##### 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 June 30, 2009
 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.
  Pennsylvania
    
    23-1174060(State or other jurisdiction of
    
    (I.R.S. Employerincorporation or organization)
    
    Identification No.)
         þ o
 o o
 Rule 12b-2
 Large accelerated filer o
    
    Accelerated filer o
    
    Non-accelerated filer þ
    
    Smaller reporting company o
 Yes o No þ




---



##### 



UGI UTILITIES, INC. AND SUBSIDIARIES
 TABLE OF CONTENTS
 PAGESPart I Financial InformationItem 1. Financial Statements (unaudited)Condensed Consolidated Balance Sheets as of June 30, 2009,
September 30, 2008 and June 30, 2008
    
    
    1Condensed Consolidated Statements of Income for the three and
nine months ended June 30, 2009 and 2008
    
    
    2Condensed Consolidated Statements of Cash Flows for the
nine months ended June 30, 2009 and 2008
    
    
    3Notes to Condensed Consolidated Financial Statements
    
    
    4 - 25Item 2. Managements Discussion and Analysis of Financial
Condition and Results of Operations
    
    
    26 - 35Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    
    35 - 36Item 4T. Controls and Procedures
    
    
    37Part II Other InformationItem 1. Legal Proceedings
    
    
    38Item 1A. Risk Factors
    
    
    38Item 6. Exhibits
    
    
    39Signatures
    
    
    40Exhibit 12.1Exhibit 31.1Exhibit 31.2Exhibit 32
   -i-




---



##### Table of Contents



June 30,
    
    
    September 30,
    
    
    June 30,2009
    
    
    2008
    
    
    2008ASSETSCurrent assets:Cash and cash equivalents
    
    $
    6,758
    
    
    $
    3,483
    
    
    $
    8,401Restricted cash
    
    
    46,485
    
    
    
    34,037
    
    
    
    Accounts receivable (less allowances for doubtful accounts of $22,818,
$10,369 and $14,751, respectively)
    
    
    112,992
    
    
    
    70,259
    
    
    
    114,500Accounts receivable  related parties
    
    
    1,698
    
    
    
    1,946
    
    
    
    7,589Accrued utility revenues
    
    
    21,176
    
    
    
    20,823
    
    
    
    22,253Regulatory assets
    
    
    28,788
    
    
    
    15,987
    
    
    
    Inventories
    
    
    106,250
    
    
    
    161,272
    
    
    
    91,723Deferred income taxes
    
    
    36,330
    
    
    
    13,712
    
    
    
    21,654Derivative financial instruments
    
    
    1,006
    
    
    
    506
    
    
    
    51,298Prepaid expenses & other current assets
    
    
    5,244
    
    
    
    3,380
    
    
    
    3,128Total current assets
    
    
    366,727
    
    
    
    325,405
    
    
    
    320,546Property, plant and equipment, at cost (less accumulated depreciation and
amortization of $691,592, $562,135 and
$557,859, respectively)
    
    
    1,352,309
    
    
    
    1,106,921
    
    
    
    1,091,991Goodwill
    
    
    176,906
    
    
    
    161,726
    
    
    
    162,309Regulatory assets
    
    
    112,706
    
    
    
    91,396
    
    
    
    91,831Other assets
    
    
    10,008
    
    
    
    9,018
    
    
    
    8,719Total assets
    
    $
    2,018,656
    
    
    $
    1,694,466
    
    
    $
    1,675,396LIABILITIES AND STOCKHOLDERS EQUITYCurrent liabilities:Bank loans
    
    $
    110,000
    
    
    $
    57,000
    
    
    $
    30,000Accounts payable
    
    
    42,779
    
    
    
    57,384
    
    
    
    69,706Accounts payable  related parties
    
    
    8,927
    
    
    
    14,680
    
    
    
    23,253Accrued income taxes
    
    
    47,755
    
    
    
    3,170
    
    
    
    29,014Deferred fuel refunds
    
    
    13,512
    
    
    
    
    
    
    
    87,926Derivative financial instruments
    
    
    42,473
    
    
    
    23,488
    
    
    
    Other current liabilities
    
    
    92,848
    
    
    
    68,441
    
    
    
    63,572Total current liabilities
    
    
    358,294
    
    
    
    224,163
    
    
    
    303,471Long-term debt
    
    
    640,000
    
    
    
    532,000
    
    
    
    532,000Deferred income taxes
    
    
    152,920
    
    
    
    171,623
    
    
    
    191,646Deferred investment tax credits
    
    
    5,762
    
    
    
    6,039
    
    
    
    6,133Other noncurrent liabilities
    
    
    199,395
    
    
    
    93,071
    
    
    
    43,798Total liabilities
    
    
    1,356,371
    
    
    
    1,026,896
    
    
    
    1,077,048Commitments and contingencies (note 6)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
    
    
    
    60,259Additional paid-in capital
    
    
    466,990
    
    
    
    466,888
    
    
    
    346,758Retained earnings
    
    
    216,991
    
    
    
    184,201
    
    
    
    206,542Accumulated other comprehensive loss
    
    
    (81,955
    )
    
    
    (43,778
    )
    
    
    (15,211
    )Total common stockholders equity
    
    
    662,285
    
    
    
    667,570
    
    
    
    598,348Total liabilities and stockholders equity
    
    $
    2,018,656
    
    
    $
    1,694,466
    
    
    $
    1,675,396
   -1-




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedJune 30,
    
    
    June 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Revenues
    
    $
    208,300
    
    
    $
    235,544
    
    
    $
    1,236,252
    
    
    $
    1,119,930Costs and expenses:Cost of sales  gas, fuel and purchased power
    
    
    129,533
    
    
    
    165,082
    
    
    
    862,743
    
    
    
    803,914Operating and administrative expenses
    
    
    43,633
    
    
    
    34,785
    
    
    
    151,556
    
    
    
    110,920Operating and administrative expenses  related
parties
    
    
    2,976
    
    
    
    2,524
    
    
    
    12,114
    
    
    
    9,332Taxes other than income taxes
    
    
    4,244
    
    
    
    4,397
    
    
    
    13,870
    
    
    
    13,650Depreciation and amortization
    
    
    12,775
    
    
    
    10,246
    
    
    
    37,849
    
    
    
    30,826Other income, net
    
    
    (1,304
    )
    
    
    (1,548
    )
    
    
    (6,008
    )
    
    
    (9,048
    )191,857
    
    
    
    215,486
    
    
    
    1,072,124
    
    
    
    959,594Operating income
    
    
    16,443
    
    
    
    20,058
    
    
    
    164,128
    
    
    
    160,336Interest expense
    
    
    10,821
    
    
    
    8,879
    
    
    
    33,010
    
    
    
    29,880Income before income taxes
    
    
    5,622
    
    
    
    11,179
    
    
    
    131,118
    
    
    
    130,456Income taxes
    
    
    2,509
    
    
    
    4,931
    
    
    
    52,125
    
    
    
