In addition, Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electric generation facilities located in Pennsylvania. The businesses of Energy Services and its subsidiaries, including UGID, are referred to herein collectively as “Midstream & Marketing.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries.
Our natural gas and electric distribution utility businesses are 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;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas are collectively referred to as “Gas Utility.” 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, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”
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2. |
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 eliminate all significant intercompany accounts and transactions when we consolidate. We report the public’s limited partner interests in the Partnership and the outside ownership interests in certain subsidiaries of Antargaz and Flaga as noncontrolling interests. Entities in which we own 50 percent or less and in which we exercise significant influence over operating and financial policies are accounted for by the equity method.
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 which 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, 2011 condensed consolidated balance sheet data were derived from audited financial statements but do 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 our Annual Report on Form 10-K for the year ended September 30, 2011 (“Company’s 2011 Annual Financial Statements and Notes”). 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.
Restricted Cash. Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.
Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
Shares used in computing basic and diluted earnings per share are as follows:
Three Months Ended December 31, |
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2011 | 2010 | |||||||
Denominator (thousands of shares): |
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Average common shares outstanding for basic computation |
112,240 | 110,894 | ||||||
Incremental shares issuable for stock options and awards |
912 | 1,522 | ||||||
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Average common shares outstanding for diluted computation |
113,152 | 112,416 | ||||||
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Comprehensive Income. Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and intracompany transaction adjustments.
Reclassifications. We have reclassified certain prior-year period balances to conform to the current-period presentation.
Income Taxes. During the three months ended December 31, 2011, the Company changed the U.S. tax status of a foreign entity. As a result of the change in tax status, we now believe it is more likely than not that a portion of our foreign tax credits will be utilized and, accordingly, adjusted our foreign tax credit valuation allowance which reduced income tax expense by $5.5 for the three months ended December 31, 2011.
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.
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3. |
Accounting Changes |
Adoption of New Accounting Standard
Goodwill Impairment. In September 2011, the Financial Accounting Standards Board (“FASB”) issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. The more-likely-than-not threshold is deemed as having a likelihood of more than 50 percent. Previous guidance required an entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance, an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirements to test goodwill annually for impairment. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted. We adopted the new guidance for Fiscal 2012.
New Accounting Standard Not Yet Adopted
Fair Value Measurements. In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments in ASU 2011-04 result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders’ equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance is effective for our interim period ending March 31, 2012 and is required to be applied prospectively. We do not expect it will have a material impact on our results of operations or financial condition.
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4. |
Goodwill and Intangible Assets |
The Company’s intangible assets comprise the following:
December 31, 2011 |
September 30, 2011 |
December 31, 2010 |
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Goodwill (not subject to amortization) |
$ | 1,624.7 | $ | 1,562.2 | $ | 1,564.7 | ||||||
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Other intangible assets: |
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Customer relationships, noncompete agreements and other |
$ | 248.8 | $ | 232.1 | $ | 219.8 | ||||||
Trademarks (not subject to amortization) |
46.4 | 47.9 | 45.4 | |||||||||
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Gross carrying amount |
295.2 | 280.0 | 265.2 | |||||||||
Accumulated amortization |
(135.5 | ) | (132.2 | ) | (115.1 | ) | ||||||
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Net carrying amount |
$ | 159.7 | $ | 147.8 | $ | 150.1 | ||||||
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The increases in goodwill and other intangible assets during the three months ended December 31, 2011 principally reflect the effects of acquisitions. Amortization expense of intangible assets was $5.8 and $5.5 for the three months ended December 31, 2011 and 2010, respectively. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. As of December 31, 2011 and excluding the impact of the Heritage Acquisition (see Note 15), our expected aggregate amortization expense of intangible assets for the remainder of Fiscal 2012 and the next four fiscal years is as follows: remainder of Fiscal 2012 — $16.8; Fiscal 2013 — $22.0; Fiscal 2014 — $21.0; Fiscal 2015 — $19.0; Fiscal 2016 — $17.1.
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5. |
Segment Information |
We have organized our business units into six reportable segments generally based upon products sold, geographic location (domestic or international) or regulatory environment. Our reportable segments are: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment comprising Flaga, our propane distribution business in the United Kingdom and our propane distribution business in China (“Flaga & Other”); (4) Gas Utility; (5) Electric Utility; and (6) Midstream & Marketing. We refer to both international segments collectively as “International Propane.”
The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2011 Annual Financial Statements and Notes. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership 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 EBITDA may be different from that used by other companies. We evaluate the performance of our International Propane, Gas Utility, Electric Utility and Midstream & Marketing segments principally based upon their income before income taxes.
Three Months Ended December 31, 2011:
Reportable Segments | ||||||||||||||||||||||||||||||||||||
International Propane | ||||||||||||||||||||||||||||||||||||
Total | Elims. | AmeriGas Propane |
Gas Utility |
Electric Utility |
Midstream & Marketing |
Antargaz | Flaga & Other (b) |
Corporate & Other (c) |
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Revenues |
$ | 1,688.8 | $ | (53.3 | ) (d) | $ | 683.8 | $ | 255.0 | $ | 25.2 | $ | 238.8 | $ | 301.6 | $ | 216.7 | $ | 21.0 | |||||||||||||||||
Cost of sales |
$ | 1,101.8 | $ | (52.3 | ) (d) | $ | 443.8 | $ | 141.7 | $ | 15.2 | $ | 198.8 | $ | 175.7 | $ | 168.1 | $ | 10.8 | |||||||||||||||||
Segment profit: |
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Operating income (loss) |
$ | 188.3 | $ | — | $ | 60.1 | $ | 61.2 | $ | 3.2 | $ | 23.9 | $ | 37.3 | $ | 4.4 | $ | (1.8 | ) | |||||||||||||||||
Loss from equity investees |
(0.1 | ) | — | — | — | — | — | (0.1 | ) | — | — | |||||||||||||||||||||||||
Interest expense |
(36.0 | ) | — | (16.5 | ) | (10.1 | ) | (0.5 | ) | (1.1 | ) | (6.5 | ) | (1.0 | ) | (0.3 | ) | |||||||||||||||||||
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Income (loss) before income taxes |
$ | 152.2 | $ | — | $ | 43.6 | $ | 51.1 | $ | 2.7 | $ | 22.8 | $ | 30.7 | $ | 3.4 | $ | (2.1 | ) | |||||||||||||||||
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Partnership EBITDA (a) |
$ | 83.7 | ||||||||||||||||||||||||||||||||||
Noncontrolling interests’ net income |
$ | 23.1 | $ | — | $ | 23.0 | $ | — | $ | — | $ | — | $ | 0.1 | $ | — | $ | — | ||||||||||||||||||
Depreciation and amortization |
$ | 60.3 | $ | — | $ | 24.2 | $ | 12.1 | $ | 0.9 | $ | 2.8 | $ | 14.1 | $ | 5.5 | $ | 0.7 | ||||||||||||||||||
Capital expenditures |
$ | 88.7 | $ | — | $ | 21.6 | $ | 21.8 | $ | 1.0 | $ | 28.1 | $ | 11.1 | $ | 4.8 | $ | 0.3 | ||||||||||||||||||
Total assets (at period end) |
$ | 7,153.9 | $ | (85.4 | ) | $ | 1,975.7 | $ | 2,088.7 | $ | 149.7 | $ | 658.3 | $ | 1,693.7 | $ | 528.9 | $ | 144.3 | |||||||||||||||||
Bank loans (at period end) |
$ | 421.9 | $ | — | $ | 226.0 | $ | 57.7 | $ | — | $ | 118.2 | $ | — | $ | 20.0 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,624.7 | $ | — | $ | 696.6 | $ | 182.1 | $ | — | $ | 2.8 | $ | 641.9 | $ | 94.3 | $ | 7.0 |
