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Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2010
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number 1-1398
UGI UTILITIES, INC.
(Exact name of registrant as specified in its charter)
     
Pennsylvania   23-1174060
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification No.)
UGI UTILITIES, INC.
2525 N. 12th Street, Suite 360
Reading, PA
(Address of principal executive offices)
19612
(Zip Code)
(610) 796-3400
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer þ   Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
At January 31, 2011, there were 26,781,785 shares of UGI Utilities, Inc. Common Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI Corporation.
 
 

 

 


 

UGI UTILITIES, INC. AND SUBSIDIARIES
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 Exhibit 12.1
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Thousands of dollars)
                         
    December 31,     September 30,     December 31,  
    2010     2010     2009  
ASSETS
                       
 
                       
Current assets:
                       
Cash and cash equivalents
  $ 11,646     $ 4,318     $ 12,678  
Restricted cash
    3,884       4,698       656  
Accounts receivable (less allowances for doubtful accounts of $8,492, $7,072 and $11,889, respectively)
    124,417       64,844       132,499  
Accounts receivable — related parties
    12,347       6,313       8,417  
Accrued utility revenues
    75,284       13,988       84,395  
Inventories
    108,027       118,858       177,087  
Deferred income taxes
    21,593       19,431       27,162  
Regulatory assets
    10,633       26,100       10,344  
Derivative financial instruments
    2,750       486       874  
Prepaid expenses & other current assets
    5,648       21,117       4,590  
 
                 
Total current assets
    376,229       280,153       458,702  
 
                       
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $746,891, $734,739 and $703,722, respectively)
    1,399,042       1,394,585       1,365,441  
 
                       
Goodwill
    180,145       180,145       180,145  
Regulatory assets
    236,221       280,602       121,646  
Other assets
    10,746       4,091       5,470  
 
                 
 
                       
Total assets
  $ 2,202,383     $ 2,139,576     $ 2,131,404  
 
                 
 
                       
LIABILITIES AND STOCKHOLDER’S EQUITY
                       
 
                       
Current liabilities:
                       
Bank loans
  $ 74,000     $ 17,000     $ 179,000  
Accounts payable — trade
    68,328       61,297       70,845  
Accounts payable — related parties
    8,494       8,144       6,424  
Deferred fuel refunds
    15,175       8,295       40,343  
Derivative financial instruments
    5,890       10,564       125  
Other current liabilities
    148,909       133,935       127,755  
 
                 
Total current liabilities
    320,796       239,235       424,492  
 
                       
Long-term debt
    640,000       640,000       640,000  
Deferred income taxes
    286,347       281,101       184,641  
Deferred investment tax credits
    5,222       5,311       5,579  
Pension and postretirement benefit obligations
    117,127       161,338       151,561  
Other noncurrent liabilities
    74,785       78,137       60,278  
 
                 
Total liabilities
    1,444,277       1,405,122       1,466,551  
 
                       
Commitments and contingencies (note 7)
                       
 
                       
Common stockholder’s equity:
                       
Common Stock, $2.25 par value (authorized - 40,000,000 shares; issued and outstanding - 26,781,785 shares)
    60,259       60,259       60,259  
Additional paid-in capital
    467,903       467,631       467,160  
Retained earnings
    234,758       217,960       219,487  
Accumulated other comprehensive loss
    (4,814 )     (11,396 )     (82,053 )
 
                 
Total common stockholder’s equity
    758,106       734,454       664,853  
 
                 
 
                       
Total liabilities and stockholder’s equity
  $ 2,202,383     $ 2,139,576     $ 2,131,404  
 
                 
See accompanying notes to condensed consolidated financial statements.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Thousands of dollars)
                 
    Three Months Ended  
    December 31,  
    2010     2009  
 
               
Revenues
  $ 350,516     $ 362,203  
 
           
 
               
Costs and expenses:
               
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
    213,484       231,217  
Operating and administrative expenses
    39,894       44,222  
Operating and administrative expenses — related parties
    2,925       1,192  
Taxes other than income taxes
    4,358       4,528  
Depreciation
    12,606       12,681  
Amortization
    632       607  
Other income, net
    (2,263 )     (1,517 )
 
           
 
    271,636       292,930  
 
           
 
               
Operating income
    78,880       69,273  
Interest expense
    10,633       10,637  
 
           
 
               
Income before income taxes
    68,247       58,636  
Income taxes
    27,173       23,473  
 