    52,489Net income
    
    $
    3,113
    
    
    $
    6,248
    
    
    $
    78,993
    
    
    $
    77,967
   -2-




---



##### Table of Contents



Nine Months EndedJune 30,2009
    
    
    2008CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    78,993
    
    
    $
    77,967Adjustments to reconcile net income to net cash from operating
activities:Depreciation and amortization
    
    
    37,849
    
    
    
    30,826Deferred income taxes, net
    
    
    (9,805
    )
    
    
    (931
    )Provision for uncollectible accounts
    
    
    20,747
    
    
    
    13,831Other, net
    
    
    11,408
    
    
    
    (390
    )Net change in:Accounts receivable and accrued utility revenues
    
    
    (46,404
    )
    
    
    (66,229
    )Inventories
    
    
    77,606
    
    
    
    70,039Deferred fuel costs, net of changes in unsettled derivatives
    
    
    40,214
    
    
    
    53,359Accounts payable
    
    
    (29,742
    )
    
    
    17,585Storage agreements security deposits
    
    
    19,000
    
    
    
    Other current assets
    
    
    (1,281
    )
    
    
    608Other current liabilities
    
    
    26,685
    
    
    
    15,141Net cash provided by operating activities
    
    
    225,270
    
    
    
    211,806CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for property, plant and equipment
    
    
    (56,068
    )
    
    
    (40,951
    )Acquisition of CPG, net of cash acquired
    
    
    (298,671
    )
    
    
    Proceeds from sale of CPP
    
    
    32,269
    
    
    
    (Increase) decrease in restricted cash
    
    
    (12,448
    )
    
    
    6,642Other, net
    
    
    (1,866
    )
    
    
    1,739Net cash used by investing activities
    
    
    (336,784
    )
    
    
    (32,570
    )CASH FLOWS FROM FINANCING ACTIVITIES:Payment of dividends
    
    
    (46,211
    )
    
    
    (50,362
    )Issuance of long-term debt
    
    
    108,000
    
    
    
    20,000Increase (decrease) in bank loans
    
    
    53,000
    
    
    
    (160,000
    )Cash portion of UGI HVAC dividend
    
    
    
    
    
    
    (1,381
    )Other
    
    
    
    
    
    
    4,701Net cash provided (used) by financing activities
    
    
    114,789
    
    
    
    (187,042
    )Cash and cash equivalents increase (decrease)
    
    $
    3,275
    
    
    $
    (7,806
    )CASH AND CASH EQUIVALENTS:End of period
    
    $
    6,758
    
    
    $
    8,401Beginning of period
    
    
    3,483
    
    
    
    16,207Increase (decrease)
    
    $
    3,275
    
    
    $
    (7,806
    )
   -3-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 
 Notes to Condensed Consolidated Financial Statements
   1.
    
    Basis of Presentation
 UGI Utilities, Inc., a wholly owned subsidiary of UGI Corporation (UGI), and its wholly
owned subsidiaries UGI Penn Natural Gas, Inc. (UGIPNG) 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, Inc.s natural gas
distribution utility is referred to herein as UGI Gas; UGIPNGs natural gas distribution
utility is referred to herein as PNG Gas; and CPGs natural gas distribution utility,
which was acquired on October 1, 2008 (see Note 2), is referred to herein as CPG Gas. UGI
Gas, PNG Gas and CPG Gas are collectively referred to as Gas Utility. UGIPNG also has a
heating, ventilation and air-conditioning service business (UGI Penn HVAC Services, Inc.)
which operates principally in the PNG Gas service territory.
 Effective January 1, 2007, as previously approved by the Pennsylvania Public Utility
Commission (PUC), UGI Utilities, Inc. contributed its heating, ventilation and air
conditioning services business to its wholly owned second-tier subsidiary, UGI HVAC
Services, Inc. (UGI HVAC). Effective April 1, 2008, UGI Utilities transferred by dividend
its ownership interest in UGI HVAC to UGI. UGI Penn HVAC Services, Inc and UGI HVAC (prior
to its transfer by dividend to UGI) are referred to herein as the HVAC Business.
 Gas Utility is subject to regulation by the PUC and the Maryland Public Service Commission
and Electric Utility is subject to regulation by the PUC. The term UGI Utilities is used
sometimes as an abbreviated reference to UGI Utilities, Inc., or to UGI Utilities, Inc. and
its subsidiaries. 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, 2008 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, 2008 (Companys 2008 Annual Report). Due to the seasonal nature of
our businesses, the results of operations for interim periods are not necessarily indicative
of the results to be expected for a full year.
 Restricted Cash. Restricted cash represents those cash balances in our commodity futures
brokerage accounts which are restricted from withdrawal.
  -4-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Comprehensive Income.The following table presents the components of comprehensive income
for the three and nine months ended June 30, 2009 and 2008:
 Three Months Ended
    
    
    Nine Months EndedJune 30,
    
    
    June 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Net income
    
    $
    3,113
    
    
    $
    6,248
    
    
    $
    78,993
    
    
    $
    77,967Other comprehensive income (loss)
    
    
    170
    
    
    
    193
    
    
    
    (38,177
    )
    