Three Months Ended December 31, 2010:
Reportable Segments | ||||||||||||||||||||||||||||||||||||
International Propane | ||||||||||||||||||||||||||||||||||||
Total | Elims. | AmeriGas Propane |
Gas Utility |
Electric Utility |
Midstream & Marketing |
Antargaz | Flaga & Other (b) |
Corporate & Other (c) |
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Revenues |
$ | 1,765.6 | $ | (40.1 | ) (d) | $ | 700.2 | $ | 321.1 | $ | 28.9 | $ | 279.6 | $ | 336.0 | $ | 118.9 | $ | 21.0 | |||||||||||||||||
Cost of sales |
$ | 1,162.6 | $ | (39.3 | ) (d) | $ | 435.3 | $ | 194.9 | $ | 18.6 | $ | 240.1 | $ | 214.6 | $ | 87.1 | $ | 11.3 | |||||||||||||||||
Segment profit: |
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Operating income |
$ | 252.3 | $ | 0.1 | $ | 91.6 | $ | 75.1 | $ | 3.6 | $ | 27.5 | $ | 51.9 | $ | 2.1 | $ | 0.4 | ||||||||||||||||||
Loss from equity investees |
(0.2 | ) | — | — | — | — | — | (0.2 | ) | — | — | |||||||||||||||||||||||||
Interest expense |
(33.3 | ) | — | (15.4 | ) | (10.1 | ) | (0.5 | ) | (0.7 | ) | (5.5 | ) | (0.9 | ) | (0.2 | ) | |||||||||||||||||||
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Income before income taxes |
$ | 218.8 | $ | 0.1 | $ | 76.2 | $ | 65.0 | $ | 3.1 | $ | 26.8 | $ | 46.2 | $ | 1.2 | $ | 0.2 | ||||||||||||||||||
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Partnership EBITDA (a) |
$ | 113.3 | ||||||||||||||||||||||||||||||||||
Noncontrolling interests’ net income |
$ | 41.9 | $ | — | $ | 41.5 | $ | — | $ | — | $ | — | $ | 0.4 | $ | — | $ | — | ||||||||||||||||||
Depreciation and amortization |
$ | 55.3 | $ | — | $ | 22.7 | $ | 12.2 | $ | 1.0 | $ | 1.7 | $ | 12.3 | $ | 4.9 | $ | 0.5 | ||||||||||||||||||
Capital expenditures |
$ | 85.6 | $ | — | $ | 21.3 | $ | 16.1 | $ | 1.5 | $ | 34.6 | $ | 9.4 | $ | 2.5 | $ | 0.2 | ||||||||||||||||||
Total assets (at period end) |
$ | 6,807.8 | $ | (89.7 | ) | $ | 1,904.5 | $ | 2,061.3 | $ | 141.0 | $ | 548.5 | $ | 1,690.9 | $ | 395.2 | $ | 156.1 | |||||||||||||||||
Bank loans (at period end) |
$ | 273.6 | $ | — | $ | 178.0 | $ | 74.0 | $ | — | $ | — | $ | — | $ | 21.6 | $ | — | ||||||||||||||||||
Investments in equity investees (at period end) |
$ | 0.3 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 0.3 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,564.7 | $ | — | $ | 690.1 | $ | 180.1 | $ | — | $ | 2.8 | $ | 591.0 | $ | 93.7 | $ | 7.0 |
(a) |
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income: |
Three Months Ended December 31, |
2011 | 2010 | ||||||
Partnership EBITDA |
$ | 83.7 | $ | 113.3 | ||||
Depreciation and amortization |
(24.2 | ) | (22.7 | ) | ||||
Noncontrolling interests (i) |
0.6 | 1.0 | ||||||
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Operating income |
$ | 60.1 | $ | 91.6 | ||||
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(i) |
Principally represents the General Partner's 1.01% interest in AmeriGas OLP. |
(b) |
International Propane—Flaga & Other principally comprises FLAGA's retail distrbution businesses, our propane distribution business in China and our propane distribution business in the United Kingdom. |
(c) |
Corporate & Other results principally comprise UGI Enterprises' heating, ventilation, air-conditioning, refrigeration and electrical contracting business ("HVAC/R"), net expenses of UGI's captive general liability insurance company and UGI Corporation's unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, assets of HVAC/R and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation. |
(d) |
Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane. |
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6. |
Energy Services Accounts Receivable Securitization Facility |
Energy Services has a $200 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in April 2012, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility back-up purchasers.
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 commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC. Trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet; the Company reflects a liability equal to the amount advanced by the commercial paper conduit; and the Company records interest expense on amounts sold to the commercial paper conduit.
During the three months ended December 31, 2011 and 2010, Energy Services transferred trade receivables to ESFC totaling $251.2 and $290.8, respectively. During the three months ended December 31, 2011 and 2010, ESFC sold an aggregate $94.0 and $61.5, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At December 31, 2011, the balance of ESFC receivables was $78.4 and there was $33.2 sold to the commercial paper conduit. At December 31, 2010, the outstanding balance of ESFC receivables was $109.7 and there were no amounts sold to the commercial paper conduit.
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7. |
Utility Regulatory Assets and Liabilities and Regulatory Matters |
For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 to the Company’s 2011 Annual Financial Statements and Notes. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:
December 31, | September 30, | December 31, | ||||||||||
2011 | 2011 | 2010 | ||||||||||
Regulatory assets: |
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Income taxes recoverable |
$ | 98.7 | $ | 97.9 | $ | 83.6 | ||||||
Underfunded pension and postretirement plans |
148.7 | 150.7 | 116.3 | |||||||||
Environmental costs |
19.4 | 19.5 | 22.5 | |||||||||
Deferred fuel and power costs |
14.8 | 12.2 | 18.1 | |||||||||
Removal costs, net |
11.9 | 12.3 | 12.2 | |||||||||
Other |
8.0 | 7.8 | 6.3 | |||||||||
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Total regulatory assets |
$ | 301.5 | $ | 300.4 | $ | 259.0 | ||||||
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Regulatory liabilities: |
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Postretirement benefits |
$ | 11.8 | $ | 11.5 | $ | 10.8 | ||||||
Environmental overcollections |
4.7 | 4.7 | 7.0 | |||||||||
Deferred fuel and power refunds |
5.0 | 6.6 | 15.2 | |||||||||
State tax benefits—distribution system repairs |
6.5 | 6.3 | 6.7 | |||||||||
Other |
0.4 | 0.7 | — | |||||||||
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Total regulatory liabilities |
$ | 28.4 | $ | 29.8 | $ | 39.7 | ||||||
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Deferred fuel and power—costs and refunds. Gas Utility’s tariffs and Electric Utility’s default service (“DS”) 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 DS rates 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 financial instruments to reduce volatility in the cost of natural gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Unrealized gains (losses) on such contracts at December 31, 2011, September 30, 2011 and December 31, 2010 were $(2.6), $(3.1) and $2.2, respectively.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with Electric Utility’s DS recovery mechanism. At December 31, 2011, September 30, 2011 and December 31, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $13.5, $8.7 and $13.4, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.
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 financial 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 refunds. Unrealized gains on FTRs at December 31, 2011, September 30, 2011 and December 31, 2010 were not material.
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8. |
Defined Benefit Pension and Other Postretirement Plans |
In the U.S., we currently sponsor one 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 (“Pension Plan”). We also provide postretirement health care benefits to certain retirees and a limited number of active employees, and postretirement life insurance benefits to nearly all domestic 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:
Other | ||||||||||||||||
Pension Benefits | Postretirement Benefits | |||||||||||||||
Three Months
Ended December 31, |
Three Months
Ended December 31, |
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2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost |
$ | 2.1 | $ | 2.3 | $ | 0.1 | $ | 0.1 | ||||||||
Interest cost |
6.1 | 5.9 | 0.2 | 0.3 | ||||||||||||
Expected return on assets |
(6.4 | ) | (6.5 | ) | (0.1 | ) | (0.1 | ) | ||||||||
Amortization of: |
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Prior service cost (benefit) |
0.1 | 0.1 | (0.1 | ) | (0.2 | ) | ||||||||||
Actuarial loss |
2.1 | 2.3 | 0.1 | 0.1 | ||||||||||||
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Net benefit cost |
4.0 | 4.1 | 0.2 | 0.2 | ||||||||||||
Change in associated regulatory liabilities |
— | — | 0.8 | 0.8 | ||||||||||||
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Net expense |
$ | 4.0 | $ | 4.1 | $ | 1.0 | $ | 1.0 | ||||||||
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Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $32.0 to the Pension Plan during the next twelve months. During the three months ended December 31, 2011 and 2010, the Company made contributions to the Pension Plan of $4.1 and $1.8, respectively. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI.
