UGI CORP /PA/, 10-Q filed on 2/4/2011
Quarterly Report
Document and Entity Information
3 Months Ended
Dec. 31, 2010
Jan. 31, 2011
Mar. 31, 2010
Document and Entity Information [Abstract]
 
 
 
Entity Registrant Name
UGI CORP /PA/ 
 
 
Entity Central Index Key
0000884614 
 
 
Document Type
10-Q 
 
 
Document Period End Date
2010-12-31 
 
 
Amendment Flag
FALSE 
 
 
Document Fiscal Year Focus
2011 
 
 
Document Fiscal Period Focus
Q1 
 
 
Current Fiscal Year End Date
09/30 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Public Float
 
 
2,848,571,109 
Entity Common Stock, Shares Outstanding
 
111,111,989 
 
Condensed Consolidated Balance Sheets (unaudited) (USD $)
In Millions
3 Months Ended
Dec. 31,
2010
2009
Year Ended
Sep. 30, 2010
Current assets:
 
 
 
Cash and cash equivalents
$ 139 
$ 216 
$ 261 
Restricted cash
19 
10 
35 
Accounts receivable (less allowances for doubtful accounts of $37.5, $34.6 and $38.0, respectively)
907 
765 
468 
Accrued utility revenues
75 
84 
14 
Inventories
387 
387 
314 
Deferred income taxes
41 
45 
33 
Utility regulatory assets
11 
10 
26 
Derivative financial instruments
23 
47 
11 
Prepaid expenses and other current assets
32 
32 
59 
Total current assets
1,635 
1,596 
1,220 
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $1,953.8, $1,916.5 and 1,822.5, respectively)
3,109 
2,915 
3,053 
Goodwill
1,565 
1,568 
1,563 
Intangible assets, net
150 
159 
150 
Other assets
349 
216 
388 
Total assets
6,808 
6,453 
6,374 
Current liabilities:
 
 
 
Current maturities of long-term debt
548 
95 
574 
Bank loans
274 
220 
200 
Accounts payable
668 
531 
373 
Derivative financial instruments
28 
34 
58 
Other current liabilities
506 
508 
470 
Total current liabilities
2,024 
1,386 
1,675 
Long-term debt
1,448 
2,025 
1,432 
Deferred income taxes
602 
514 
601 
Deferred investment tax credits
Other noncurrent liabilities
519 
569 
599 
Total liabilities
4,598 
4,500 
4,313 
Commitments and contingencies (note 9)
 
 
 
UGI Corporation stockholders' equity
 
 
 
UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,434,694, 115,400,294 and 115,261,294 shares, respectively)
916 
878 
906 
Retained earnings
1,052 
881 
967 
Accumulated other comprehensive income (loss)
15 
(28)
(10)
Treasury stock, at cost
(34)
(49)
(38)
Total UGI Corporation stockholders' equity
1,949 
1,682 
1,825 
Noncontrolling interests, principally in AmeriGas Partners
261 
271 
237 
Total equity
2,210 
1,952 
2,062 
Total liabilities and equity
$ 6,808 
$ 6,453 
$ 6,374 
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)
In Millions, except Share data
Dec. 31, 2010
Sep. 30, 2010
Dec. 31, 2009
Current assets:
 
 
 
Accounts receivable, allowances for doubtful accounts
$ 38 
$ 35 
$ 38 
Accumulated depriciation, depletion and amortization on property, plant and equipment
1,954 
1,917 
1,823 
UGI Corporation stockholders' equity
 
 
 
UGI Common Stock, without par value
$ 0 
$ 0 
$ 0 
UGI Common Stock, without par value authorized
300,000,000 
300,000,000 
300,000,000 
UGI Common Stock, without par value, issued
115,434,694 
115,400,294 
115,261,294 
Condensed Consolidated Statements of Income (unaudited) (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended
Dec. 31,
2010
2009
Condensed Consolidated Statements of Income (unaudited) [Abstract]
 
 
Revenues
$ 1,766 
$ 1,619 
Costs and expenses:
 
 
Cost of sales
1,163 
1,027 
Operating and administrative expenses
312 
297 
Utility taxes other than income taxes
Depreciation
49 
48 
Amortization
Other income, net
(21)
(5)
Total costs and expenses
1,513 
1,376 
Operating income
252 
243 
Loss from equity investees
(0)
 
Interest expense
(33)
(34)
Income before income taxes
219 
209 
Income taxes
(64)
(64)
Net income
155 
146 
Less: net income attributable to noncontrolling interests,principally in AmeriGas Partners
(42)
(47)
Net income attributable to UGI Corporation
113 
98 
Earnings per common share attributable to UGI stockholders:
 
 
Basic
1.02 
0.9 
Diluted
1.01 
0.9 
Average common shares outstanding (thousands):
 
 
Basic
110,894 
109,077 
Diluted
112,416 
109,877 
Dividends declared per common share
$ 0.25 
$ 0.2 
Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)
In Millions
3 Months Ended
Dec. 31,
2010
2009
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 155 
$ 146 
Reconcile to net cash from operating activities:
 