    
    106Comprehensive income
    
    $
    3,283
    
    
    $
    6,441
    
    
    $
    40,816
    
    
    $
    78,073
 Other comprehensive income (loss) for all periods presented includes reclassifications
to net income of settled net losses on interest rate protection agreements and, in the nine
months ended June 30, 2008, includes net changes in the fair value of an electricity price
swap agreement through its expiration on December 31, 2007. In addition, effective December
31, 2008, UGI Utilities merged two of the defined benefit pension plans that it sponsors. In
accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No.
87, Employers Accounting for Pensions (SFAS 87), we were required to remeasure the
merged plans assets and obligations and, in accordance with SFAS No. 158, Employers
Accounting for Defined Benefit Pension and Other Postretirement Plans  an Amendment of FASB
Statements No. 87, 88, 106 and 132(R) (SFAS 158), record the funded status at December 31,
2008 in our Condensed Consolidated Balance Sheet. The remeasurement resulted in an increase
in other comprehensive loss of $38,688 for the nine months ended June 30, 2009 (see Note 5).
 Natural Gas Inventories.UGI Utilities has two storage contract administrative agreements
pursuant to which it has, among other things, released certain storage and transportation
contracts for the terms of the storage agreements. UGI Utilities also transferred certain
associated storage inventories upon commencement of the storage agreements, will receive a
transfer of storage inventories at the end of the storage agreements, and makes payments
associated with refilling storage inventories during the terms of such agreements. These
agreements are currently scheduled to expire on October 31, 2009. Included among these
storage agreements is an agreement with UGI Energy Services, Inc., a second-tier wholly owned
subsidiary of UGI (see Note 7).
 UGI Utilities reflects the historical cost of natural gas storage inventories released under
these agreements, which represent 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 agreements but not yet replenished) on its balance sheets
under the caption Inventories. The carrying value of gas storage inventories released under
these agreements at June 30, 2009, September 30, 2008 and June 30, 2008, comprising
5.0 billion cubic feet (bcf), 9.3 bcf, and 6.0 bcf of natural gas, was $43,683, $81,182 and
$48,837, respectively. In conjunction with the storage agreements, at June 30, 2009 UGI
Utilities had a total of $19,000 of security deposits received from its storage agreement
counterparties which amount is reflected in other current liabilities on the Condensed
Consolidated Balance Sheet.
  -5-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Reclassifications.We have reclassified certain prior-year period balances to conform to the
current-period presentation.
 Use of Estimates.We make estimates and assumptions when preparing financial statements in
conformity with GAAP. These estimates and assumptions affect the reported amounts of assets
and liabilities, revenues and expenses, as well as the disclosure of contingent assets and
liabilities. Actual results could differ from these estimates.
 Income Taxes.As a result of settlements with tax authorities, in December 2008 the Company
adjusted its unrecognized tax benefits. The reduction decreased income tax expense for the
nine months ended June 30, 2009 by $490.
 Subsequent Events.The Companys management has evaluated the impact of subsequent events
through August 7, 2009, the date the financial statements were filed with the SEC, and the
effects of such evaluation have been reflected in the financial statements and related
disclosures.
 Newly Adopted Accounting Standards.Effective with the quarter ended June 30, 2009, we
adopted Financial Accounting Standards Boards (FASB) Staff Position (FSP) FAS 107-1 and
APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (FSP 107-1 and APB
28-1). FSP 107-1 and APB 28-1 expands the fair value disclosures required for all financial
instruments by SFAS 107, Disclosures about Fair Value of Financial Instruments, to interim
periods for public companies. It also requires disclosures regarding significant fair value
assumptions used. See Note 10 for further information on interim period fair value
disclosures in accordance with FSP 107-1 and APB 28-1.
 Effective with the quarter ended June 30, 2009, we adopted SFAS No. 165, Subsequent Events
(SFAS 165). SFAS 165 provides guidance on managements accounting for and disclosure of
events that occur after the balance sheet date but before the financial statements are issued
including the date through which subsequent events are evaluated. The adoption of SFAS 165
did not have a significant impact on the Companys financial statements.
 Also effective with the quarter ended June 30, 2009, we adopted FSP FAS 115-2 and 124-2,
Recognition and Presentation of Other-Than-Temporary Impairments (FSP 115-2 and 124-2).
FSP 115-2 and 124-2 amends other-than-temporary impairment guidance in GAAP for debt
securities to make the guidance more operational and to improve the presentation and
disclosure of other-than-temporary impairments on debt and equity securities in the financial
statements. The FSP does not amend existing recognition and measurement guidance related to
other-than-temporary impairments of equity securities. The adoption of FSP 115-2 and 124-2
did not impact the Companys financial statements.
 Effective March 31, 2009, we adopted the provisions of SFAS No. 161, Disclosures about
Derivative Instruments and Hedging Activities (SFAS 161). SFAS 161 requires enhanced
disclosures for all derivative instruments and hedging activity accounted for under SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133). SFAS
161 provides greater transparency by requiring disclosure regarding: (1) how and why an
entity uses derivatives, (2) how derivatives and related hedged items are accounted for under
SFAS 133 and its related interpretations, and (3) how derivatives and related hedged items
affect an entitys financial position, financial performance and cash flows. See Note 10 for
disclosures required by SFAS 161.
  -6-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Effective October 1, 2008, we adopted SFAS No. 157, Fair Value Measurements (SFAS 157).
SFAS 157 defines fair value, establishes a framework for measuring fair value under GAAP and
expands disclosures about fair value measurements. In February 2008, the FASB issued two FSPs
amending SFAS 157. FSP FAS 157-1 amends SFAS 157 to exclude SFAS No. 13, Accounting for
Leases, and its related interpretive accounting pronouncements that address leasing
transactions. FSP FAS 157-2 delays the effective date of SFAS 157 until fiscal years
beginning after November 15, 2008 (Fiscal 2010) for non-financial assets and liabilities that
are recognized or disclosed at fair value in the financial statements on a non-recurring
basis. The adoption of the initial phase of SFAS 157 did not have a material effect on the
Companys financial statements and the Company does not anticipate that the adoption of the
remainder of SFAS 157 will have a material effect on the Companys consolidated financial
statements. In October 2008, the FASB issued FSP FAS 157-3, Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not Active (FSP 157-3), which clarifies
the application of SFAS 157 to financial assets in a market that is not active. In
April 2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the Volume and Level
of Activity for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly (FSP 157-4), which provides additional guidance for
estimating fair value in accordance with SFAS 157 when the volume and level of activity for
the asset or liability have significantly decreased. FSP 157-3 and FSP 157-4 did not have an
impact on our results of operations or financial condition. See Note 9 for further
information on fair value measurements in accordance with SFAS 157.
 Effective October 1, 2008, we adopted FSP FIN 39-1, Amendment of FASB Interpretation No. 39
(FSP 39-1). FSP 39-1 permits companies to offset fair value amounts recognized for the
right to reclaim cash collateral (a receivable) or the obligation to return cash collateral
(a payable) against fair value amounts recognized for derivative instruments executed with
the same counterparty under a master netting agreement. In addition, upon the adoption,
companies are permitted to change their accounting policy to offset or not offset fair value
amounts recognized for derivative instruments under master netting arrangements. FSP 39-1
requires retrospective application for all periods presented. We have elected to continue our
policy of reflecting derivative asset or liability positions, as well as cash collateral, on
a gross basis in our Condensed Consolidated Balance Sheets. Accordingly, the adoption of FSP
39-1 did not impact our financial statements.
 Also effective October 1, 2008, we adopted SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities (SFAS 159). Under SFAS 159, we may elect to report
individual financial instruments and certain items at fair value with changes in fair value
reported in earnings. Once made, this election is irrevocable for those items. The adoption
of SFAS 159 did not impact our financial statements.
  -7-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Recently Issued Accounting Standards Not Yet Adopted.In June 2009, the FASB issued SFAS No.
168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles (SFAS 168). SFAS 168 identifies the sources of accounting principles
and the framework for selecting accounting principles used in the preparation of financial
statements presented in conformity with GAAP. SFAS 168 establishes the FASB Accounting
Standards Codification as the source of authoritative accounting principles recognized by the
FASB. The issuance of SFAS 168 will not change existing GAAP. SFAS 168 is effective for all
financial statements issued after September 15, 2009.
 In December 2008, the FASB issued FSP 132(R)-1, Employers Disclosures about Postretirement
Benefit Plan Assets, which amends Statement 132(R) to require more detailed disclosures
about employers plan assets, including employers investment strategies, major categories of
plan assets, concentrations of risk within plan assets, and valuation techniques used to
measure the fair value of plan assets. The provisions of this FSP are effective for reporting
periods ending after December 15, 2009. We are currently evaluating the provisions of
FSP 132(R)-1.
 In April 2008, the FASB issued FSP FAS 142-3, Determination of the Useful Life of Intangible
Assets (FSP 142-3). FSP 142-3 amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful life of a recognized intangible
asset under SFAS No. 142, Goodwill and Other Intangible Assets (SFAS 142). The intent of
FSP 142-3 is to improve the consistency between the useful life of a recognized intangible
asset under SFAS 142 and the period of expected cash flows used to measure the fair value of
the asset under SFAS No. 141 (revised 2007), Business Combinations (SFAS 141R), and other
applicable accounting literature. FSP 142-3 is effective for financial statements issued for
fiscal years beginning after December 15, 2008 (Fiscal 2010) and must be applied
prospectively to intangible assets acquired after the effective date. We are currently
evaluating the provisions of FSP 142-3.
 In December 2007, the FASB issued SFAS 141R, Business Combinations. SFAS 141R applies to
all transactions or other events in which an entity obtains control of one or more
businesses. SFAS 141R establishes, among other things, principles and requirements for how
the acquirer (1) recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2)
recognizes and measures the goodwill acquired in a business combination or gain from a
bargain purchase; and (3) determines what information with respect to a business combination
should be disclosed. SFAS 141R applies prospectively to business combinations for which the
acquisition date is on or after the first annual reporting period beginning on or after
December 15, 2008 (Fiscal 2010). Among the more significant changes in accounting for
acquisitions are (1) transaction costs will generally be expensed (rather than being included
as costs of the acquisition); (2) contingencies, including contingent consideration, will
generally be recorded at fair value with subsequent adjustments recognized in operations
(rather than as adjustments to the purchase price); and (3) decreases in valuation allowances
on acquired deferred tax assets will be recognized in operations (rather than decreases in
goodwill). Generally, the effects of SFAS 141R will depend on future acquisitions.
  -8-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   2.
    