Gas and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP for postretirement benefits other than pensions. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the three months ended December 31, 2011 and 2010, nor are they expected to be material for all of Fiscal 2012.
We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans. We recorded pre-tax expense associated with these plans of $0.7 and $0.6 for the three months ended December 31, 2011 and 2010, respectively.
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9. |
Debt |
In December 2011, Flaga entered into a €19.1 ($24.8 at December 31, 2011) euro-based variable-rate term loan agreement. Proceeds from the term loan were used, in large part, to fund Flaga’s October 2011 acquisition of Shell’s LPG propane businesses in Finland, Norway, Sweden and Denmark. The term loan matures in October 2016 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 1.175% to 2.525%. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 1.79% by entering into an interest rate swap agreement. The effective interest rate on this term loan at December 31, 2011 was 3.85%.
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10. |
Commitments and Contingencies |
Environmental Matters
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 terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At December 31, 2011 and 2010, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $17.8 and $21.3, respectively. We have recorded associated regulatory assets in equal amounts.
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. 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 UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. At December 31, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.
UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating three claims against it relating to out-of-state sites.
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.
South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 in remediation costs and paid $26 in third-party claims relating to the site and estimates that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14. Trial took place in March 2009 and the trial court’s decision is pending.
Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens Communications Company, now known as Frontier Communications Company (“Frontier”), served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that they are responsible for an equitable share of any clean up costs Frontier would be required to pay to the City. Frontier alleged that through ownership and control of a subsidiary, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to Frontier’s claims. On October 19, 2010, the magistrate judge recommended the Court grant UGI Utilities’ motion. On November 19, 2010, the Court affirmed the recommended decision of the magistrate judge granting summary judgment in favor of UGI Utilities. On July 1, 2011, Frontier appealed the Court’s decision to the United States Court of Appeals for the First Circuit.
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10. KeySpan has indicated that the cost could be as high as $20. There have been no recent developments in this case.
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies. The Northeast Companies alleged that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites in Waterbury, CT (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s decision in favor of UGI Utilities. A second phase of the trial took place in August 2011 to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The District Court’s decision is pending. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25.
Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha (“City”) and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities’ predecessor is identified as an owner and operator of the site. The City and MUD has requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska and issued an information request to UGI Utilities. On January 17, 2012, UGI Utilities responded to the EPA’s information request and is cooperating with its investigation.
AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac Lake, New York on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by DEC disclosed contamination related to former MGP operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership has researched the history of the site and its ownership interest in the site. The Partnership has reviewed the preliminary site characterization study prepared by the DEC, the extent of contamination and the possible existence of other potentially responsible parties. The Partnership communicated the results of its research to DEC in January 2009 and is awaiting a response before doing any additional investigation. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.
Other Matters
AmeriGas Cylinder Investigations. On or about October 21, 2009, the General Partner received a notice that the Offices of the District Attorneys of Santa Clara, Sonoma, Ventura, San Joaquin and Fresno Counties and the City Attorney of San Diego (the “District Attorneys”) have commenced an investigation into AmeriGas OLP’s cylinder labeling and filling practices in California and issued an administrative subpoena seeking documents and information relating to these practices. We have responded to the administrative subpoena. On or about July 20, 2011, the General Partner received a second subpoena from the District Attorneys. The subpoena sought information and documents regarding AmeriGas OLP’s cylinder exchange program and alleges potential violations of California’s Unfair Competition Law. We reviewed and responded to the subpoena and will continue to cooperate with the District Attorneys.
Federal Trade Commission Investigation of Propane Grill Cylinder Filling Practices. On or about November 4, 2011, the General Partner received notice that the Federal Trade Commission (“FTC”) is conducting an antitrust and consumer protection investigation into certain practices of the Partnership which relate to the filling of portable propane cylinders. On February 2, 2012, the Partnership received a Civil Investigative Demand from the FTC that requests documents and information concerning, among other things, (i) the Partnership’s decision, in 2008, to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds; (ii) changes in the Partnership’s labeling, advertising, and marketing practices resulting from that decision; (iii) cross-filling and related service arrangements with competitors; and (iv) communications between the Partnership and any competitors regarding the foregoing. The Partnership believes that it will have good defenses to any claims that may result from this investigation. We are not able to assess the financial impact this investigation or any related claims may have on the Partnership.
Purported Class Action Lawsuit. In 2005, Samuel and Brenda Swiger (the “Swigers”) filed what purports to be a class action in the Circuit Court of Harrison County, West Virginia against UGI, an insurance subsidiary of UGI, certain officers of UGI and the General Partner, and their insurance carriers and insurance adjusters. In this lawsuit, the Swigers are seeking compensatory and punitive damages on behalf of the putative class for alleged violations of the West Virginia Insurance Unfair Trade Practice Act, negligence, intentional misconduct, and civil conspiracy. The Court has not certified the class and, in October 2008, stayed the lawsuit pending resolution of a separate, but related class action lawsuit filed against AmeriGas Propane, L.P. in Monongalia County, which was settled in Fiscal 2011. We believe we have good defenses to the claims in this action.
BP America Production Company v. Amerigas Propane, L.P. On July 15, 2011, BP America Production Company (“BP”) filed a complaint against AmeriGas Propane, L.P. in the District Court of Denver County, Colorado, alleging, among other things, breach of contract and breach of the covenant of good faith and fair dealing relating to amounts billed for certain goods and services provided to BP since 2005 (the “Services”). The Services relate to the installation of propane-fueled equipment and appliances, and the supply of propane, to approximately 400 residential customers at the request of and for the account of BP. The complaint seeks an unspecified amount of direct, indirect, consequential, special and compensatory damages, including attorneys’ fees, costs and interest and other appropriate relief. It also seeks an accounting to determine the amount of the alleged overcharges related to the Services. We have substantially completed our investigation of this matter and, based upon the results of that investigation, we believe we have good defenses to the claims set forth in the complaint and the amount of loss will not have a material impact on our results of operations and financial condition.
We cannot predict the final results of any of the environmental or other pending claims or legal actions described above. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. We believe, after consultation with counsel, the final outcome of such other matters will not have a material effect on our consolidated financial position, results of operations or cash flows.