 
Depreciation and amortization
55 
53 
Deferred income taxes, net
(21)
(10)
Provision for uncollectible accounts
10 
Net change in realized gains and losses deferred as cash flow hedges
25 
Other, net
Net change in:
 
 
Accounts receivable and accrued utility revenues
(486)
(437)
Inventories
(67)
(25)
Utility deferred fuel costs
16 
19 
Accounts payable
280 
207 
Other current assets
Other current liabilities
11 
25 
Net cash (used) provided by operating activities
(36)
17 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Expenditures for property, plant and equipment
(86)
(75)
Acquisitions of businesses, net of cash acquired
(38)
(4)
Decrease (increase) in restricted cash
15 
(3)
Other
(11)
Net cash used by investing activities
(104)
(93)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Dividends on UGI Common Stock
(28)
(22)
Distributions on AmeriGas Partners publicly held Common Units
(23)
(22)
Repayments of debt
(3)
(2)
Increase in bank loans
75 
57 
Receivables Facility net repayments
(12)
 
Issuances of UGI Common Stock
12 
Other
 
Net cash provided by financing activities
22 
13 
EFFECT OF EXCHANGE RATE CHANGES ON CASH
(3)
(2)
Cash and cash equivalents decrease
(121)
(65)
Cash and cash equivalents:
 
 
End of period
139 
216 
Beginning of period
261 
280 
Decrease
$ (121)
$ (65)
Nature of Operations
Nature of Operations
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 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”) and, prior to its October 1, 2010 merger with AmeriGas OLP, AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (together with AmeriGas OLP, 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, 2010, 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 32,400,450 Common Units held by the general public as limited partner interests.
   
Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1) conducts an LPG distribution business in France (“Antargaz”); (2) conducts an LPG distribution business in other European countries (“Flaga”); and (3) conducts an LPG distribution business in the Nantong region of China. We refer to our foreign operations collectively as “International Propane.” Enterprises, through UGI Energy Services, Inc. (“Energy Services”) and its subsidiaries, conducts an energy marketing, midstream infrastructure 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. 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 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.”
Significant Accounting Policies
Significant Accounting Policies
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, 2010 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, 2010 (“Company’s 2010 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 stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
   
Shares used in computing basic and diluted earnings per share are as follows:
                 
    Three Months Ended  
    December 31,  
    2010     2009  
Denominator (thousands of shares):
               
Average common shares outstanding for basic computation
    110,894       109,077  
Incremental shares issuable for stock options and awards
    1,522       800  
 
           
Average common shares outstanding for diluted computation
    112,416       109,877  
 
           
   
Comprehensive Income. The following table presents the components of comprehensive income for the three months ended December 31, 2010 and 2009:
                 
    Three Months Ended  
    December 31,  
    2010     2009  
Net income
  $ 155.0     $ 145.5  
Other comprehensive income
    29.7       31.2  
 
           
Comprehensive income (including noncontrolling interests)
    184.7       176.7  
Less: comprehensive income attributable to noncontrolling interests
    (46.7 )     (67.2 )
 
           
Comprehensive income attributable to UGI Corporation
  $ 138.0     $ 109.5  
 
           
   
Other comprehensive income 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 adjustments.
   
Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in an after-tax increase in other comprehensive income of $2.2 for the three months ended December 31, 2010 (See Notes 7 and 8).
   
Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
Accounting Changes
Accounting Changes
3.  
Accounting Changes
   
Adoption of New Accounting Standard
   
Transfers of Financial Assets. Effective October 1, 2010, the Company adopted new guidance regarding accounting for transfers of financial assets. Among other things, the new guidance eliminates the concept of Qualified Special Purpose Entities (“QSPEs”). It also amends previous derecognition guidance. The adoption of the new accounting guidance changed the Company’s accounting prospectively for sales of undivided interests in accounts receivable to the commercial paper conduit of a major bank under the Energy Services Receivables Facility. Effective October 1, 2010, trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet. Also effective October 1, 2010, the Company records interest expense on amounts owed to the commercial paper conduit. Prior to October 1, 2010, losses on sales of accounts receivable to the commercial paper conduit were reflected in other income, net. Additionally, effective October 1, 2010 borrowings and repayments associated with the Energy Services Receivables Facility are reflected in cash flows from financing activities. Previously such transactions were reflected in cash flows from operating activities. For further information, see Note 6.
Intangible Assets
Intangible Assets
4.  
Intangible Assets
   
The Company’s intangible assets comprise the following:
                         
    December 31,     September 30,     December 31,  
    2010     2010     2009  
Goodwill (not subject to amortization)
  $ 1,564.7     $ 1,562.7     $ 1,567.5  
 
                 
 
                       
Other intangible assets:
                       
Customer relationships, noncompete agreements and other
  $ 219.8     $ 215.4     $ 217.8  
Trademark (not subject to amortization)
    45.4       46.3       48.6  
 
                 
Gross carrying amount
    265.2       261.7       266.4  
Accumulated amortization
    (115.1 )     (111.6 )     (107.8 )
 