           
 
               
Net income
  $ 41,074     $ 35,163  
 
           
See accompanying notes to condensed consolidated financial statements.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Thousands of dollars)
                 
    Three Months Ended  
    December 31,  
    2010     2009  
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net income
  $ 41,074     $ 35,163  
Adjustments to reconcile net income to net cash from operating activities:
               
Depreciation and amortization
    13,238       13,288  
Deferred income taxes, net
    (2,260 )     11,724  
Provision for uncollectible accounts
    3,161       4,845  
Other, net
    2,560       2,180  
Net change in:
               
Accounts receivable and accrued utility revenues
    (130,063 )     (131,512 )
Inventories
    10,832       19,511  
Deferred fuel and power costs
    15,459       18,737  
Accounts payable
    29,886       15,258  
Storage agreements security deposits
          3,500  
Other current assets
    3,546       570  
Other current liabilities
    4,341       13,414  
 
           
Net cash (used) provided by operating activities
    (8,226 )     6,678  
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Expenditures for property, plant and equipment
    (17,587 )     (13,810 )
Net costs of property, plant and equipment disposals
    (668 )     (671 )
Decrease (increase) in restricted cash
    814       (656 )
 
           
Net cash used by investing activities
    (17,441 )     (15,137 )
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Payment of dividends
    (24,277 )     (17,386 )
Increase in bank loans
    57,000       25,000  
Other
    272        
 
           
Net cash provided by financing activities
    32,995       7,614  
 
           
 
               
Cash and cash equivalents increase (decrease)
  $ 7,328     $ (845 )
 
           
 
               
CASH AND CASH EQUIVALENTS:
               
End of period
  $ 11,646     $ 12,678  
Beginning of period
    4,318       13,523  
 
           
Increase (decrease)
  $ 7,328     $ (845 )
 
           
See accompanying notes to condensed consolidated financial statements.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
1.  
Nature of Operations
   
UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“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.” PNG also has a heating, ventilation and air-conditioning service business (“UGI Penn HVAC Services, Inc.”) which operates principally in the PNG Gas service territory.
   
The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.
2.  
Significant Accounting Policies
   
Basis of Presentation. Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or “the Company”). We eliminate all significant intercompany accounts when we consolidate.
   
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.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
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
  $ 41,074     $ 35,163  
Other comprehensive income
    6,582       1,033  
 
           
Comprehensive income
  $ 47,656     $ 36,196  
 
           
   
Other comprehensive income principally reflects net gains on interest rate protection agreements qualifying as cash flow hedges in the 2010 three month period and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.
   
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 $2,170 for the three months ended December 31, 2010 (see Notes 5 and 6).
   
Restricted Cash. Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.
   
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.
3.  
Segment Information
   
We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. UGI Penn HVAC Services, Inc. does not meet the quantitative thresholds for separate segment reporting under GAAP relating to business segment reporting and has been included in “Other.”
   
The accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s 2010 Annual Financial Statements and Notes. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States and all of our reportable segments’ long-lived assets are located in the United States.
   
Financial information by business segment follows:
   
Three Months Ended December 31, 2010:
                                 
            Reportable Segments        
            Gas     Electric        
    Total     Utility     Utility     Other  
 
                               
Revenues
  $ 350,516     $ 321,114     $ 28,940     $ 462  
Cost of sales
  $ 213,484     $ 194,913     $ 18,571     $  
Depreciation and amortization
  $ 13,238     $ 12,225     $ 1,013     $  
Operating income
  $ 78,880     $ 75,067     $ 3,603     $ 210  
Interest expense
  $ 10,633     $ 10,108     $ 525     $  
Income before income taxes
  $ 68,247     $ 64,959     $ 3,078     $ 210  
 
                               
Total assets (at period end)
  $ 2,202,383     $ 2,061,337     $ 141,046     $  
Goodwill (at period end)
  $ 180,145     $ 180,145     $     $  
Capital expenditures
  $ 17,587     $ 16,086     $ 1,501     $  
   
Three Months Ended December 31, 2009:
                                 
            Reportable Segments        
            Gas     Electric        
    Total     Utility     Utility     Other  
 