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11. |
Equity |
The following table sets forth changes in UGI’s equity and the equity of the noncontrolling interests for the three months ended December 31, 2011 and 2010:
UGI Shareholders | ||||||||||||||||||||||||
Non- controlling Interests |
Common Stock |
Retained Earnings |
Accumulated Other Comprehensive Income (Loss) |
Treasury Stock |
Total Equity |
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Three Months Ended December 31, 2011: |
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Balance September 30, 2011 |
$ | 213.4 | $ | 937.4 | $ | 1,085.8 | $ | (17.7 | ) | $ | (27.8 | ) | $ | 2,191.1 | ||||||||||
Net income |
23.1 | 87.0 | 110.1 | |||||||||||||||||||||
Net losses on derivative instruments |
(7.8 | ) | (33.5 | ) | (41.3 | ) | ||||||||||||||||||
Reclassifications of net losses on derivative instruments |
1.0 | 11.5 | 12.5 | |||||||||||||||||||||
Benefit plans |
0.1 | 0.1 | ||||||||||||||||||||||
Foreign currency translation and transaction adjustments |
(22.2 | ) | (22.2 | ) | ||||||||||||||||||||
Dividends and distributions |
(24.0 | ) | (29.2 | ) | (53.2 | ) | ||||||||||||||||||
Equity transactions |
0.4 | 1.7 | 1.1 | 3.2 | ||||||||||||||||||||
Other |
(0.6 | ) | (0.6 | ) | ||||||||||||||||||||
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Balance December 31, 2011 |
$ | 205.5 | $ | 939.1 | $ | 1,143.6 | $ | (61.8 | ) | $ | (26.7 | ) | $ | 2,199.7 | ||||||||||
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Three Months Ended December 31, 2010: |
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Balance September 30, 2010 |
$ | 237.1 | $ | 906.1 | $ | 966.7 | $ | (10.1 | ) | $ | (38.2 | ) | $ | 2,061.6 | ||||||||||
Net income |
41.9 | 113.1 | 155.0 | |||||||||||||||||||||
Net gains on derivative instruments |
7.2 | 18.7 | 25.9 | |||||||||||||||||||||
Reclassifications of net (gains) losses on derivative instruments |
(2.4 | ) | 16.1 | 13.7 | ||||||||||||||||||||
Benefit plans |
2.2 | 2.2 | ||||||||||||||||||||||
Foreign currency translation adjustments |
(12.1 | ) | (12.1 | ) | ||||||||||||||||||||
Dividends and distributions |
(22.8 | ) | (27.8 | ) | (50.6 | ) | ||||||||||||||||||
Equity transactions |
0.4 | 10.2 | 3.9 | 14.5 | ||||||||||||||||||||
Other |
(0.4 | ) | (0.4 | ) | ||||||||||||||||||||
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Balance December 31, 2010 |
$ | 261.0 | $ | 916.3 | $ | 1,052.0 | $ | 14.8 | $ | (34.3 | ) | $ | 2,209.8 | |||||||||||
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12. |
Fair Value Measurement |
Derivative Financial Instruments
The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of December 31, 2011, September 30, 2011 and December 31, 2010:
Asset (Liability) | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets and Liabilities |
Significant Other Observable Inputs |
Unobservable Inputs |
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(Level 1) | (Level 2) | (Level 3) | Total | |||||||||||||
December 31, 2011: |
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Assets: |
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Derivative financial instruments: |
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Commodity contracts |
$ | 7.4 | $ | 2.0 | $ | — | $ | 9.4 | ||||||||
Foreign currency contracts |
$ | — | $ | 7.0 | $ | — | $ | 7.0 | ||||||||
Liabilities: |
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Derivative financial instruments: |
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Commodity contracts |
$ | (43.9 | ) | $ | (34.6 | ) | $ | — | $ | (78.5 | ) | |||||
Interest rate contracts |
$ | — | $ | (52.4 | ) | $ | — | $ | (52.4 | ) | ||||||
September 30, 2011: |
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Assets: |
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Derivative financial instruments: |
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Commodity contracts |
$ | 3.5 | $ | 3.3 | $ | — | $ | 6.8 | ||||||||
Foreign currency contracts |
$ | — | $ | 5.3 | $ | — | $ | 5.3 | ||||||||
Liabilities: |
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Derivative financial instruments: |
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Commodity contracts |
$ | (28.1 | ) | $ | (16.1 | ) | $ | — | $ | (44.2 | ) | |||||
Foreign currency contracts |
$ | — | $ | (3.3 | ) | $ | — | $ | (3.3 | ) | ||||||
Interest rate contracts |
$ | — | $ | (44.4 | ) | $ | — | $ | (44.4 | ) | ||||||
December 31, 2010: |
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Assets: |
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Derivative financial instruments: |
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Commodity contracts |
$ | 2.9 | $ | 18.0 | $ | — | $ | 20.9 | ||||||||
Foreign currency contracts |
$ | — | $ | 2.8 | $ | — | $ | 2.8 | ||||||||
Interest rate contracts |
$ | — | $ | 7.2 | $ | — | $ | 7.2 | ||||||||
Liabilities: |
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Derivative financial instruments: |
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Commodity contracts |
$ | (22.3 | ) | $ | (12.0 | ) | $ | — | $ | (34.3 | ) | |||||
Foreign currency contracts |
$ | — | $ | (0.9 | ) | $ | — | $ | (0.9 | ) | ||||||
Interest rate contracts |
$ | — | $ | (8.0 | ) | $ | — | $ | (8.0 | ) | ||||||
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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 financial instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts 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 interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions.
Other Financial Instruments
The carrying amounts of other financial instruments included in current assets and current liabilities (excluding current maturities of long-term debt) approximate their fair values because of their short-term nature. At December 31, 2011, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $2,162.5 and $2,264.9, respectively. At December 31, 2010, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $1,996.7 and $2,100.5, 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.
Financial instruments other than derivative financial 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 from trade accounts receivable is limited because we have a large customer base which extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 13.
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13. |
Disclosures About 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. Because most of our derivative instruments generally qualify for hedge accounting or are subject to regulatory rate recovery mechanisms, we expect that changes in the fair value of derivative instruments used to manage commodity, interest rate or currency exchange rate risk would be substantially offset by gains or losses on the associated anticipated transactions.
Commodity Price Risk
In order to manage market price risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane principally during the months of October through March, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units and our International Propane 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. In addition, from time to time, the Partnership enters into price swap agreements to provide market price risk support to some of its wholesale customers. These agreements are not designated as hedges for accounting purposes and the volumes of propane subject to these agreements were not material.
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At December 31, 2011 and 2010, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.1 million dekatherms and 25.2 million dekatherms, respectively. At December 31, 2011, the maximum period over which Gas Utility is hedging natural gas market price risk is 9 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with FASB’s guidance in ASC 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 7).
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. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception. Because these contracts no longer qualify for the normal purchases and normal sales exception, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At December 31, 2011 and 2010, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $13.5 and $13.4, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Consolidated Balance Sheets. In accordance with ASC 980 related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At December 31, 2011 and 2010, the volumes of Electric Utility’s forward electricity purchase contracts was 816.0 million kilowatt hours and 984.3 million kilowatt hours, respectively. At December 31, 2011, the maximum period over which these contracts extend is 29 months.
In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 7). At December 31, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 130.0 million kilowatt hours and 342.0 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At December 31, 2011 and 2010, the volumes associated with Midstream & Marketing’s FTRs totaled 882.1 million kilowatt hours and 637.8 million kilowatt hours, respectively.
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 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, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Because the contracts associated with the anticipated sale of stored natural gas or propane do not qualify for hedge accounting treatment, any gains or losses on the derivative contracts are recognized in earnings prior to gains or losses from the sale of the stored gas. Such derivative gains or losses during Fiscal 2011 were not material. At December 31, 2011, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 3.9 million dekatherms and 3.5 million gallons, respectively. Midstream & Marketing has entered into and may continue to enter into fixed-price propane sales agreements. In order to manage the market price risk relating to substantially all of its fixed-price propane sales agreements, Midstream & Marketing enters into price swap and option contracts.
In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. Associated volumes, fair values and effects on net income were not material for all periods presented.
At December 31, 2011 and 2010, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:
Volumes | ||||||||
December 31, | ||||||||
Commodity |
2011 | 2010 | ||||||
LPG (millions of gallons) |
125.4 | 123.7 | ||||||
Natural gas (millions of dekatherms) |
28.0 | 34.3 | ||||||
Electricity calls (millions of kilowatt-hours) |
1,538.3 | 1,612.7 | ||||||
Electricity puts (millions of kilowatt-hours) |
175.4 | — |
At December 31, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 21 months with a weighted average of 4 months; the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 34 months with a weighted average of 9 months; and the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 24 months for electricity call contracts, with a weighted average of 8 months, and 24 months for electricity put contracts, with a weighted average of 13 months. At December 31, 2011, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 5 months.