                 
Net carrying amount
  $ 150.1     $ 150.1     $ 158.6  
 
                 
   
The increases in goodwill and other intangible assets during the three months ended December 31, 2010 principally reflects the effects of acquisitions partially offset by the effects of currency translation. Amortization expense of intangible assets was $5.5 and $4.9 for the three months ended December 31, 2010 and 2009, respectively. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. Our expected aggregate amortization expense of intangible assets for the next five fiscal years is as follows: Fiscal 2011 — $20.1; Fiscal 2012 — $20.9; Fiscal 2013 — $20.7; Fiscal 2014 — $19.6; Fiscal 2015 — $14.9.
Segment Information
Segment Information
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 China and certain International Propane nonoperating entities (“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 2010 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, 2010:
                                                                         
                    Reportable Segments        
                                                    International Propane        
                    AmeriGas     Gas     Electric     Midstream &             Flaga &     Corporate  
    Total     Elims.     Propane     Utility     Utility     Marketing     Antargaz     Other     & Other (b)  
Revenues
  $ 1,765.6     $ (40.1 )(c)   $ 700.2     $ 321.1     $ 28.9     $ 279.6     $ 336.0     $ 118.9     $ 21.0  
 
                                                                       
Cost of sales
  $ 1,162.6     $ (39.3 )(c)   $ 435.3     $ 194.9     $ 18.6     $ 240.1     $ 214.6     $ 87.1     $ 11.3  
 
                                                                       
Segment profit:
                                                                       
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 )
 
                                                     
Income before income taxes
  $ 218.8     $ 0.1     $ 76.2     $ 65.0     $ 3.1     $ 26.8     $ 46.2     $ 1.2     $ 0.2  
 
                                                     
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  
Three Months Ended December 31, 2009:
                                                                         
                    Reportable Segments        
                                                    International Propane        
                    AmeriGas     Gas     Electric     Midstream &             Flaga &     Corporate  
    Total     Elims.     Propane     Utility     Utility     Marketing     Antargaz     Other     & Other (b)  
Revenues
  $ 1,618.8     $ (39.9 )(c)   $ 656.6     $ 327.8     $ 34.0     $ 312.3     $ 264.1     $ 42.8     $ 21.1  
 
                                                                       
Cost of sales
  $ 1,026.8     $ (38.5 )(c)   $ 389.6     $ 209.8     $ 21.5     $ 271.3     $ 135.2     $ 26.8     $ 11.1  
 
                                                                       
Segment profit:
                                                                       
Operating income
  $ 243.2     $ (0.2 )   $ 102.6     $ 63.7     $ 5.4     $ 27.7     $ 41.3     $ 2.6     $ 0.1  
Loss from equity investees
                                                     
Interest expense
    (34.2 )           (16.5 )     (10.2 )     (0.4 )           (6.1 )     (0.9 )     (0.1 )
 
                                                     
Income before income taxes
  $ 209.0     $ (0.2 )   $ 86.1     $ 53.5     $ 5.0     $ 27.7     $ 35.2     $ 1.7     $  
 
                                                     
Partnership EBITDA (a)
                  $ 123.0                                                  
Noncontrolling interests’ net income
  $ 47.1     $     $ 46.8     $     $     $     $ 0.3     $     $  
Depreciation and amortization
  $ 53.0     $ (0.1 )   $ 21.4     $ 12.3     $ 1.0     $ 2.1     $ 13.2     $ 2.8     $ 0.3  
Capital expenditures
  $ 75.0     $     $ 26.7     $ 13.0     $ 0.8     $ 22.5     $ 9.4     $ 2.2     $ 0.4  
Total assets (at period end)
  $ 6,452.7     $ (82.8 )   $ 1,830.3     $ 2,015.4     $ 115.8     $ 429.0     $ 1,749.8     $ 256.5     $ 138.7  
Bank loans (at period end)
  $ 219.5     $     $ 24.0     $ 169.2     $ 9.8     $     $     $ 16.5     $  
Investments in equity investees (at period end)
  $ 2.9     $     $     $     $     $     $     $ 2.9     $  
Goodwill (at period end)
  $ 1,567.5     $ (4.0 )   $ 670.8     $ 180.1     $     $ 11.8     $ 632.8     $ 68.9     $ 7.1  
     
(a)  
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
                 
Three months Ended December 31,   2010     2009  
Partnership EBITDA
  $ 113.3     $ 123.0  
Depreciation and amortization
    (22.7 )     (21.4 )
Noncontrolling interests (i)
    1.0       1.0  
 
           
Operating income
  $ 91.6     $ 102.6  
 
           
     
(i)  
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
 
(b)  
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.
 
(c)  
Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
Energy Services Accounts Receivable Securitization Facility
Energy Services Accounts Receivable Securitization Facility
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 2011, 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.
   
Effective October 1, 2010, the Company adopted a new accounting standard that changes the accounting for the Receivables Facility on a prospective basis (see Note 3). Effective October 1, 2010, 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. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet and any losses on sales of accounts receivable were reflected in other income, net.
   