    Acquisition of PPL Gas Utilities Corporation
 On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL
Gas Utilities Corporation (now CPG), the natural gas distribution utility of PPL
Corporation (the CPG Acquisition), and its subsidiaries for cash consideration of $267,600
plus estimated working capital of $35,370. Immediately after the closing of the CPG
Acquisition, CPGs wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central
Penn Propane, LLC, CPP), its retail propane distributor, sold its assets to AmeriGas
Propane, L.P. (AmeriGas OLP), an affiliate of UGI, for cash consideration of $32,000 plus
estimated working capital of $1,621. CPG distributes natural gas to approximately 76,000
customers in eastern and central Pennsylvania and also distributes natural gas to several
hundred customers in portions of one Maryland county. CPP sold propane to customers
principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition at closing
with a combination of $120,000 cash contributed by UGI on September 25, 2008, proceeds from
the issuance on October 1, 2008 of $108,000 principal amount of 6.375% Senior Notes due 2013
and approximately $75,000 of borrowings under UGI Utilities Revolving Credit Agreement. The
cash proceeds of $33,621 from the sale of the assets of CPP to AmeriGas OLP were used to
reduce borrowings under UGI Utilities Revolving Credit Agreement.
 The assets and liabilities resulting from the CPG Acquisition are included in our Condensed
Consolidated Balance Sheet at June 30, 2009. The purchase price allocation has been
finalized except for the fair values of regulatory assets and liabilities which are subject
to a pending base rate proceeding of CPG (see Note 4). Pursuant to the CPG Acquisition
purchase agreement, the purchase price was subject to adjustment for the difference between
the estimated working capital of $35,370 and the actual working capital as of the closing
date agreed to by both UGI Utilities and PPL Corporation (PPL). In February 2009, UGI
Utilities and PPL reached an agreement on the working capital adjustment pursuant to which
PPL paid UGI Utilities $3,673 in cash including interest. UGI Utilities expects to receive
from PPL later in Fiscal 2009 an additional approximately $7,500 in cash associated with
certain income tax assets. Also during the three months ended March 31, 2009, UGI Utilities
and AmeriGas OLP reached an agreement on the working capital adjustment associated with UGI
Utilities sale of the assets of CPP to AmeriGas OLP pursuant to which UGI Utilities paid
AmeriGas OLP $1,352 plus interest.
 The purchase price of the CPG Acquisition, including transaction fees and expenses and
liabilities incurred totaling approximately $2,300 has been allocated to the assets acquired
and liabilities assumed (but excluding the assets of CPP sold to AmeriGas OLP) as follows:
 Working capital
    
    $
    21,589Property, plant and equipment, net
    
    
    227,301Goodwill
    
    
    15,180Regulatory assets
    
    
    22,466Other assets
    
    
    7,412Noncurrent liabilities
    
    
    (32,057
    )Total
    
    $
    261,891
  -9-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Substantially all of the goodwill is deductible for income tax purposes over a
fifteen-year period.
 The operating results of CPG are included in our consolidated results beginning October 1,
2008. The following table presents pro forma income statement data for the three and nine
months ended June 30, 2008 as if the CPG Acquisition had occurred as of October 1, 2007:
 Three Months Ended
    
    
    Nine Months EndedJune 30, 2008
    
    
    June 30, 2008(pro forma)
    
    
    (pro forma)Revenues
    
    $
    272,644
    
    
    $
    1,284,485Net income
    
    
    7,106
    
    
    
    89,408
 The pro forma results of operations reflect CPGs historical operating results after
giving effect to adjustments directly attributable to the transaction that are expected to
have a continuing effect. The pro forma amounts are not necessarily indicative of operating
results that would have occurred had the CPG Acquisition been completed as of the date
indicated, nor are they necessarily indicative of future operating results.
 3.
    
    Segment Information
 We have two reportable segments: (1) Gas Utility and (2) Electric Utility. The accounting
policies of our two reportable segments are the same as those described in the Significant
Accounting Policies note contained in the Companys 2008 Annual Report. We evaluate each
segments profitability principally based upon its income before income taxes. No single
customer represents more than 10% of the total revenues of either Gas Utility or Electric
Utility. There are no significant intersegment transactions. In addition, all of our
reportable segments revenues are derived from sources within the United States.
 The HVAC Business does not meet the quantitative thresholds for separate segment reporting
under the provisions of SFAS No. 131, Disclosures about Segments of an Enterprise and
Related Information and has been reflected as Other.
  -10-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Financial information by business segment follows:
 Three Months Ended June 30, 2009:
 Reportable SegmentsGas
    
    
    ElectricTotal
    
    
    Utility
    
    
    Utility
    
    
    OtherRevenues
    
    $
    208,300
    
    
    $
    176,937
    
    
    $
    30,741
    
    
    $
    622Cost of sales
    
    
    129,533
    
    
    
    109,828
    
    
    
    19,705
    
    
    
    Depreciation and amortization
    
    
    12,775
    
    
    
    11,757
    
    
    
    1,018
    
    
    
    Operating income
    
    
    16,443
    
    
    
    12,948
    
    
    
    3,373
    
    
    
    122Interest expense
    
    
    10,821
    
    
    
    10,379
    
    
    
    442
    
    
    