                               
Revenues
  $ 362,203     $ 327,809     $ 33,999     $ 395  
Cost of sales
  $ 231,217     $ 209,760     $ 21,457     $  
Depreciation and amortization
  $ 13,288     $ 12,299     $ 989     $  
Operating income
  $ 69,273     $ 63,728     $ 5,359     $ 186  
Interest expense
  $ 10,637     $ 10,246     $ 391     $  
Income before income taxes
  $ 58,636     $ 53,482     $ 4,968     $ 186  
 
                               
Total assets (at period end)
  $ 2,131,404     $ 2,015,558     $ 115,846     $  
Goodwill (at period end)
  $ 180,145     $ 180,145     $     $  
Capital expenditures
  $ 13,810     $ 13,040     $ 770     $  
4.  
Inventories
   
Inventories comprise the following:
                         
    December 31,     September 30,     December 31,  
    2010     2010     2009  
Gas Utility natural gas
  $ 100,121     $ 111,531     $ 170,235  
Materials, supplies and other
    7,905       7,327       6,852  
 
                 
Total inventories
  $ 108,026     $ 118,858     $ 177,087  
 
                 

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
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 (see Note 8). 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 terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.
   
The carrying value of gas storage inventories released under the SCAAs at December 31, 2010, September 30, 2010 and December 31, 2009 comprising 11.1 billion cubic feet (“bcf”), 11.7 bcf, and 11.4 bcf of natural gas, was $58,363, $62,653 and $95,911, respectively. In conjunction with the SCAAs, at December 31, 2010, September 30, 2010 and December 31, 2009, UGI Utilities held a total of $22,500 of security deposits received from its SCAA counterparties. These amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets.
5.  
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 5 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
  $ 83,601     $ 82,525     $ 80,524  
Underfunded pension and postretirement plans
    116,288       159,154       10,908  
Environmental costs
    22,515       22,587       25,812  
Deferred fuel and power costs
    18,113       36,597       10,344  
Other
    6,337       5,839       4,402  
 
                 
Total regulatory assets
  $ 246,854     $ 306,702     $ 131,990  
 
                 
 
                       
Regulatory liabilities:
                       
Postretirement benefits
  $ 10,835     $ 10,472     $ 9,538  
Environmental overcollections
    6,990       7,211       8,392  
Deferred fuel and power refunds
    15,175       8,298       40,343  
State tax benefits — distribution system repairs
    6,716       6,685        
 
                 
Total regulatory liabilities
  $ 39,716     $ 32,666     $ 58,273  
 
                 

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
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 $42,962 (see Note 6).
   
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 $2,214, $(1,359) and $(125), 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 10, 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 $13,369 and $19,702, 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.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
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 UGI Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI. CPG will transfer the natural gas storage facilities on April 1, 2011. The net book value of the storage facility assets was approximately $11,000 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 $16,500 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.
6.  
Defined Benefit Pension and Other Postretirement Plans
   
Subsequent to the December 31, 2010 plan merger described below, we currently sponsor one defined benefit pension plan (“Pension Plan”) for employees hired prior to January 1, 2009 of UGI Utilities, PNG, CPG, UGI and certain of UGI’s other wholly owned domestic subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and a limited number of active employees, and postretirement life insurance benefits to nearly all active and retired employees.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
Net periodic pension expense and other postretirement benefit costs relating to our employees include the following components:
                                 
    Pension Benefits     Other Postretirement Benefits  
    Three Months Ended     Three Months Ended  
    December 31,     December 31,  
    2010     2009     2010     2009  
Service cost
  $ 1,925     $ 1,745     $ 54     $ 40  
Interest cost
    5,355       5,284       182       212  
Expected return on assets
    (6,022 )     (5,858 )     (130 )     (126 )
Amortization of:
                               
Prior service cost (benefit)
    62       9       (174 )     (102 )
Actuarial loss
    2,128       1,333       121       89  
 
                       
Net benefit cost
    3,448       2,513       53       113  
Change in associated regulatory liabilities
                785       736  
 
                       
Net expense
  $ 3,448     $ 2,513     $ 838     $ 849  
 
                       
   
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 $20,303 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. 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 participate in an unfunded and non-qualified defined benefit supplemental executive retirement plan. Net benefit costs associated with this plan for all periods presented were not material.
   
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 pension and postretirement benefit obligations by $46,672; decreased associated regulatory assets by $42,962; and increased pre-tax other comprehensive income by $3,710 (see Notes 2 and 5).