During the three months ended December 31, 2010 and 2009, Energy Services transferred trade receivables totaling $290.8 and $296.7, respectively, to ESFC. During the three months ended December 31, 2010 and 2009, ESFC sold an aggregate $61.5 and $120.2, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At December 31, 2010, the balance of ESFC receivables was $109.7 and there were no amounts sold to the commercial paper conduit. At December 31, 2009, the outstanding balance of ESFC receivables was $88.3 which is reflected net of $27.6 that was sold to the commercial paper conduit and removed from the balance sheet.
Utility Regulatory Assets and Liabilities and Regulatory Matters
Utility Regulatory Assets and Liabilities and Regulatory Matters
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 2010 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,  
    2010     2010     2009  
Regulatory assets:
                       
Income taxes recoverable
  $ 83.6     $ 82.5     $ 80.5  
Underfunded pension and postretirement plans
    116.3       159.2       10.9  
Environmental costs
    22.5       22.6       25.8  
Deferred fuel and power costs
    18.1       36.6       10.3  
Other
    6.3       5.8       4.4  
 
                 
Total regulatory assets
  $ 246.8     $ 306.7     $ 131.9  
 
                 
 
                       
Regulatory liabilities:
                       
Postretirement benefits
  $ 10.8     $ 10.5     $ 9.5  
Environmental overcollections
    7.0       7.2       8.4  
Deferred fuel and power refunds
    15.2       8.3       40.3  
State tax benefits — distribution system repairs
    6.7       6.7        
 
                 
Total regulatory liabilities
  $ 39.7     $ 32.7     $ 58.2  
 
                 
   
Underfunded pension and postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and postretirement benefits which is probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP relating to accounting for retirement benefits. These costs are amortized over the average remaining future service lives of the plan participants.
   
Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets of $43.0 (see Note 8).
   
Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and, commencing January 1, 2010 Electric Utility’s default service tariffs, contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) 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 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, 2010, September 30, 2010 and December 31, 2009 were $2.2, $(1.4) and $(0.1), respectively.
   
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. As more fully described in Note 12, 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 under GAAP 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 GAAP relating to rate-regulated entities and Electric Utility’s DS procurement, implementation and contingency plans. At December 31, 2010 and September 30, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $13.4 and $19.7, 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 commencing January 1, 2010 through DS rates, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power — costs or refunds. Unrealized gains on FTRs at December 31, 2010 and 2009 were not material.
   
Other Regulatory Matters
   
Approval of Transfer of CPG Storage Assets. On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. CPG will transfer the natural gas storage facilities on April 1, 2011. The net book value of the storage facility assets was approximately $11.0 as of December 31, 2010.
   
Subsequent Event — CPG Base Rate Filing. On January 14, 2011, CPG filed a request with the PUC to increase its base operating revenues by $16.5 annually. The increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment. CPG is requesting that the new gas rates become effective March 15, 2011. However, the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. This review process is expected to last approximately nine months, which would delay implementation of the new rates until late October 2011.
Defined Benefit Pension and Other Postretirement Plans
Defined Benefit Pension and Other Postretirement Plans
8.  
Defined Benefit Pension and Other Postretirement Plans
   
After the plan merger described below, 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     Three Months Ended  
    December 31,     December 31,  
    2010     2009     2010     2009  
Service cost
  $ 2.3     $ 2.2     $ 0.1     $ 0.1  
Interest cost
    5.9       5.9       0.3       0.3  
Expected return on assets
    (6.5 )     (6.5 )     (0.1 )     (0.1 )
Amortization of:
                               
Prior service cost (benefit)
    0.1             (0.2 )     (0.1 )
Actuarial loss
    2.3       1.5       0.1       0.1  
 
                       
Net benefit cost
    4.1       3.1       0.2       0.3  
Change in associated regulatory liabilities
                0.8       0.7  
 
                       
Net expense
  $ 4.1     $ 3.1     $ 1.0     $ 1.0  
 
                       
   
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 $20.3 to the Pension Plan during the next twelve months. 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, 2010, nor are they expected to be material for all of Fiscal 2011.
   
We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans. We recorded pre-tax expense associated with these plans of $0.6 for each of the three-month periods ended December 31, 2010 and 2009.
   
Effective December 31, 2010, UGI Utilities merged its two defined benefit pension plans. The merged plan will maintain separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger and in accordance with GAAP relating to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010 which decreased other noncurrent liabilities by $46.7; decreased associated regulatory assets by $43.0; and increased pre-tax other comprehensive income by $3.7 (see Notes 2 and 7).
   