    Income before income taxes
    
    
    5,622
    
    
    
    2,569
    
    
    
    2,931
    
    
    
    122Total assets at period end
    
    $
    2,018,656
    
    
    $
    1,900,874
    
    
    $
    116,155
    
    
    $
    1,627Goodwill at period end
    
    $
    176,906
    
    
    $
    176,906
    
    
    $
    
    
    
    $
    
 Three Months Ended June 30, 2008:
 Reportable SegmentsGas
    
    
    ElectricTotal
    
    
    Utility
    
    
    Utility
    
    
    OtherRevenues
    
    $
    235,544
    
    
    $
    202,145
    
    
    $
    32,761
    
    
    $
    638Cost of sales
    
    
    165,082
    
    
    
    147,358
    
    
    
    17,724
    
    
    
    Depreciation and amortization
    
    
    10,246
    
    
    
    9,326
    
    
    
    920
    
    
    
    Operating income
    
    
    20,058
    
    
    
    12,412
    
    
    
    7,535
    
    
    
    111Interest expense
    
    
    8,879
    
    
    
    8,404
    
    
    
    475
    
    
    
    Income before income taxes
    
    
    11,179
    
    
    
    4,008
    
    
    
    7,060
    
    
    
    111Total assets at period end
    
    $
    1,675,396
    
    
    $
    1,558,530
    
    
    $
    115,879
    
    
    $
    987Goodwill at period end
    
    $
    162,309
    
    
    $
    162,309
    
    
    $
    
    
    
    $
    
  -11-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Nine Months Ended June 30, 2009:
 Reportable SegmentsGas
    
    
    ElectricTotal
    
    
    Utility
    
    
    Utility
    
    
    OtherRevenues
    
    $
    1,236,252
    
    
    $
    1,130,099
    
    
    $
    104,780
    
    
    $
    1,373Cost of sales
    
    
    862,743
    
    
    
    795,675
    
    
    
    67,068
    
    
    
    Depreciation and amortization
    
    
    37,849
    
    
    
    34,893
    
    
    
    2,956
    
    
    
    Operating income
    
    
    164,128
    
    
    
    149,848
    
    
    
    13,837
    
    
    
    443Interest expense
    
    
    33,010
    
    
    
    31,731
    
    
    
    1,279
    
    
    
    Income before income taxes
    
    
    131,118
    
    
    
    118,117
    
    
    
    12,558
    
    
    
    443Total assets at period end
    
    $
    2,018,656
    
    
    $
    1,900,874
    
    
    $
    116,155
    
    
    $
    1,627Goodwill at period end
    
    $
    176,906
    
    
    $
    176,906
    
    
    $
    
    
    
    $
    
 Nine Months Ended June 30, 2008:
 Reportable SegmentsGas
    
    
    ElectricTotal
    
    
    Utility
    
    
    Utility
    
    
    OtherRevenues
    
    $
    1,119,930
    
    
    $
    1,005,590
    
    
    $
    103,294
    
    
    $
    11,046Cost of sales
    
    
    803,914
    
    
    
    739,259
    
    
    
    59,621
    
    
    
    5,034Depreciation and amortization
    
    
    30,826
    
    
    
    28,128
    
    
    
    2,689
    
    
    
    9Operating income
    
    
    160,336
    
    
    
    138,063
    
    
    
    21,407
    
    
    
    866Interest expense
    
    
    29,880
    
    
    
    28,339
    
    
    
    1,541
    
    
    
    Income before income taxes
    
    
    130,456
    
    
    
    109,724
    
    
    
    19,866
    
    
    
    866Total assets at period end
    
    $
    1,675,396
    
    
    $
    1,558,530
    
    
    $
    115,879
    
    
    $
    987Goodwill at period end
    
    $
    162,309
    
    
    $
    162,309
    
    
    $
    
    
    
    $
    
  -12-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   4.
    
    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 3 to the Companys 2008 Annual Report. UGI Utilities does not
recover a rate of return on its regulatory assets. The following regulatory assets and
liabilities associated with Gas Utility and Electric Utility are included in our accompanying
Condensed Consolidated Balance Sheets:
 June 30,
    
    
    September 30,
    
    
    June 30,2009
    
    
    2008
    
    
    2008Regulatory assets:Income taxes recoverable
    
    $
    76,645
    
    
    $
    73,695
    
    
    $
    73,792Postretirement benefits
    
    
    3,017
    
    
    
    4,321
    
    
    
    4,497Recoverable costs  CPG Gas postretirement benefit plans
    
    
    5,545
    
    
    
    
    
    
    
    Environmental costs
    
    
    20,583
    
    
    
    9,009
    
    
    
    9,009Deferred fuel costs
    
    
    28,788
    
    
    
    15,987
    
    
    
    Other
    
    
    6,916
    
    
    
    4,371
    
    
    
    4,533Total regulatory assets
    
    $
    141,494
    
    
    $
    107,383
    
    
    $
    91,831Regulatory liabilities:Postretirement benefits
    
    $
    9,971
    
    
    $
    8,886
    
    
    $
    8,565Environmental overcollections
    
    
    9,724
    
    
    
    
    
    
    
    Deferred fuel refunds
    
    
    13,512
    
    
    
    
    
    
    