We account for commodity price risk contracts (other than those contracts that are not eligible for hedge accounting and Gas Utility and Electric Utility contracts that are subject to regulatory treatment) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in accumulated other comprehensive income (“AOCI”) and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Condensed Consolidated Statements of Income. At December 31, 2011, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $66.8.
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 has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its term loans, in each case through the respective scheduled maturity dates. As of December 31, 2011, the total notional amount of existing variable-rate debt subject to interest rate swap agreements was €442.6. As of December 31, 2010, the total notional amount of existing and anticipated variable-rate debt subject to interest rate swap agreements was €702.5.
Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At December 31, 2011 and 2010, the total notional amount of unsettled IRPAs was $173 and $106.5. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2012 and September 2013.
We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values of interest rate swaps and IRPAs are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At December 31, 2011, 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 $1.3.
Foreign Currency Exchange Rate Risk
In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At December 31, 2011 and 2010, we were hedging a total of $106.0 and $96.1 of U.S. dollar-denominated LPG purchases, respectively. At December 31, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 27 months with a weighted average of 7 months. 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. For both December 31, 2011 and 2010, we were hedging a total of €14.5 of our euro-denominated net investments. As of December 31, 2011, such foreign currency contracts extend through September 2012.
We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At December 31, 2011, 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 $3.1. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.
In conjunction with the Shell Acquisition, in September 2011 we entered into foreign currency exchange transactions to economically hedge the U.S. dollar amount of a substantial portion of the associated euro-denominated purchase price. Through the date of their final expiration in October 2011, these contracts were recorded at fair value with gains or losses recorded in other income (expense). Gains recorded on these contracts during the three months ended December 31, 2011 were not material.
Derivative Financial Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial 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 and options contracts generally require cash deposits in margin accounts. At December 31, 2011 and 2010, restricted cash in brokerage accounts totaled $22.3 and $19.4, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at December 31, 2011. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At December 31, 2011, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of December 31, 2011 and 2010:
Derivative Assets | Derivative (Liabilities) | |||||||||||||||||||
Balance Sheet | Fair Value December 31, |
Balance Sheet | Fair Value December 31, |
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Location | 2011 | 2010 | Location | 2011 | 2010 | |||||||||||||||
Derivatives Designated as Hedging Instruments: |
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Commodity contracts |
Derivative financial instruments and Other assets |
$ | 1.7 | $ | 16.6 | Derivative financial instruments and Other noncurrent liabilities |
$ | (62.4 | ) | $ | (20.9 | ) | ||||||||
Foreign currency contracts |
Derivative financial instruments and Other assets |
7.0 | 2.8 | Derivative financial instruments and Other noncurrent liabilities |
— | (0.9 | ) | |||||||||||||
Interest rate contracts |
Other assets | — | 7.2 | Derivative financial instruments and Other noncurrent liabilities |
(52.4 | ) | (8.0 | ) | ||||||||||||
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Total Derivatives Designated as Hedging Instruments |
$ | 8.7 | $ | 26.6 | $ | (114.8 | ) | $ | (29.8 | ) | ||||||||||
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Derivatives Accounted for under ASC 980: |
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Commodity contracts |
Derivative financial instruments | $ | — | $ | 2.6 | Derivative financial instruments and Other noncurrent liabilities |
$ | (16.1 | ) | $ | (13.4 | ) | ||||||||
Derivatives Not Designated as Hedging Instruments: |
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Commodity contracts |
Derivative financial instruments | $ | 7.7 | $ | 1.7 | |||||||||||||||
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Total Derivatives |
$ | 16.4 | $ | 30.9 | $ | (130.9 | ) | $ | (43.2 | ) | ||||||||||
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The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three months ended December 31, 2011 and 2010:
Three Months Ended December 31,:
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 |
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2011 | 2010 | 2011 | 2010 | Interests into Income | ||||||||||||||
Cash Flow |
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Hedges: |
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Commodity contracts |
$ | (57.2 | ) | $ | 19.9 | $ | (19.5 | ) | $ | (20.0 | ) | Cost of sales | ||||||
Foreign currency contracts |
1.9 | 2.9 | 0.9 | (1.0 | ) | Cost of sales | ||||||||||||
Interest rate contracts |
(9.6 | ) | 14.4 | (1.9 | ) | (3.7 | ) | Interest expense / other income |
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Total |
$ | (64.9 | ) | $ | 37.2 | $ | (20.5 | ) | $ | (24.7 | ) | |||||||
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Net Investment |
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Hedges: |
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Foreign currency contracts |
$ | 0.5 | $ | 0.5 | ||||||||||||||
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Derivatives Not Designated as Hedging Instruments:
Gain (Loss) Recognized in Income |
Location of Gain (Loss) Recognized in Income |
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2011 | 2010 | |||||||||
Commodity contracts |
$ | 3.1 | $ | (0.1 | ) | Cost of sales | ||||
Commodity contracts |
(0.1 | ) | 0.2 | Operating expenses / other income | ||||||
Foreign currency contracts |
0.5 | — | Other income | |||||||
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Total |
$ | 3.5 | $ | 0.1 | ||||||
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The amounts of derivative gains or losses representing ineffectiveness were not material for the three months ended December 31, 2011 and 2010.
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 and contracts which provide for the purchase and delivery, or sale, of natural gas, LPG and electricity to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchases and normal sales exception accounting because they provide for the delivery of products in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
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14. |
Inventories |
Inventories comprise the following:
December 31, 2011 |
September 30, 2011 |
December 31, 2010 |
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Non-utility LPG and natural gas |
$ | 249.1 | $ | 222.2 | $ | 234.7 | ||||||
Gas Utility natural gas |
87.7 | 95.6 | 100.1 | |||||||||
Materials, supplies and other |
53.9 | 45.2 | 52.5 | |||||||||
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Total inventories |
$ | 390.7 | $ | 363.0 | $ | 387.3 | ||||||
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At December 31, 2011, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013. Pursuant to these and predecessor 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 term 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), are included in the caption “Gas Utility natural gas” in the table above.
The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at December 31, 2011, September 30, 2011 and December 31, 2010 comprising 3.3 billion cubic feet (“bcf”), 3.9 bcf and 3.6 bcf of natural gas was $15.7, $19.0 and $18.9, respectively.
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15. |
Subsequent Event—Partnership Acquisition of Heritage Propane |
On January 12, 2012, AmeriGas Partners completed the acquisition of the subsidiaries of Energy Transfer Partners, L.P., a Delaware limited partnership (“ETP”), which operate ETP’s propane distribution business (“Heritage Propane”) for total consideration of approximately $2,600, including $1,460 in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of approximately $1,100 (the “Heritage Acquisition”). The cash consideration for the Heritage Acquisition is subject to adjustments for working capital, cash and the amount of indebtedness of Heritage Propane. The Heritage Acquisition was consummated pursuant to a Contribution and Redemption Agreement dated October 15, 2011, as amended (the “Contribution Agreement”), with ETP, Energy Transfer Partners GP, L.P. and the general partner of ETP (“ETP GP”), and Heritage ETC, L.P., (the “Contributor”). ETP conducted its propane operations in 41 states through its subsidiaries Heritage Operating, L.P. (“HOLP”) and Titan Propane LLC (“Titan”), a Delaware limited partnership and Delaware limited liability company, respectively. According to LP-Gas Magazine rankings, Heritage Propane comprises the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers. The Heritage Acquisition is consistent with UGI’s strategic initiatives and the Partnership’s growth strategies, one of which is to grow the Partnership’s core business.