The following table provides a reconciliation of the projected benefit obligation (“PBO”), plan assets and the funded status of the merged Pension Plan as of December 31, 2010:
         
    Three Months  
    Ended  
    December 31,  
    2010  
Change in benefit obligations:
       
Benefit obligations — October 1, 2010
  $ 465.0  
Service cost
    2.2  
Interest cost
    5.8  
Actuarial gain
    (30.6 )
Benefits paid
    (4.7 )
 
     
Benefit obligations — December 31, 2010
  $ 437.7  
 
     
 
       
Change in plan assets:
       
Fair value of plan assets — October 1, 2010
  $ 287.9  
Actual gain on assets
    19.3  
Employer contributions
    1.8  
Benefits paid
    (4.7 )
 
     
Fair value of plan assets — December 31, 2010
  $ 304.3  
 
     
Funded status of the merged plan — December 31, 2010
  $ (133.4 )
 
     
 
Liabilities recorded in the balance sheet:
       
Unfunded liabilities — included in other current liabilities
  $ (20.3 )
Unfunded liabilities — included in other noncurrent liabilities
    (113.1 )
 
     
Net amount recognized
  $ (133.4 )
 
     
Amounts recorded in regulatory assets and liabilities:
       
Prior service cost
  $ 0.3  
Net actuarial loss
    112.7  
 
     
Total
  $ 113.0  
 
     
Amounts recorded in stockholders’ equity:
       
Prior service cost
  $ 0.1  
Net actuarial loss
    9.8  
 
     
Total
  $ 9.9  
 
     
   
The accumulated benefit obligation (“ABO”) of the merged plan at December 31, 2010 is $391.2. Actuarial assumptions for the merged plan at December 31, 2010 are as follows: discount rate — 5.5%; expected return on plan assets — 8.5%; rate of increase in salary levels — 3.8%.
Commitments and Contingencies
Commitments and Contingencies
9.  
Commitments and Contingencies
   
Environmental Matters
   
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, 2010, 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 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 the third-party defendants are responsible for an equitable share of any costs Frontier would be required to pay to the City for cleaning up tar deposits in the Penobscot River. Frontier alleged that through ownership and control of a subsidiary, Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Frontier made similar allegations of control against another third-party defendant, CenterPoint Energy Resources Corporation (“CenterPoint”), whose predecessor owned the Bangor subsidiary from 1928 to 1944. Frontier’s third-party claims were stayed pending a resolution of the City’s suit against Frontier, which was tried in September 2005. On June 27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup costs, which were estimated at $18. On February 14, 2007, Frontier and the City entered into a settlement agreement pursuant to which Frontier agreed to pay $7.6. The City’s suit was dismissed, and Frontier filed the current action against the original third-party defendants, repeating its claims for contribution. On September 22, 2009, the court granted summary judgment in favor of co-defendant CenterPoint. UGI Utilities subsequently filed a motion for summary judgment with respect to Frontier’s claims and the court referred the motion to a magistrate judge for findings and a recommendation. On October 19, 2010, the magistrate judge entered an order recommending that 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.
   
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 believes that the cost could be as high as $20. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
   
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 in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites could total approximately $215 and asserted that UGI Utilities is responsible for approximately $103 of this amount. 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, Waterbury North, pursuant to a lease. In April 2009, the court conducted a trial to determine whether UGI Utilities operated any of the nine remaining sites that were owned and operated by former subsidiaries. On May 22, 2009, the court granted judgment in favor of UGI Utilities with respect to all nine sites. The Northeast Companies have appealed the decision. With respect to Waterbury North, the Northeast Companies are expected to complete additional environmental investigations in early 2011. A second phase of the trial is scheduled for August 2011 to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25.
   
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 has communicated the results of its research to DEC 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
   
Purported AmeriGas Class Action Lawsuits. On May 27, 2009, the General Partner was named as a defendant in a purported class action lawsuit in the Superior Court of the State of California in which plaintiffs are challenging AmeriGas OLP’s weight disclosure with regard to its portable propane grill cylinders. The complaint purports to be brought on behalf of a class of all consumers in the state of California during the four years prior to the date of the California complaint, who exchanged an empty cylinder and were provided with what is alleged to be only a partially filled cylinder. The plaintiffs seek restitution, injunctive relief, interest, costs, attorneys’ fees and other appropriate relief.
   
Since that initial suit, various AmeriGas entities have been named in more than a dozen similar suits that have been filed in various courts throughout the United States. These complaints purport to be brought on behalf of nationwide classes, which are loosely defined as including all purchasers of liquefied propane gas cylinders marketed or sold by AmeriGas OLP and another unaffiliated entity nationwide. The complaints claim that defendants’ conduct constituted unfair and deceptive practices that injured consumers and violated the consumer protection statutes of at least thirty-seven states and the District of Columbia, thereby entitling the class to damages, restitution, disgorgement, injunctive relief, costs and attorneys’ fees. Some of the complaints also allege violation of state “slack filling” laws. Additionally, the complaints allege that defendants were unjustly enriched by their conduct and they seek restitution of any unjust benefits received, punitive or treble damages, and pre-judgment and post-judgment interest. A motion to consolidate the purported class action lawsuits was heard by the Multidistrict Litigation Panel (“MDL Panel”) on September 24, 2009 in the United States District Court for the District of Kansas. By Order, dated October 6, 2009, the MDL Panel transferred the pending cases to the United States District Court for the Western District of Missouri. The AmeriGas entities named in the consolidated class action lawsuits have entered into a settlement agreement with the class. On May 19, 2010, the United States District Court for the District of Kansas granted the classes’ motion seeking preliminary approval of the settlement. On October 4, 2010, after the expiration of the time in which claims were, or could have been, made by the class members, the District Court ruled that the settlement was fair, reasonable and adequate to the class and granted final approval of the settlement. Two parties have appealed that final order and the matter is now awaiting review by the 8th Circuit Court of Appeals.
   