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
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
  $ 464,976  
Service cost
    2,188  
Interest cost
    5,805  
Actuarial gain
    (30,639 )
Benefits paid
    (4,664 )
 
     
Benefit obligations — December 31, 2010
  $ 437,666  
 
     
 
       
Change in plan assets:
       
Fair value of plan assets — October 1, 2010
  $ 287,902  
Actual gain on assets
    19,285  
Employer contribution
    1,788  
Benefits paid
    (4,664 )
 
     
Fair value of plan assets — December 31, 2010
  $ 304,311  
 
     
Funded status of the merged plan — December 31, 2010
  $ (133,355 )
 
     
 
       
Liabilities recorded in the balance sheet:
       
Unfunded liabilities — included in other current liabilities
  $ (20,303 )
Unfunded liabilities — included in other noncurrent liabilities
    (113,052 )
 
     
Net amount recognized
  $ (133,355 )
 
     
Amounts recorded in regulatory assets and liabilities:
       
Prior service cost
  $ 257  
Net actuarial loss
    112,733  
 
     
Total
  $ 112,990  
 
     
Amounts recorded in stockholder’s equity:
       
Prior service cost
  $ 29  
Net actuarial loss
    9,925  
 
     
Total
  $ 9,954  
 
     
   
The accumulated benefit obligation (“ABO”) of the merged plan at December 31, 2010 is $391,192. 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%.
7.  
Commitments and Contingencies
   
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.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
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 $22,000 in remediation costs and paid $26,000 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 $14,000. Trial took place in March 2009 and the court’s decision is pending.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
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 $18,000. On February 14, 2007, Frontier and the City entered into a settlement agreement pursuant to which Frontier agreed to pay $7,600. 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 $2,300 and expects to spend another $11,000 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 $10,000. KeySpan believes that the cost could be as high as $20,000. 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 $215,000 and asserted that UGI Utilities is responsible for approximately $103,000 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 $25,000.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
We cannot predict with certainty the final results of any of the environmental 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.
8.  
Related Party Transactions
   
UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as operating and administrative expenses — related parties in the Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries, principally payroll-related services. Amounts billed to these entities by UGI Utilities for all periods presented were not material.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
From time to time, UGI Utilities is a party to SCAAs with Energy Services. At December 31, 2010, UGI Utilities was a party to two three-year SCAAs with Energy Services expiring October 31, 2012 and October 31, 2013 and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives 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. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $2,293 and $7,484 during the three months ended December 31, 2010 and 2009, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets, were $15,000, $7,500 and $7,500 as of December 31, 2010, September 30, 2010 and December 31, 2009, respectively.
   
UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at December 31, 2010, comprising approximately 7.5 bcf of natural gas, was $39,447. The carrying value of these gas storage inventories at September 30, 2010, comprising approximately 4.1 bcf of natural gas, was $20,749. The carrying value of these gas storage inventories at December 31, 2009, comprising approximately 4.0 bcf of natural gas, was $32,855.
   
UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the months of November through March. In addition, from time to time, Gas Utility purchases natural gas or pipeline capacity from Energy Services. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three months ended December 31, 2010 and 2009, totaled $18,755 and $16,282, respectively.
   
From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2010 and 2009, revenues associated with such sales to Energy Services totaled $22,034 and $9,244, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to those transactions already described above). During the three months ended December 31, 2010 and 2009, the aggregate amount of such purchases totaled $13,497 and $5,977, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
9.  
Fair Value Measurements
   
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
  $ 2,398     $ 352     $     $ 2,750  
Interest rate contracts
  $     $ 7,249     $     $ 7,249  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (1,438 )   $ (11,932 )   $     $ (13,370 )
 
                               
September 30, 2010:
                               
Assets:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ 61     $ 425     $     $ 486  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (3,263 )   $ (17,798 )   $     $ (21,061 )
 
                               
December 31, 2009:
                               
Assets:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ 233     $ 641     $     $ 874  
Liabilities:
                               
Derivative financial instruments:
                               
Commodity contracts
  $ (125 )   $     $     $ (125 )
   
The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts and certain non exchange-traded electricity forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments and electricity forward contracts, which are designated as Level 2, are generally based upon recent market transactions and related market indicators.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
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 $640,000 and $720,011 respectively. The carrying amount and estimated fair value of our long-term debt at December 31, 2009 were $640,000 and $697,137, 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 types of debt.
10.  
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 and (2) interest 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 commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations.
   