Pursuant to the Contribution Agreement, the Contributor contributed to AmeriGas Partners, a 99.999% limited partner interest in HOLP; a 100% membership interest in Heritage Operating GP, LLC, a Delaware limited liability company and a holder of a 0.001% general partner interest in HOLP; a 99.99% limited partner interest in Titan Energy Partners, L.P., a Delaware limited partnership and sole member of Titan; and a 100% membership interest in Titan Energy GP, L.L.C., a Delaware limited liability company and holder of a 0.01% general partner interest in Titan Energy Partners, L.P. Immediately prior to the consummation of the Heritage Acquisition, HOLP transferred its interests in all of the net assets constituting HOLP’s cylinder exchange business (“HPX”) to an indirect wholly owned subsidiary of ETP and ETP has agreed to use its best efforts to sell HPX to a third party. To the extent that the gross proceeds of ETP’s sale of HPX exceed an agreed upon amount, AmeriGas Partners will receive a share of such excess and to the extent such gross proceeds of the sale of HPX are less than such amount, AmeriGas Partners will pay Contributor an amount equal to the shortfall. Immediately after the consummation of the Heritage Acquisition and giving effect to the related contribution of Common Units to the Partnership by the General Partner, in order to maintain its general partner interests in AmeriGas Partners and AmeriGas OLP, UGI, through subsidiaries, held a 1% general partner interest and 27.4% limited partner interest in AmeriGas Partners and an effective 29.2% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 Common Units. The remaining 71.6% interest in AmeriGas Partners comprises 62,003,949 publicly held Common Units of which 29,567,362 Common Units are held by ETP. As a result of the Heritage Acquisition and in accordance with GAAP, UGI anticipates recording an increase in its common stockholder’s equity of approximately $175 relating to changes in UGI’s ownership interest in AmeriGas Partners.
The cash portion of the Heritage Acquisition was financed by the issuance by AmeriGas Finance Corp. and AmeriGas Finance LLC, wholly owned finance subsidiaries of AmeriGas Partners (the “Issuers”), of $550 principal amount of 6.75% Senior Notes due May 2020 (the “6.75% Notes”) and $1,000 principal amount of 7.00% Senior Notes due May 2022 (the “7.00% Notes” and, together with the 6.75% Notes, the “Notes”). The Notes are fully and unconditionally guaranteed on a senior unsecured basis by AmeriGas Partners. The Issuers have the right to redeem the Notes, in whole or in part, prior to their maturity subject to certain restrictions. A premium applies to redemptions of the 6.75% Notes and 7.00% Notes through May 2018 and May 2020, respectively. The Issuers may also redeem, at a premium and subject to certain restrictions, up to 35% of the Notes with the proceeds of a registered public equity offering. The Notes and guarantees rank equal in right of payment with all of AmeriGas Partners’ existing senior notes.
Due to the timing of the Heritage Acquisition, pro forma financial information for the three months ended December 31, 2011 cannot be reasonably determined at this time.
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Restricted Cash. Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.
Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
Shares used in computing basic and diluted earnings per share are as follows:
Three Months Ended December 31, |
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2011 | 2010 | |||||||
Denominator (thousands of shares): |
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Average common shares outstanding for basic computation |
112,240 | 110,894 | ||||||
Incremental shares issuable for stock options and awards |
912 | 1,522 | ||||||
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Average common shares outstanding for diluted computation |
113,152 | 112,416 | ||||||
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Comprehensive Income. Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and intracompany transaction adjustments.
Reclassifications. We have reclassified certain prior-year period balances to conform to the current-period presentation.
Income Taxes. During the three months ended December 31, 2011, the Company changed the U.S. tax status of a foreign entity. As a result of the change in tax status, we now believe it is more likely than not that a portion of our foreign tax credits will be utilized and, accordingly, adjusted our foreign tax credit valuation allowance which reduced income tax expense by $5.5 for the three months ended December 31, 2011.
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.
Goodwill Impairment. In September 2011, the Financial Accounting Standards Board (“FASB”) issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. The more-likely-than-not threshold is deemed as having a likelihood of more than 50 percent. Previous guidance required an entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance, an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirements to test goodwill annually for impairment. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted. We adopted the new guidance for Fiscal 2012.
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Three Months Ended December 31, |
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2011 | 2010 | |||||||
Denominator (thousands of shares): |
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Average common shares outstanding for basic computation |
112,240 | 110,894 | ||||||
Incremental shares issuable for stock options and awards |
912 | 1,522 | ||||||
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Average common shares outstanding for diluted computation |
113,152 | 112,416 | ||||||
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December 31, 2011 |
September 30, 2011 |
December 31, 2010 |
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Goodwill (not subject to amortization) |
$ | 1,624.7 | $ | 1,562.2 | $ | 1,564.7 | ||||||
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Other intangible assets: |
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Customer relationships, noncompete agreements and other |
$ | 248.8 | $ | 232.1 | $ | 219.8 | ||||||
Trademarks (not subject to amortization) |
46.4 | 47.9 | 45.4 | |||||||||
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Gross carrying amount |
295.2 | 280.0 | 265.2 | |||||||||
Accumulated amortization |
(135.5 | ) | (132.2 | ) | (115.1 | ) | ||||||
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Net carrying amount |
$ | 159.7 | $ | 147.8 | $ | 150.1 | ||||||
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Reportable Segments | ||||||||||||||||||||||||||||||||||||
International Propane | ||||||||||||||||||||||||||||||||||||
Total | Elims. | AmeriGas Propane |
Gas Utility |
Electric Utility |
Midstream & Marketing |
Antargaz | Flaga & Other (b) |
Corporate & Other (c) |
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Revenues |
$ | 1,688.8 | $ | (53.3 | ) (d) | $ | 683.8 | $ | 255.0 | $ | 25.2 | $ | 238.8 | $ | 301.6 | $ | 216.7 | $ | 21.0 | |||||||||||||||||
Cost of sales |
$ | 1,101.8 | $ | (52.3 | ) (d) | $ | 443.8 | $ | 141.7 | $ | 15.2 | $ | 198.8 | $ | 175.7 | $ | 168.1 | $ | 10.8 | |||||||||||||||||
Segment profit: |
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Operating income (loss) |