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 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, but have had no further requests from the District Attorneys since that initial inquiry.
   
Swiger, et al. v. UGI/AmeriGas, Inc. et al. In 1996, a fire occurred at the residence of Samuel and Brenda Swiger (the “Swigers”) when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, resulting from the defendants’ alleged failure to install underground propane lines at depths required by applicable safety standards. On December 14, 2010, AmeriGas OLP and its affiliates entered into a settlement agreement with the class, which was preliminarily approved by the Circuit Court of Monongalia County on January 13, 2011.
In 2005, the Swigers also 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 the Harrison County 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 Swigers have also requested that the Court rule that insurance coverage exists under the policies issued by the defendant insurance companies for damages sustained by the members of the class in the Monongalia County lawsuit. The Circuit Court of Harrison County has not certified the class in the Harrison County lawsuit at this time and, in October 2008, stayed that lawsuit pending resolution of the class action lawsuit in Monongalia County. We believe we have good defenses to the claims in this action.
Antargaz Competition Authority Matter. On July 21, 2009, Antargaz received a Statement of Objections from France’s Autorité de la concurrence (“Competition Authority”) with respect to the investigation of Antargaz by the General Division of Competition, Consumption and Fraud Punishment. The Statement alleged that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. On December 17, 2010, the Competition Authority issued its decision dismissing all objections against Antargaz. The appeal period has expired without an appeal having been filed. As a result of the decision, during the three-month period ended December 31, 2010 the Company reversed its previously recorded nontaxable accrual for this matter which increased net income by $9.4. This amount is reflected in other income, net, on the Condensed Consolidated Statement of Income.
We cannot predict with certainty 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. While the results of these other pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, the final outcome of such other matters will not have a significant effect on our consolidated financial position, results of operations or cash flows.
Equity
Equity
10.  
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, 2010 and 2009:
                                                 
            UGI Shareholders        
                            Accumulated              
                            Other              
    Non-                     Comprehensive              
    controlling     Common     Retained     Income     Treasury     Total  
    Interests     Stock     Earnings     (Loss)     Stock     Equity  
 
                                               
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 )
 
                                       
Comprehensive income
    46.7               113.1       24.9               184.7  
Dividends and distributions
    (22.8 )             (27.8 )                     (50.6 )
Equity transactions
    0.4       10.2                       3.9       14.5  
Other
    (0.4 )                                     (0.4 )
 
                                   
Balance December 31, 2010
  $ 261.0     $ 916.3     $ 1,052.0     $ 14.8     $ (34.3 )   $ 2,209.8  
 
                                   
 
                                               
Three Months Ended December 31, 2009:
                                               
Balance September 30, 2009
  $ 225.4     $ 875.6     $ 804.3     $ (38.9 )   $ (49.6 )   $ 1,816.8  
Net income
    47.1               98.4                       145.5  
Net gains on derivative instruments
    24.8                       0.2               25.0  
Reclassifications of net (gains) losses on derivative instruments
    (4.7 )                     15.7               11.0  
Benefit plans
                            0.8               0.8  
Foreign currency translation adjustments
                            (5.6 )             (5.6 )
 
                                       
Comprehensive income
    67.2               98.4       11.1               176.7  
Dividends and distributions
    (21.7 )             (21.9 )                     (43.6 )
Equity transactions
    0.2       2.2                       0.6       3.0  
Other
    (0.5 )                                     (0.5 )
 
                                   
Balance December 31, 2009
  $ 270.6     $ 877.8     $ 880.8     $ (27.8 )   $ (49.0 )   $ 1,952.4  
 
                                   
Fair Value Measurements
Fair Value Measurements
11.  
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, 2010, September 30, 2010 and December 31, 2009:
                                 
    Asset (Liability)  
    Quoted Prices                    
    in Active     Significant              
    Markets for     Other              
    Identical Assets     Observable     Unobservable        
    and Liabilities     Inputs     Inputs        
    (Level 1)     (Level 2)     (Level 3)     Total  
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 )
 
                               
September 30, 2010:
                               
Assets:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ 1.1     $ 10.7     $     $ 11.8  
Foreign currency contracts
  $     $ 0.8     $     $ 0.8  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (49.4 )   $ (20.3 )   $     $ (69.7 )
Foreign currency contracts
  $     $ (2.9 )   $     $ (2.9 )
Interest rate contracts
  $     $ (18.5 )   $     $ (18.5 )
 
                               
December 31, 2009:
                               