Commodity Price Risk
   
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. With respect to natural gas futures and option contracts, gains and losses on Gas Utility unsettled 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”) 980 related to rate-regulated entities.
   
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 $13,369 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the 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 on the December 31, 2010 Condensed Consolidated Balance Sheet.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. 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 relating to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 5). 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.
   
At December 31, 2010, the volume of natural gas associated with our unsettled NYMEX natural gas futures and option contracts totaled 25.2 million dekatherms and the maximum period over which we are currently hedging natural gas futures and option contracts is 9 months. At December 31, 2009, the volume of natural gas associated with unsettled NYMEX natural gas futures contracts was not material. At December 31, 2010, the volume of electricity under Electric Utility’s forward electricity purchase contracts was 984.3 million kilowatt hours and the maximum period over which these contracts extend is 40 months with a weighted average term of 16 months.
   
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. The volumes of gasoline under these contracts and the values of these contracts were not material for all periods presented.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
Interest Rate Risk
   
Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in accumulated other comprehensive income (“AOCI”), to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. As of December 31, 2010, the total notional amount of our unsettled IRPA contracts was $106,500. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of long-term debt forecasted to occur in September 2012 and September 2013. There were no unsettled IPRA contracts outstanding at December 31, 2009.
   
We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in AOCI, 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 IRPAs expected to be reclassified into earnings during the next twelve months is $1,165.
   
Derivative Financial Instrument Credit Risk
   
Our natural gas exchange-traded futures and options contracts are guaranteed by the NYMEX and have limited credit risk. These contracts generally require cash deposits in margin accounts. At December 31, 2010 and 2009, restricted cash in margin accounts totaled $3,884 and $656, respectively. 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)  
    Balance Sheet     Fair Value     Balance Sheet     Fair Value  
    Location     2010     2009     Location     2010     2009  
Derivatives Designated as Hedging Instruments:
                                               
Interest rate contracts
  Other Assets     $ 7,249     $                          
 
                                               
Derivatives Accounted for Under ASC 980:
                                               
Commodity contracts
  Derivative financial instruments       2,566       644     Derivative financial instruments and Other noncurrent liabilities     $ (13,370 )   $ (125 )
 
                                               
Derivatives Not Designated as Hedging Instruments:
                                               
Commodity contracts
  Derivative financial instruments       184       230                          
 
                                       
Total Derivatives
          $ 9,999     $ 874             $ (13,370 )   $ (125 )
 
                                       

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
   
The amount of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding IRPAs from ineffectiveness testing were not material for the three months ended December 31, 2010. During the three months ended December 31, 2010 and 2009, the amounts of IRPA net losses included in AOCI that were reclassified into net income were not material. During the three months ended December 31, 2009, the impact on net income from changes in the fair value of FTRs not accounted for under ASC 980 was not material.
   
We are also a party to a number of contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas, 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 purchase and normal sale exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
Information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability of oil, electricity and natural gas and the capacity to transport them to market areas; (3) changes in laws and regulations, including safety, tax and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability for environmental claims; (8) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor relations; (10) large customer, counterparty or supplier defaults; (11) increased uncollectible accounts expense; (12) liability for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas, including liability in excess of insurance coverage; (13) political, regulatory and economic conditions in the United States; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity market prices resulting in significantly higher cash collateral requirements.
These factors, and those factors set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on our business, financial condition or future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
ANALYSIS OF RESULTS OF OPERATIONS
The following analyses compare our results of operations for the three months ended December 31, 2010 (“2010 three-month period”) with the three months ended December 31, 2009 (“2009 three-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 3 to the condensed consolidated financial statements.
2010 three-month period compared with 2009 three-month period
                                 
                    Increase  
Three Months Ended December 31,   2010     2009     (Decrease)  
(Millions of dollars)                                
 
                               
Gas Utility:
                               
Revenues
  $ 321.1     $ 327.8     $ (6.7 )     (2.0 )%
Total margin (a)
  $ 126.2     $ 118.0     $ 8.2       6.9 %
Operating income
  $ 75.1     $ 63.7     $ 11.4       17.9 %
Income before income taxes
  $ 64.9     $ 53.5     $ 11.4       21.3 %
System throughput — bcf
    48.9       42.3       6.6       15.6 %
Heating degree days — % colder than normal (b)
    7.9 %     0.4 %            
 
                               
Electric Utility:
                               
Revenues
  $ 28.9     $ 34.0     $ (5.1 )     (15.0 )%
Total margin (a)
  $ 8.8     $ 10.7     $ (1.9 )     (17.8 )%
Operating income
  $ 3.6     $ 5.4     $ (1.8 )     (33.3 )%
Income before income taxes
  $ 3.1     $ 5.0     $ (1.9 )     (38.0 )%
Distribution sales — gwh
    250.5       242.4       8.1       3.3 %
     
bcf — billions of cubic feet. gwh — millions of kilowatt-hours.
 