    87,926Total regulatory liabilities
    
    $
    33,207
    
    
    $
    8,886
    
    
    $
    96,491
 Deferred fuel costs and refunds.Gas Utilitys tariffs contain clauses which permit
recovery of certain purchased gas costs through the application of purchased gas cost (PGC)
rates. The clauses provide for periodic adjustments to PGC rates for differences between the
total amount of purchased gas costs collected from customers and recoverable costs incurred.
Net undercollected gas 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 refunds or costs.
Unrealized (losses) gains on such contracts at June 30, 2009, September 30, 2008 and June 30,
2008 were $(42,473), $(23,321) and $49,349, respectively.
 Recoverable costs  CPG Gas postretirement benefit plans.This regulatory asset represents
the portion of prior service cost and net actuarial losses that will be 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 SFAS 158. These costs are amortized over the average
remaining life expectancy of the plan participants.
 Environmental overcollections. Environmental overcollections represents the difference
between the amounts recovered in rates and actual costs incurred (net of insurance proceeds)
associated with the terms of a consent order agreement between CPG Gas and the Pennsylvania
Department of Environmental Protection to remediate certain gas plant sites.
  -13-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Other Regulatory Matters
 UGIPNG and CPG Base Rate Filings. On January 28, 2009, UGIPNG and CPG filed separate requests
with the PUC to increase base operating revenues by $38,118 annually for UGIPNG and $19,635
annually for CPG to fund system improvements and operations necessary to maintain safe and
reliable natural gas service and energy assistance for low income customers as well as energy
conservation programs for all customers. On March 26, 2009, the PUC suspended the effective
date for the base operating revenue rate increases to allow for investigation and public
hearings. On May 5, 2009, UGIPNG and CPG received testimony submitted by various state and
special interest parties opposing the level of the proposed rate increases. On July 2, 2009,
UGIPNG and CPG each filed joint settlement petitions with the PUC based on agreements with
the opposing parties regarding the requested base operating revenue increases. The settlement
agreements were approved by an
administrative law judge on July 29, 2009 in substantially the
form submitted. The recommended
decision of the administrative law judge is subject to PUC approval. It is
anticipated that this process will conclude by the end of Fiscal 2009.
 Electric Utility.As a result of Pennsylvanias Electricity Generation Customer Choice and
Competition Act that became effective January 1, 1997, all of Electric Utilitys customers
are permitted to acquire their electricity from entities other than Electric Utility.
Electric Utility remains the provider of last resort (POLR) for its customers that are not
served by an alternate electric generation provider. The terms and conditions under which
Electric Utility provides POLR service, and rules governing the rates that may be charged for
such service through December 31, 2009, were established in a series of PUC approved
settlements (collectively, the POLR Settlement), the latest of which became effective June
23, 2006.
 In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to
certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement,
Electric Utility increased its POLR rates effective January 1, 2008 which increased the
average cost to a residential heating customer by approximately 5.5% over such costs in
effect during calendar year 2007. Effective January 1, 2009, the average cost to a
residential heating customer increased by 1.5% over such costs in effect during calendar year
2008.
 On July 17, 2008, the PUC approved Electric Utilitys default service procurement,
implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement,
filed in accordance with the PUCs default service regulations. These plans do not affect
Electric Utilitys existing POLR Settlement effective through December 31, 2009. The approved
plans specify how Electric Utility will solicit and acquire default service supplies for
residential customers for the period January 1, 2010 through May 31, 2014, and for commercial
and industrial customers for the period January 1, 2010 through May 31, 2011 (collectively,
the Settlement Term). UGI Utilities filed a rate plan on August 29, 2008 for the Settlement
Term. On January 22, 2009, the PUC approved a settlement of the rate filing that provides for
Electric Utility to fully recover its default service costs. Under applicable statutory
standards, Electric Utility is entitled to fully recover its default service costs.
 5.
    
    Defined Benefit Pension and Other Postretirement Plans
 Subsequent to the plan merger as further described below, we sponsor two defined benefit
pension plans (Pension Plans) for employees of UGI Utilities, UGIPNG, CPG, UGI, and certain
of UGIs other wholly owned domestic subsidiaries. In addition, we provide postretirement
health care benefits to certain retirees and postretirement life insurance benefits to nearly
all active and retired employees.
  -14-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Net periodic pension expense and other postretirement benefit costs relating to our employees
include the following components:
 Pension Benefits
    
    
    Other Postretirement BenefitsThree Months Ended
    
    
    Three Months EndedJune 30,
    
    
    June 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Service cost
    
    $
    1,321
    
    
    $
    1,271
    
    
    $
    33
    
    
    $
    66Interest cost
    
    
    3,813
    
    
    
    4,453
    
    
    
    211
    
    
    
    212Expected return on assets
    
    
    (4,262
    )
    
    
    (5,693
    )
    
    
    (130
    )
    
    
    (159
    )Amortization of:Prior service cost
(benefit)
    
    
    6
    
    
    
    7
    
    
    
    (87
    )
    
    
    (96
    )Actuarial loss
    
    
    950
    
    
    
    
    
    
    
    30
    
    
    
    17Net benefit cost
    
    
    1,828
    
    
    
    38
    
    
    
    57
    
    
    
    40Change in associated
regulatory liabilities
    
    
    
    
    
    
    
    
    
    
    803
    
    
    
    818Net expense
    
    $
    1,828
    
    
    $
    38
    
    
    $
    860
    
    
    $
    858
 Pension Benefits
    
    
    Other Postretirement BenefitsNine Months Ended
    
    
    Nine Months EndedJune 30,
    
    
    June 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Service cost
    
    $
    3,741
    
    
    $
    3,812
    
    
    $
    99
    
    
    $
    200Interest cost
    
    
    11,532
    
    
    
    13,360
    
    
    
    633
    
    
    
    636Expected return on assets
    
    
    (12,994
    )
    
    
    (17,079
    )
    
    
    (391
    )
    
    
    (477
    )Amortization of:Prior service cost
(benefit)
    
    
    19
    
    
    
    22
    
    
    
    (260
    )
    
    
    (290
    )Actuarial loss
    
    
    2,089
    
    
    
    
    
    
    
    89
    
    
    
    51Net benefit cost
    
    
    4,387
    
    
    
    115
    
    
    
    170
    
    
    
    120Change in associated
regulatory liabilities
    
    
    
    
    
    
    
    
    
    
    2,410
    
    
    
    2,453Net expense
    
    $
    4,387
    
    
    $
    115
    
    
    $
    2,580
    
    
    $
    2,573
 Pension Plans assets are held in trust and consist principally of equity and fixed
income mutual funds. The Company does not believe it will be required to make any
contributions to the Pension Plans during the year ending September 30, 2009 (Fiscal 2009)
for ERISA funding purposes. Pursuant to orders previously issued by the PUC, UGI Utilities
has established a Voluntary Employees Beneficiary Association (VEBA) trust to fund and 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 SFAS No. 106, Employers Accounting for Postretirement Benefits Other
Than Pensions. The difference between the annual amount calculated and the amount 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
nine months ended June 30, 2009, nor are they expected to be material for all of Fiscal 2009.
  -15-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   We also sponsor an unfunded and non-qualified defined benefit supplemental executive
retirement income plan. Net benefit costs associated with this plan for all periods presented
were not material.
 Effective December 31, 2008, UGI Utilities merged two of its 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 SFAS 87, the Company
remeasured the combined plans assets and benefit obligations as of December 31, 2008 (the
Remeasurement Date) and in accordance with SFAS 158 recorded an after-tax charge to
accumulated other comprehensive loss of $38,688.
 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 the Remeasurement Date:
 Three MonthsEndedDecember 31, 2008Change in benefit obligations:Benefit obligations  October 1, 2008
    
    $
    300,578Service cost
    
    
    1,317Interest cost
    
    
    5,073Actuarial loss
    
    
    35,413Benefits paid
    
    
    (3,690
    )Benefit obligations  December 31, 2008
    
    $
    338,691Change in plan assets:Fair value of plan assets  October 1, 2008
    
    $
    240,997Actual loss on assets
    
    
    (27,350
    )Benefits paid
    
    
    (3,690
    )Fair value of plan assets  December 31, 2008
    
    $
    209,957Funded status of the merged plan  December 31, 2008
    
    $
    (128,734
    )Liabilities recorded in the balance sheet:Unfunded liabilities (included in other
noncurrent liabilities)
    
    
    (128,734
    )Amounts recorded in stockholders equity  December
31, 2008:Prior service cost
    
    $
    313Net actuarial loss
    
    
    132,874Total
    
    $
    133,187
 The accumulated benefit obligation (ABO) of the merged plan at the Remeasurement Date
is $301,464. Actuarial assumptions for the merged plan as of the Remeasurement Date are as
follows: discount rate  5.9%; expected return on plan assets  8.5%; rate of increase in
salary levels  3.8%.
  -16-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   6.
    