Assets:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ 0.6     $ 42.0     $     $ 42.6  
Foreign currency contracts
  $     $ 0.7     $     $ 0.7  
Interest rate contracts
  $     $ 3.9     $     $ 3.9  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (8.9 )   $ (1.7 )   $     $ (10.6 )
Foreign currency contracts
  $     $ (3.1 )   $     $ (3.1 )
Interest rate contracts
  $     $ (29.0 )   $     $ (29.0 )
The fair values of our Level 1 exchange-traded commodity futures and options 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 financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at December 31, 2010 were $1,996.7 and $2,100.5, respectively. The carrying amount and estimated fair value of our long-term debt at December 31, 2009 were $2,119.8 and $2,176.6, 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.
Diclosures About Derivative Instruments and Hedging Activities
Diclosures About Derivative Instruments And Hedging Activities
12.  
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 our derivative instruments, other than FTRs and gasoline futures and swap contracts (as further described below), generally qualify as hedges under GAAP 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. 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, the Partnership from time to time enters into price swap agreements to provide market price risk support to a limited number of its wholesale customers. These agreements are not designated as hedges for accounting purposes. The volumes of propane subject to these wholesale customer agreements at December 31, 2010 and 2009 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. 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, 2010 the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 25.2 million dekatherms and the maximum period over which Gas Utility is hedging natural gas market price risk is 9 months. At December 31, 2009, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures contracts was not material. 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 Accounting Standards Codification (“ASC”) No. 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 7).
Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. 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 under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At December 31, 2010, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $13.4 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying December 31, 2010 Condensed Consolidated Balance Sheet. In accordance with ASC 980 related to rate-regulated entities. Electric Utility has recorded equal and offsetting amounts in regulatory assets. At December 31, 2010, the volumes under Electric Utility’s forward electricity purchase contracts were 984.3 million kilowatt hours and the maximum period over which these contracts extend is 40 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 commencing January 1, 2010, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 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). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At December 31, 2010 and 2009, the volumes associated with Electric Utility FTRs totaled 342.0 million kilowatt hours and 730.0 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, 2010 and 2009, the volumes associated with Midstream & Marketing’s FTRs totaled 637.8 million kilowatt hours and 453.0 million kilowatt hours, respectively.
In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Energy Services enters into NYMEX and over-the-counter natural gas and electricity futures 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, 2010 and 2009, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:
                 
    Volumes  
Commodity   2010     2009  
 
               
LPG (millions of gallons)
    123.7       95.0  
Natural gas (millions of dekatherms)
    34.3       22.4  
Electricity (millions of kilowatt-hours)
    1,612.7       484.5  
At December 31, 2010, 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 3 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 8 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 25 months with a weighted average of 9 months. At December 31, 2010, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 5 months with a weighted average of 3 months.
We account for commodity price risk contracts (other than our Gas Utility natural gas futures and option contracts, Electric Utility electricity forward contracts, gasoline futures and swap contracts, and FTRs) 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, 2010, 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 $12.8.
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 effectively fixed the underlying euribor interest rate on its 380 variable-rate debt through its March 2011 maturity date through the use of pay-fixed, receive-variable interest rate swap agreements. Antargaz intends to refinance its 380 variable-rate term loan on a long-term basis by March 31, 2011. In anticipation of such refinancing, during Fiscal 2010 Antargaz entered into forward-starting interest rate swap agreements to hedge the underlying euribor rate of interest relating to 4 1/2 years of quarterly interest payments on 300 notional amount of long-term debt commencing March 31, 2011. Flaga has also fixed the underlying euribor interest rate on a substantial portion of its two term loans through their scheduled maturity dates ending in 2014 through the use of pay-fixed, receive-variable interest rate swap agreements. As of December 31, 2010 and 2009, the total notional amounts of our existing and anticipated variable-rate debt subject to interest rate swap agreements were 702.5 and 409.9, respectively.
Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At December 31, 2010, the total notional amount of unsettled IRPAs was $106.5. At December 31, 2009, the total notional amount of unsettled IRPAs was $150. 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, 2010, 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 $1.7.
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, 2010 and 2009, we were hedging a total of $96.1 and $89.0 of U.S. dollar-denominated LPG purchases, respectively. At December 31, 2010, 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 12 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. At December 31, 2010 and 2009, we were hedging a total of 14.5 and 30.8, respectively, of our euro-denominated net investments. As of December 31, 2010, such foreign currency contracts extend through March 2013.
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 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, 2010, the amount of net losses 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 $1.5. Gains and losses on net investment hedges remain in AOCI until such foreign operations are liquidated.
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 major energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and option contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. At December 31, 2010 and 2009, restricted cash in these accounts totaled $19.4 and $9.6, 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, 2010. We generally do not have credit-risk-related contingent features in our derivative contracts.
The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of December 31, 2010 and 2009:
                                         
    Derivative Assets     Derivative (Liabilities)  
        Fair Value         Fair Value  
    Balance Sheet   December 31,     Balance Sheet   December 31,  
    Location   2010     2009     Location   2010     2009  
Derivatives Designated as Hedging Instruments:
                                       