(a)  
Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.6 million and $1.9 million during the three-month periods ended December 31, 2010 and 2009, respectively. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” in the Condensed Consolidated Statements of Income.
 
(b)  
For 2010, deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory. For 2009, deviation from average heating degree days for the 15-year period 1990-2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.
Gas Utility. Temperatures in the Gas Utility service territory based upon heating degree days were 7.9% colder than normal in the 2010 three-month period compared with temperatures that were 0.4% colder than normal in the prior-year period. Total distribution system throughput increased 6.6 bcf principally reflecting higher throughput to certain low-margin interruptible delivery service customers and the effects of the colder weather on core market customers. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Gas Utility revenues decreased $6.7 million during the 2010 three-month period principally reflecting a decline in revenues from retail core market customers ($19.7 million) partially offset by an $11.5 million increase in low-margin off-system sales. The decrease in core market revenues principally resulted from lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices. Under Gas Utility’s PGC recovery mechanisms, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $194.9 million in the 2010 three-month period compared with $209.8 million in the prior-year period reflecting lower average PGC rates.
Gas Utility total margin increased $8.2 million in the 2010 three-month period. The increase principally reflects a $7.0 million increase in core market margin resulting from the increase in core market throughput.
Gas Utility operating income and income before income taxes during the 2010 three-month period each increased $11.4 million. The increases principally reflect the previously mentioned increase in total margin ($8.2 million) and lower operating and administrative costs ($2.4 million).
Electric Utility. Electric Utility’s kilowatt-hour sales in the 2010 three-month period were 3.3% higher than in the prior year three-month period on heating degree day weather that was 5.4% colder. Notwithstanding the effects on heating-related sales from the colder weather, Electric Utility revenues decreased $5.1 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service and, to a much lesser extent, lower average default service (“DS”) rates compared to provider of last resort (“POLR”) rates in effect in the prior year. Under DS rates, Electric Utility is no longer subject to electricity price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under POLR rates. Electric Utility cost of sales declined to $18.6 million in the 2010 three-month period compared to $21.5 million in the 2009 three-month period principally reflecting the effects of the previously mentioned electricity generation supplier customer switching.
Electric Utility total margin declined $1.9 million in the 2010 three-month period principally reflecting the absence of margin from electric generation service beginning January 1, 2010.
Electric Utility 2010 three-month period operating income and income before income taxes were $1.8 million and $1.9 million lower, respectively, principally reflecting the previously mentioned lower total margin.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
FINANCIAL CONDITION AND LIQUIDITY
Financial Condition
The Company’s total debt outstanding at December 31, 2010 was $714 million compared to total debt outstanding of $657 million at September 30, 2010. Included in these amounts are $74 million and $17 million, respectively, of bank loans outstanding under UGI Utilities’ Revolving Credit Agreement (as further described below).
UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement which expires in August 2011. UGI Utilities expects to renew this facility before its expiration. At December 31, 2010, UGI Utilities had $74 million of borrowings outstanding under its Revolving Credit Agreement. Borrowings under the Revolving Credit Agreement are classified as bank loans on the Condensed Consolidated Balance Sheets. During the three months ended December 31, 2010 and 2009, average daily bank loan borrowings were $49.3 million and $161.2 million, respectively, and peak bank loan borrowings totaled $90 million and $203 million, respectively. Peak bank loan borrowings typically occur during the peak heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is greatest.
Based upon cash expected to be generated from Gas Utility and Electric Utility operations and borrowings available under the Revolving Credit Agreement, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2011.
Cash Flows
Operating activities. Due to the seasonal nature of UGI Utilities’ businesses, cash flows from our operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas and electricity consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally accounts receivable and inventories, is generally greatest. UGI Utilities uses borrowings under its Revolving Credit Agreement to manage seasonal cash flow needs.
Cash flow used by operating activities was $8.2 million in the 2010 three-month period compared to cash provided by operating activities of $6.7 million in the prior-year three-month period. Cash flow from operating activities before changes in operating working capital decreased to $57.8 million in the 2010 three-month period from $67.2 million in the prior-year three-month period. The decrease principally reflects changes in noncash charges for deferred income taxes. Changes in operating working capital used $66.0 million of operating cash flow during the 2010 three-month period, comparable to the $60.5 million used during the prior-year three-month period.