    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.
 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. In accordance with the terms
of the PNG Gas base rate case order which became effective December 2, 2006, site-specific
environmental investigation and remediation costs associated with PNG Gas incurred prior to
December 2, 2006 are amortized as removal costs over five-year periods. Such costs incurred
after December 1, 2006 are expensed as incurred.
 CPG is party to a Consent Order and Agreement with the Pennsylvania Department of
Environmental Protection dated February 15, 2005 (CPG-COA) requiring CPG to perform a
specified level of activities associated with environmental investigation and remediation
work at certain properties in Pennsylvania on which MGP-related facilities were operated
(MGP Properties) and to plug a minimum of 16 non-producing natural gas wells per year. CPG
has closed all but 8 of the MGP Properties and has plugged all but approximately 78 wells.
Under the CPG-COA, environmental expenditures relating to the MGP Properties are capped at
$1,750 in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP Properties
and at the end of 2013 for well plugging activities. In addition, CPG is responsible for
remediation of an MGP Property in Georgetown, Delaware. The costs associated with remediation
of the Georgetown MGP Property are not expected to be material. At June 30, 2009, our accrued
liability for environmental investigation and remediation costs related to the CPG-COA was
$11,619.
 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.
  -17-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   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.
 City of Bangor, Maine v. Frontier Communications Corporation, f/k/a Citizens Communications
Company. In April 2003, Citizens Communications Company, now known as Frontier Communications
Corporation (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 plaintiff, 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 costs Frontier may be required to pay to
the City for cleaning up tar deposits in the Penobscot River. Frontier alleges 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. Studies conducted by the City
and Frontier suggest that it could cost up to $18,000 to clean up the river. Frontiers
third-party claims were stayed pending trial of the Citys suit against Frontier, which took
place in September 2005. On June 27, 2006, the court issued an order finding Frontier
responsible for 60% of the cleanup costs. On February 14, 2007, Frontier and the City entered
into a settlement agreement pursuant to which Frontier agreed to pay $7,625 in exchange for a
release of its and all predecessors liabilities. Separately, the Maine Department of
Environmental Protection has disclaimed its previously announced intention to pursue
third-party defendants, including UGI Utilities, for costs incurred by the State of Maine
related to contaminants at this site. UGI Utilities believes that it has good defenses to all
of Frontiers claims.
 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.
  -18-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   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. In a second phase of the trial scheduled for
early 2010, the court will determine what, if any, contamination at Waterbury North is
related to UGI Utilities period of operation. The Northeast Companies estimate that
remediation costs at Waterbury North could total $25,000.
 In addition to these environmental matters, there are other pending claims and legal actions
arising in the normal course of our businesses. We cannot predict with certainty the final
results of any of our environmental or other matters. 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.
 7.
    
    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.
  -19-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   UGI Utilities has entered into a Storage Contract Administration Agreement (Storage
Agreement) extending through October 31, 2009 with UGI Energy Services, Inc., a second-tier
wholly owned subsidiary of UGI (Energy Services). Under the Storage Agreement UGI Utilities
has, among other things, and subject to recall for operational purposes, released certain
storage and transportation contracts to Energy Services for the term of the Storage
Agreement. UGI Utilities also transferred certain associated storage inventories upon the
commencement of the Storage Agreement, will receive a transfer of storage inventories at the
end of the Storage Agreement, and makes payments associated with refilling storage
inventories during the term of the Storage Agreement. Energy Services, in turn, provides a
firm delivery service and makes certain payments to UGI Utilities for its various obligations
under the Storage Agreement. UGI Utilities incurred costs associated with the Storage
Agreement totaling $18,144 and $38,005 during the three and nine months ended June 30, 2009,
respectively, and $46,056 and $68,212 during the three and nine months ended June 30, 2008,
respectively. In conjunction with the storage agreement, UGI Utilities received $15,000 in
security deposits from Energy Services which amount is included in other current liabilities
on the June 30, 2009 Condensed Consolidated Balance Sheet.
 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 released under the Storage Agreement at June
30, 2009, comprising approximately 4.2 billion cubic feet of natural gas, was $36,951. The
carrying value of these gas storage inventories at September 30, 2008, comprising
approximately 8.3 billion cubic feet of natural gas, was $70,833. The carrying value of these
gas storage inventories at June 30, 2008, comprising approximately 5.1 billion cubic feet of
natural gas, was $42,926.
 Gas Utility 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 peak heating-season months of November through to 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 Storage Agreement transactions) during
the three and nine months ended June 30, 2009 totaled $1,665 and $34,869, respectively.
During the three and nine months ended June 30, 2008, such transactions totaled $7,424 and
$43,609, respectively,
 From time to time, the Company sells natural gas or pipeline capacity to Energy Services.
During the three and nine months ended June 30, 2009, revenues associated with sales to
Energy Services totaled $3,625 and $24,438, respectively. During the three and nine months
ended June 30, 2008, such revenues totaled $21,561 and $50,204, respectively. These
transactions did not have a material effect on the Companys results of operations.
  -20-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   8.
    
    Financing Transactions
 On October 1, 2008, UGI Utilities issued $108,000 face value of 6.375% Senior Notes due
October 2013. The proceeds from the issuance of the Notes were used by UGI Utilities to fund
a portion of the CPG Acquisition.
 9.
    
    Fair Value Measurement
 The Company adopted SFAS 157 effective October 1, 2008. SFAS 157 defines fair value,
establishes a framework for measuring fair value in GAAP, and expands disclosures about fair
value measurements. SFAS 157 defines fair value as the price that would be received to sell
an asset or paid to transfer a liability (an exit price) in an orderly transaction between
market participants at the measurement date. SFAS 157 clarifies that the fair value should be
based upon assumptions that market participants would use when pricing an asset or liability,
including assumptions about risk and risks inherent in valuation techniques and inputs to
valuations. This includes not only the credit standing of counterparties and credit
enhancements but also the impact of our own nonperformance risk on our liabilities. SFAS 157
requires fair value measurements to assume that the transaction occurs in the principal
market for the asset or liability or in the absence of a principal market, the most
advantageous market for the asset or liability (the market for which the reporting entity
would be able to maximize the amount received or minimize the amount paid). We apply fair
value measurements to our commodity derivative instruments which principally comprise natural
gas futures contracts and Financial Transmission Rights (FTRs). Our commodity derivative
financial instruments (other than FTRs) are traded on the New York Mercantile Exchange
(NYMEX) and have nominal credit risk. Gas Utility uses natural gas derivative financial
instruments to reduce volatility in the cost of gas it purchases for its retail core-market
customers. Because of its ratemaking mechanism, gains or losses on natural gas derivative
financial instruments are included in gas costs charged to these customers.
 In accordance with SFAS 157, we maximize the use of observable inputs and minimize the use of
unobservable inputs when measuring fair value. With respect to our exchange-traded commodity
futures contracts, fair value is based upon actively-quoted market prices on the NYMEX. We
estimate FTR fair values based upon available historical and near-term price information.
 In accordance with SFAS 157, we use the following fair value hierarchy, which prioritizes the
inputs to valuation techniques used to measure fair value, into three broad levels:
 
    
    Level 1  Quoted prices (unadjusted) in active markets for identical assets and
liabilities that we have the ability to access at the measurement date. Instruments
categorized in Level 1 consist of our exchange-traded commodity futures contracts.
 