Commodity contracts
  Derivative financial instruments and Other assets   $ 16.6     $ 40.3     Derivative financial instruments and Other noncurrent liabilities   $ (20.9 )   $ (10.5 )
Foreign currency contracts
  Derivative financial instruments     2.8       0.7     Derivative financial instruments and Other noncurrent liabilities     (0.9 )     (3.1 )
Interest rate contracts
  Other assets     7.2       3.9     Derivative financial instruments and Other noncurrent liabilities     (8.0 )     (29.0 )
 
                               
Total Derivatives Designated as Hedging Instruments
      $ 26.6     $ 44.9         $ (29.8 )   $ (42.6 )
 
                               
 
                                       
Derivatives Accounted for under ASC 980:
                                       
 
                                       
Commodity contracts
  Derivative financial instruments   $ 2.6     $ 0.6     Derivative financial instruments and Other noncurrent liabilities   $ (13.4 )   $ (0.1 )
 
                                       
Derivatives Not Designated as Hedging Instruments:
                                       
Commodity contracts
  Derivative financial instruments   $ 1.7     $ 1.7                      
 
                               
 
                                       
Total Derivatives
      $ 30.9     $ 47.2         $ (43.2 )   $ (42.7 )
 
                               
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, 2010 and 2009:
Three Months Ended December 31,:
                                         
    Gain     Gain (Loss)     Location of  
    Recognized in     Reclassified from     Gain (Loss)  
    AOCI and     AOCI and Noncontrolling     Reclassified from  
    Noncontrolling Interests     Interests into Income     AOCI and Noncontrolling  
    2010     2009     2010     2009     Interests into Income  
Cash Flow
                                       
Hedges:
                                       
Commodity contracts
  $ 19.9     $ 28.6     $ (20.0 )   $ (17.7 )   Cost of sales
Foreign currency contracts
    2.9       2.6       (1.0 )     0.3     Cost of sales
Interest rate contracts
    14.4       5.3       (3.7 )     (4.4 )   Interest expense
 
                               
Total
  $ 37.2     $ 36.5     $ (24.7 )   $ (21.8 )        
 
                               
 
                                       
Net Investment
                                       
Hedges:
                                       
 
                                       
Foreign currency contracts
  $ 0.5     $ 1.0                          
 
                                   
                         
    Gain (Loss)                        
    Recognized in Income                     Location of Gain (Loss)  
    2010     2009                     Recognized in Income  
Derivatives Not Designated as Hedging Instruments:
                                       
Commodity contracts
  $ (0.1 )   $ 0.5                     Cost of sales
Commodity contracts
    0.2       0.2                     Operating expenses / other income
 
 
                       
Total
  $ 0.1     $ 0.7                          
 
                                   
The amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material for the three months ended December 31, 2010 or 2009.
We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery, or sale, of natural gas, LPG and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchases and normal sales exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
Inventories
Inventories
13.  
Inventories
Inventories comprise the following:
                         
    December 31,     September 30,     December 31,  
    2010     2010     2009  
Non-utility LPG and natural gas
  $ 234.7     $ 157.9     $ 166.9  
Gas Utility natural gas
    100.1       111.5       170.2  
Materials, supplies and other
    52.5       44.6       50.3  
 
                 
Total inventories
  $ 387.3     $ 314.0     $ 387.4  
 
                 
At December 31, 2010, 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, 2010, September 30, 2010 and December 31, 2009 comprising 3.6 billion cubic feet (“bcf”), 8.0 bcf and 7.4 bcf of natural gas was $18.9, $41.9 and $63.1, respectively.
Subsequent Event-Partnership Debt Refinancing
Subsequent Event-Partnership Debt Refinancing
14.  
Subsequent Event – Partnership Debt Refinancing
On January 20, 2011, AmeriGas Partners announced that holders of approximately $327.9 in aggregate principal amount of its 7.25% Senior Notes due May 2015, representing approximately 79% of the total $415 principal amount outstanding, had validly tendered their notes in connection with the Partnership’s January 5, 2011 tender offer. The tendered notes were redeemed on January 20, 2011 at an effective price of 100.95%, plus a consent fee. On January 21, 2011, the Partnership issued a notice of full optional redemption at a price of 103.625% for the remaining outstanding $87.1 aggregate principal amount of 7.25% Senior Notes and a notice of full optional redemption at par for the $14.6 outstanding balance of its 8.875% Senior Notes due May 2011. The redemption of these notes is scheduled to occur on February 22, 2011. The tendered 7.25% Senior Notes were, and the called notes will be, redeemed with proceeds from the January 20, 2011 issuance of $470 aggregate principal amount of AmeriGas Partners 6.50% Senior Notes due 2021. The 6.50% Senior Notes due 2021 rank pari passu with AmeriGas Partners’ outstanding senior debt. The Partnership expects to record a loss of approximately $19.0 associated with these transactions during the second quarter of Fiscal 2011 which is expected to reduce net income attributable to UGI Corporation by approximately $5.0. Because the 8.875% Senior Notes will be refinanced with proceeds from the previously mentioned issuance of AmeriGas Partners 6.50% Senior Notes due 2021, the outstanding principal amount of the 8.875% Senior Notes due May 2011 has been classified as long-term debt on the December 31, 2010 Condensed Consolidated Balance Sheet.