Investing activities. Cash used by investing activities was $17.4 million in the 2010 three-month period compared to $15.1 million in the 2009 three-month period. The greater cash used in the 2010 three-month period principally reflects higher Gas Utility capital expenditures.
Financing activities. Cash provided by financing activities was $33.0 million in the 2010 three-month period compared with cash provided by financing activities of $7.6 million in the 2009 three-month period. Financing activity cash flows are primarily the result of net borrowings and repayments under our Revolving Credit Agreement, cash dividends paid to UGI and capital contributions from UGI. We paid cash dividends to UGI totaling $24.3 million and $17.4 million during the 2010 and 2009 three-month periods, respectively. During the 2010 three-month period, net bank loan borrowings totaled $57 million compared with net bank loan borrowings of $25 million in the prior-year three-month period.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Merger of Pension Plans
Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. 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 related to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010. The remeasurement resulted in a decrease in pension and postretirement benefit obligations and associated regulatory assets, and an increase in other comprehensive income (see Notes 2, 5 and 6). The remeasurement will result in an approximate $1.4 million decrease in pension expense during the remainder of Fiscal 2011.
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 million 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.
ITEM 3.  
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of natural gas derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At December 31, 2010 and 2009, Gas Utility had $3.9 million and $0.7 million, respectively, of restricted cash associated with natural gas futures accounts with brokers. At December 31, 2010, the fair values of our natural gas futures and option contracts were gains of $2.2 million.
Beginning January 1, 2010, Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs through the application of DS rates. Because of this ratemaking mechanism, beginning January 1, 2010 there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations. FTRs are 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 electricity transmission grid. Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, through purchases at monthly PJM auctions. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. At December 31, 2010, the fair values of FTRs were gains of $0.4 million.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at December 31, 2010 and 2009 were not material.
In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). The fair value of unsettled IRPAs held at December 31, 2010 was a gain of $7.2 million. A hypothetical 10% adverse change in the three-month LIBOR and the three- and nine-month Euribor would result in a decrease in fair value of $3.8 million. There were no unsettled interest rate protection agreements outstanding as of December 31, 2009.
Our unsettled derivative instruments at December 31, 2010 comprise (1) Gas Utility’s exchange-traded natural gas futures and options contracts, which are included in Gas Utility’s PGC recovery mechanism; (2) Electric Utility’s FTRs and electricity forward purchase contracts, which are included in Electric Utility’s DS recovery mechanism; (3) exchange-traded gasoline futures and swap contracts; and (4) IRPAs.
ITEM 4.  
CONTROLS AND PROCEDURES
(a)  
Evaluation of Disclosure Controls and Procedures
   
The Company’s disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were effective at the reasonable assurance level.
(b)  
Change in Internal Control over Financial Reporting
   
No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
PART II OTHER INFORMATION
ITEM 1.  
LEGAL PROCEEDINGS
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 million. On February 14, 2007, Frontier and the City entered into a settlement agreement pursuant to which Frontier agreed to pay $7.6 million. 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.
ITEM 1A.  
RISK FACTORS
In addition to the other information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
ITEM 6.  
EXHIBITS
The exhibits filed as part of this report are as follows:
         
Exhibit No.   Exhibit
  12.1    
Computation of ratio of earnings to fixed charges
       
 
  31.1    
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
       
 
  31.2    
Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
       
 
  32    
Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2010, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  UGI Utilities, Inc.
(Registrant)
 
 
Date: February 4, 2011  By:   /s/ Donald E. Brown    
    Donald E. Brown   
    Vice President - Finance and
Chief Financial Officer 
 
     
Date: February 4, 2011  By:   /s/ Matthew J. Nolan    
    Matthew J. Nolan   
    Controller   

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
EXHIBIT INDEX
         
  12.1    
Computation of ratio of earnings to fixed charges
       
 
  31.1    
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
       
 
  31.2    
Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
       
 
  32    
Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2010, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002