$ | 188.3 | $ | — | $ | 60.1 | $ | 61.2 | $ | 3.2 | $ | 23.9 | $ | 37.3 | $ | 4.4 | $ | (1.8 | ) | |||||||||||||||||
Loss from equity investees |
(0.1 | ) | — | — | — | — | — | (0.1 | ) | — | — | |||||||||||||||||||||||||
Interest expense |
(36.0 | ) | — | (16.5 | ) | (10.1 | ) | (0.5 | ) | (1.1 | ) | (6.5 | ) | (1.0 | ) | (0.3 | ) | |||||||||||||||||||
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Income (loss) before income taxes |
$ | 152.2 | $ | — | $ | 43.6 | $ | 51.1 | $ | 2.7 | $ | 22.8 | $ | 30.7 | $ | 3.4 | $ | (2.1 | ) | |||||||||||||||||
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Partnership EBITDA (a) |
$ | 83.7 | ||||||||||||||||||||||||||||||||||
Noncontrolling interests’ net income |
$ | 23.1 | $ | — | $ | 23.0 | $ | — | $ | — | $ | — | $ | 0.1 | $ | — | $ | — | ||||||||||||||||||
Depreciation and amortization |
$ | 60.3 | $ | — | $ | 24.2 | $ | 12.1 | $ | 0.9 | $ | 2.8 | $ | 14.1 | $ | 5.5 | $ | 0.7 | ||||||||||||||||||
Capital expenditures |
$ | 88.7 | $ | — | $ | 21.6 | $ | 21.8 | $ | 1.0 | $ | 28.1 | $ | 11.1 | $ | 4.8 | $ | 0.3 | ||||||||||||||||||
Total assets (at period end) |
$ | 7,153.9 | $ | (85.4 | ) | $ | 1,975.7 | $ | 2,088.7 | $ | 149.7 | $ | 658.3 | $ | 1,693.7 | $ | 528.9 | $ | 144.3 | |||||||||||||||||
Bank loans (at period end) |
$ | 421.9 | $ | — | $ | 226.0 | $ | 57.7 | $ | — | $ | 118.2 | $ | — | $ | 20.0 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,624.7 | $ | — | $ | 696.6 | $ | 182.1 | $ | — | $ | 2.8 | $ | 641.9 | $ | 94.3 | $ | 7.0 |
Three Months Ended December 31, 2010:
Reportable Segments | ||||||||||||||||||||||||||||||||||||
International Propane | ||||||||||||||||||||||||||||||||||||
Total | Elims. | AmeriGas Propane |
Gas Utility |
Electric Utility |
Midstream & Marketing |
Antargaz | Flaga & Other (b) |
Corporate & Other (c) |
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Revenues |
$ | 1,765.6 | $ | (40.1 | ) (d) | $ | 700.2 | $ | 321.1 | $ | 28.9 | $ | 279.6 | $ | 336.0 | $ | 118.9 | $ | 21.0 | |||||||||||||||||
Cost of sales |
$ | 1,162.6 | $ | (39.3 | ) (d) | $ | 435.3 | $ | 194.9 | $ | 18.6 | $ | 240.1 | $ | 214.6 | $ | 87.1 | $ | 11.3 | |||||||||||||||||
Segment profit: |
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Operating income |
$ | 252.3 | $ | 0.1 | $ | 91.6 | $ | 75.1 | $ | 3.6 | $ | 27.5 | $ | 51.9 | $ | 2.1 | $ | 0.4 | ||||||||||||||||||
Loss from equity investees |
(0.2 | ) | — | — | — | — | — | (0.2 | ) | — | — | |||||||||||||||||||||||||
Interest expense |
(33.3 | ) | — | (15.4 | ) | (10.1 | ) | (0.5 | ) | (0.7 | ) | (5.5 | ) | (0.9 | ) | (0.2 | ) | |||||||||||||||||||
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Income before income taxes |
$ | 218.8 | $ | 0.1 | $ | 76.2 | $ | 65.0 | $ | 3.1 | $ | 26.8 | $ | 46.2 | $ | 1.2 | $ | 0.2 | ||||||||||||||||||
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Partnership EBITDA (a) |
$ | 113.3 | ||||||||||||||||||||||||||||||||||
Noncontrolling interests’ net income |
$ | 41.9 | $ | — | $ | 41.5 | $ | — | $ | — | $ | — | $ | 0.4 | $ | — | $ | — | ||||||||||||||||||
Depreciation and amortization |
$ | 55.3 | $ | — | $ | 22.7 | $ | 12.2 | $ | 1.0 | $ | 1.7 | $ | 12.3 | $ | 4.9 | $ | 0.5 | ||||||||||||||||||
Capital expenditures |
$ | 85.6 | $ | — | $ | 21.3 | $ | 16.1 | $ | 1.5 | $ | 34.6 | $ | 9.4 | $ | 2.5 | $ | 0.2 | ||||||||||||||||||
Total assets (at period end) |
$ | 6,807.8 | $ | (89.7 | ) | $ | 1,904.5 | $ | 2,061.3 | $ | 141.0 | $ | 548.5 | $ | 1,690.9 | $ | 395.2 | $ | 156.1 | |||||||||||||||||
Bank loans (at period end) |
$ | 273.6 | $ | — | $ | 178.0 | $ | 74.0 | $ | — | $ | — | $ | — | $ | 21.6 | $ | — | ||||||||||||||||||
Investments in equity investees (at period end) |
$ | 0.3 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 0.3 | $ | — | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,564.7 | $ | — | $ | 690.1 | $ | 180.1 | $ | — | $ | 2.8 | $ | 591.0 | $ | 93.7 | $ | 7.0 |
(a) |
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income: |
Three Months Ended December 31, |
2011 | 2010 | ||||||
Partnership EBITDA |
$ | 83.7 | $ | 113.3 | ||||
Depreciation and amortization |
(24.2 | ) | (22.7 | ) | ||||
Noncontrolling interests (i) |
0.6 | 1.0 | ||||||
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|
|||||
Operating income |
$ | 60.1 | $ | 91.6 | ||||
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(i) |
Principally represents the General Partner's 1.01% interest in AmeriGas OLP. |
(b) |
International Propane—Flaga & Other principally comprises FLAGA's retail distrbution businesses, our propane distribution business in China and our propane distribution business in the United Kingdom. |
(c) |
Corporate & Other results principally comprise UGI Enterprises' heating, ventilation, air-conditioning, refrigeration and electrical contracting business ("HVAC/R"), net expenses of UGI's captive general liability insurance company and UGI Corporation's unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, assets of HVAC/R and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation. |
(d) |
Principally represents the elimination of intersegment transactions among Midstream & Marketing, Gas Utility and AmeriGas Propane. |
|
December 31, | September 30, | December 31, | ||||||||||
2011 | 2011 | 2010 | ||||||||||
Regulatory assets: |
||||||||||||
Income taxes recoverable |
$ | 98.7 | $ | 97.9 | $ | 83.6 | ||||||
Underfunded pension and postretirement plans |
148.7 | 150.7 | 116.3 | |||||||||
Environmental costs |
19.4 | 19.5 | 22.5 | |||||||||
Deferred fuel and power costs |
14.8 | 12.2 | 18.1 | |||||||||
Removal costs, net |
11.9 | 12.3 | 12.2 | |||||||||
Other |
8.0 | 7.8 | 6.3 | |||||||||
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|||||||
Total regulatory assets |
$ | 301.5 | $ | 300.4 | $ | 259.0 | ||||||
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Regulatory liabilities: |
||||||||||||
Postretirement benefits |
$ | 11.8 | $ | 11.5 | $ | 10.8 | ||||||
Environmental overcollections |
4.7 | 4.7 | 7.0 | |||||||||
Deferred fuel and power refunds |
5.0 | 6.6 | 15.2 | |||||||||
State tax benefits—distribution system repairs |
6.5 | 6.3 | 6.7 | |||||||||
Other |
0.4 | 0.7 | — | |||||||||
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|||||||
Total regulatory liabilities |
$ | 28.4 | $ | 29.8 | $ | 39.7 | ||||||
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Other | ||||||||||||||||
Pension Benefits | Postretirement Benefits | |||||||||||||||
Three Months
Ended December 31, |
Three Months
Ended December 31, |
|||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost |
$ | 2.1 | $ | 2.3 | $ | 0.1 | $ | 0.1 | ||||||||
Interest cost |
6.1 | 5.9 | 0.2 | 0.3 | ||||||||||||
Expected return on assets |
(6.4 | ) | (6.5 | ) | (0.1 | ) | (0.1 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service cost (benefit) |
0.1 | 0.1 | (0.1 | ) | (0.2 | ) | ||||||||||
Actuarial loss |
2.1 | 2.3 | 0.1 | 0.1 | ||||||||||||
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Net benefit cost |
4.0 | 4.1 | 0.2 | 0.2 | ||||||||||||
Change in associated regulatory liabilities |
— | — | 0.8 | 0.8 | ||||||||||||
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Net expense |
$ | 4.0 | $ | 4.1 | $ | 1.0 | $ | 1.0 | ||||||||
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UGI Shareholders | ||||||||||||||||||||||||
Non- controlling Interests |
Common Stock |
Retained Earnings |
Accumulated Other Comprehensive Income (Loss) |
Treasury Stock |
Total Equity |
|||||||||||||||||||
Three Months Ended December 31, 2011: |
||||||||||||||||||||||||
Balance September 30, 2011 |
$ | 213.4 | $ | 937.4 | $ | 1,085.8 | $ | (17.7 | ) | $ | (27.8 | ) | $ | 2,191.1 | ||||||||||
Net income |
23.1 | 87.0 | 110.1 | |||||||||||||||||||||
Net losses on derivative instruments |
(7.8 | ) | (33.5 | ) | (41.3 | ) | ||||||||||||||||||
Reclassifications of net losses on derivative instruments |
1.0 | 11.5 | 12.5 | |||||||||||||||||||||
Benefit plans |
0.1 | 0.1 | ||||||||||||||||||||||
Foreign currency translation and transaction adjustments |
(22.2 | ) | (22.2 | ) | ||||||||||||||||||||
Dividends and distributions |
(24.0 | ) | (29.2 | ) | (53.2 | ) | ||||||||||||||||||
Equity transactions |
0.4 | 1.7 | 1.1 | 3.2 | ||||||||||||||||||||
Other |
(0.6 | ) | (0.6 | ) | ||||||||||||||||||||
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|||||||||||||
Balance December 31, 2011 |
$ | 205.5 | $ | 939.1 | $ | 1,143.6 | $ | (61.8 | ) | $ | (26.7 | ) | $ | 2,199.7 | ||||||||||
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|||||||||||||
Three Months Ended December 31, 2010: |
||||||||||||||||||||||||
Balance September 30, 2010 |
$ | 237.1 | $ | 906.1 | $ | 966.7 | $ | (10.1 | ) | $ | (38.2 | ) | $ | 2,061.6 | ||||||||||
Net income |
41.9 | 113.1 | 155.0 | |||||||||||||||||||||
Net gains on derivative instruments |
7.2 | 18.7 | 25.9 | |||||||||||||||||||||
Reclassifications of net (gains) losses on derivative instruments |
(2.4 | ) | 16.1 | 13.7 | ||||||||||||||||||||
Benefit plans |
2.2 | 2.2 | ||||||||||||||||||||||
Foreign currency translation adjustments |
(12.1 | ) | (12.1 | ) | ||||||||||||||||||||
Dividends and distributions |
(22.8 | ) | (27.8 | ) | (50.6 | ) | ||||||||||||||||||
Equity transactions |
0.4 | 10.2 | 3.9 | 14.5 | ||||||||||||||||||||
Other |
(0.4 | ) | (0.4 | ) | ||||||||||||||||||||
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|||||||||||||
Balance December 31, 2010 |
$ | 261.0 | $ | 916.3 | $ | 1,052.0 | $ | 14.8 | $ | (34.3 | ) | $ | 2,209.8 | |||||||||||
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Asset (Liability) | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets and Liabilities |
Significant Other Observable Inputs |
Unobservable Inputs |
||||||||||||||
(Level 1) | (Level 2) | (Level 3) | Total | |||||||||||||
December 31, 2011: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | 7.4 | $ | 2.0 | $ | — | $ | 9.4 | ||||||||
Foreign currency contracts |
$ | — | $ | 7.0 | $ | — | $ | 7.0 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (43.9 | ) | $ | (34.6 | ) | $ | — | $ | (78.5 | ) | |||||
Interest rate contracts |
$ | — | $ | (52.4 | ) | $ | — | $ | (52.4 | ) | ||||||
September 30, 2011: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | 3.5 | $ | 3.3 | $ | — | $ | 6.8 | ||||||||
Foreign currency contracts |
$ | — | $ | 5.3 | $ | — | $ | 5.3 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (28.1 | ) | $ | (16.1 | ) | $ | — | $ | (44.2 | ) | |||||
Foreign currency contracts |
$ | — | $ | (3.3 | ) | $ | — | $ | (3.3 | ) | ||||||
Interest rate contracts |
$ | — | $ | (44.4 | ) | $ | — | $ | (44.4 | ) | ||||||
December 31, 2010: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | 2.9 | $ | 18.0 | $ | — | $ | 20.9 | ||||||||
Foreign currency contracts |
$ | — | $ | 2.8 | $ | — | $ | 2.8 | ||||||||
Interest rate contracts |
$ | — | $ | 7.2 | $ | — | $ | 7.2 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (22.3 | ) | $ | (12.0 | ) | $ | — | $ | (34.3 | ) | |||||
Foreign currency contracts |
$ | — | $ | (0.9 | ) | $ | — | $ | (0.9 | ) | ||||||
Interest rate contracts |
$ | — | $ | (8.0 | ) | $ | — | $ | (8.0 | ) | ||||||
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Volumes | ||||||||
December 31, | ||||||||
Commodity |
2011 | 2010 | ||||||
LPG (millions of gallons) |
125.4 | 123.7 | ||||||
Natural gas (millions of dekatherms) |
28.0 | 34.3 | ||||||
Electricity calls (millions of kilowatt-hours) |
1,538.3 | 1,612.7 | ||||||
Electricity puts (millions of kilowatt-hours) |
175.4 | — |
Derivative Assets | Derivative (Liabilities) | |||||||||||||||||||
Balance Sheet | Fair Value December 31, |
Balance Sheet | Fair Value December 31, |
|||||||||||||||||
Location | 2011 | 2010 | Location | 2011 | 2010 | |||||||||||||||
Derivatives Designated as Hedging Instruments: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments and Other assets |
$ | 1.7 | $ | 16.6 | Derivative financial instruments and Other noncurrent liabilities |
$ | (62.4 | ) | $ | (20.9 | ) | ||||||||
Foreign currency contracts |
Derivative financial instruments and Other assets |
7.0 | 2.8 | Derivative financial instruments and Other noncurrent liabilities |
— | (0.9 | ) | |||||||||||||
Interest rate contracts |
Other assets | — | 7.2 | Derivative financial instruments and Other noncurrent liabilities |
(52.4 | ) | (8.0 | ) | ||||||||||||
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|||||||||||||
Total Derivatives Designated as Hedging Instruments |
$ | 8.7 | $ | 26.6 | $ | (114.8 | ) | $ | (29.8 | ) | ||||||||||
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|||||||||||||
Derivatives Accounted for under ASC 980: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | $ | — | $ | 2.6 | Derivative financial instruments and Other noncurrent liabilities |
$ | (16.1 | ) | $ | (13.4 | ) | ||||||||
Derivatives Not Designated as Hedging Instruments: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | $ | 7.7 | $ | 1.7 | |||||||||||||||
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|||||||||||||
Total Derivatives |
$ | 16.4 | $ | 30.9 | $ | (130.9 | ) | $ | (43.2 | ) | ||||||||||
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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 |
||||||||||||||||
2011 | 2010 | 2011 | 2010 | Interests into Income | ||||||||||||||
Cash Flow |
||||||||||||||||||
Hedges: |
||||||||||||||||||
Commodity contracts |
$ | (57.2 | ) | $ | 19.9 | $ | (19.5 | ) | $ | (20.0 | ) | Cost of sales | ||||||
Foreign currency contracts |
1.9 | 2.9 | 0.9 | (1.0 | ) | Cost of sales | ||||||||||||
Interest rate contracts |
(9.6 | ) | 14.4 | (1.9 | ) | (3.7 | ) | Interest expense / other income |
||||||||||
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|
|||||||||||
Total |
$ | (64.9 | ) | $ | 37.2 | $ | (20.5 | ) | $ | (24.7 | ) | |||||||
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|
|||||||||||
Net Investment |
||||||||||||||||||
Hedges: |
||||||||||||||||||
Foreign currency contracts |
$ | 0.5 | $ | 0.5 | ||||||||||||||
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|
Derivatives Not Designated as Hedging Instruments:
Gain (Loss) Recognized in Income |
Location of Gain (Loss) Recognized in Income |
|||||||||
2011 | 2010 | |||||||||
Commodity contracts |
$ | 3.1 | $ | (0.1 | ) | Cost of sales | ||||
Commodity contracts |
(0.1 | ) | 0.2 | Operating expenses / other income | ||||||
Foreign currency contracts |
0.5 | — | Other income | |||||||
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|
|||||||
Total |
$ | 3.5 | $ | 0.1 | ||||||
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|
December 31, 2011 |
September 30, 2011 |
December 31, 2010 |
||||||||||
Non-utility LPG and natural gas |
$ | 249.1 | $ | 222.2 | $ | 234.7 | ||||||
Gas Utility natural gas |
87.7 | 95.6 | 100.1 | |||||||||
Materials, supplies and other |
53.9 | 45.2 | 52.5 | |||||||||
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|||||||
Total inventories |
$ | 390.7 | $ | 363.0 | $ | 387.3 | ||||||
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