    
    Level 2  Inputs other than quoted prices included within Level 1 that are either
directly or indirectly observable for the asset or liability, including quoted
prices for similar assets or liabilities in active markets, quoted prices for
identical or similar assets or liabilities in inactive markets, inputs other than
quoted prices that are observable for the asset or liability, and inputs that are
derived from observable market data by correlation or other means. Instruments
categorized in Level 2 include our FTRs.
  -21-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   
    
    Level 3  Unobservable inputs for the asset or liability including situations
where there is little, if any, market activity for the asset or liability. The
Company did not have any derivative financial instruments categorized as Level 3 at
June 30, 2009.
 The fair value hierarchy gives the highest priority to quoted prices in active markets (Level
1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to
measure fair value might fall into different levels of the fair value hierarchy. The lowest
level input that is significant to a fair value measurement in its entirety determines the
applicable level in the fair value hierarchy. Assessing the significance of a particular
input to the fair value measurement in its entirety requires judgment, considering factors
specific to the asset or liability.
 SFAS 157 requires fair value measurements to be separately disclosed by level within the fair
value hierarchy. The following table presents our assets and liabilities that are measured at
fair value on a recurring basis for each hierarchy level, including both current and
noncurrent portions as of June 30, 2009:
 Level 1
    
    
    Level 2
    
    
    Level 3
    
    
    TotalDerivative financial instruments:Assets
    
    $
    4
    
    
    $
    1,002
    
    
    $
    
    
    
    $
    1,006Liabilities
    
    $
    (42,473
    )
    
    $
    
    
    
    $
    
    
    
    $
    (42,473
    )
 10.
    
    Disclosures About Derivative Instruments, Hedging Activities and Financial
Instruments
 Derivative Instruments and Hedging Activities
 The primary market risks managed by the Company through the use of derivative instruments are
(1) commodity price risk, principally natural gas commodity price risk and electricity
transmission congestion risk, and (2) interest rate risk. Due to Gas Utility and Electric
Utility ratemaking as further described below, there is limited commodity price risk
associated with these operations that affects our net income. 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 derivative, hedging
and credit policies which govern, among other things, the derivative instruments we can use,
counterparty credit limits and contract authorization limits.
  -22-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Commodity Price Risk
 Gas Utilitys tariffs contain clauses that permit recovery of substantially 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 gas cost PGC filings, Gas
Utility currently uses NYMEX natural gas futures contracts to reduce commodity price
volatility associated with a portion of the natural gas it purchases for its retail
core-market customers. At June 30, 2009, the volumes of natural gas associated with our
unsettled NYMEX natural gas futures contracts totaled 8.2 million dekatherms and the maximum
period over which we are hedging natural gas market risk is 15 months. Gains and losses on
unsettled natural gas futures contracts are recorded in deferred fuel costs on the Condensed
Consolidated Balance Sheet in accordance with SFAS No. 71, Accounting for the Effects of
Certain Types of Regulation, and reflected in cost of sales through the PGC mechanism. At
June 30, 2009, Gas Utility had recorded a current liability of $42,473, representing the fair
value of unsettled natural gas futures contracts as of that date, and an associated
regulatory asset of $42,473 within deferred fuel costs.
 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.
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. At June 30, 2009, the volume of electricity
congestion that is subject to FTRs totaled 1,277.0 million kilowatt-hours and the maximum
period over which we are currently hedging electricity congestion is 23 months. Because
Electric Utility is entitled to fully recover its default service costs commencing January 1,
2010 pursuant to a January 22, 2009 settlement of its default service rate filing with the
PUC (see Note 4), changes in the fair value of FTRs associated with periods after January 1,
2010 will not affect net income. FTRs associated with periods prior to January 2010 are
recorded at fair value with changes in fair value reflected in cost of sales.
 In order to reduce operating expense volatility, Gas Utility and Electric Utility from time
to time enter into NYMEX gasoline futures and swap contracts for a portion of gasoline
volumes expected to be used in the operation of their vehicles and equipment. These contracts
do not currently qualify for hedge accounting treatment. The volumes of gasoline associated
with NYMEX futures and swap contracts were not material for all periods presented.
  -23-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   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, to the extent effective in
offsetting changes in the underlying interest rate risk, until earnings are affected by the
hedged interest expense. At June 30, 2009 there were no unsettled IRPA contracts outstanding.
 The following table provides information regarding the balance sheet location and fair values
of derivative assets and liabilities existing as of June 30, 2009:
 Derivative Assets
    
    
    Derivative (Liabilities)Balance Sheet
    
    
    Fair
    
    
    Balance Sheet
    
    
    FairAs of June 30, 2009
    
    Location
    
    
    Value
    
    
    Location
    
    
    ValueDerivatives Accounted for Under SFAS 71:Natural gas futures contracts
    
    
    
    
    
    
    
    
    
    Derivative financial
instruments
    
    $
    (42,473
    )Derivatives Not Designated as
Hedging Instruments:FTRs
    
    Derivative financial instruments
    
    $
    1,002Gasoline futures contracts
    
    Derivative financial instruments
    
    
    4Total Derivatives Not Designated
as Hedging Instruments
    
    
    
    
    
    $
    1,006
    
    
    
    
    
    
    $
    Total Derivatives
    
    
    
    
    
    $
    1,006
    
    
    
    
    
    
    $
    (42,473
    )
 During the three and nine months ended June 30, 2009, the amount of IRPA net losses
included in AOCI that were reclassified into net income, and the impact of changes in the
fair value of FTRs and gasoline futures and swap contracts on our net income, were not
material.
  -24-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Notes to Condensed Consolidated Financial Statements
   Financial Instruments
 The carrying amounts of financial instruments included in current assets and current
liabilities (excluded unsettled derivatives and current maturities of long-term debt)
approximate their fair values because of their short-term nature. The carrying amounts and
estimated values of our remaining financial instruments assets and (liabilities) at June 30,
2009 (including unsettled derivative instruments) are as follows:
 Asset (Liability)Carrying
    
    
    EstimatedAmount
    
    
    Fair ValueDerivative financial instruments
    
    $
    (41,467
    )
    
    $
    (41,467
    )Long-term debt
    
    
    (640,000
    )
    
    
    (657,832
    )
 We estimate the fair value of long-term debt by using current market prices and by
discounting future cash flows using rates available for similar type of debt. Fair value of
derivative instruments are determined in accordance with the provisions of SFAS 157 as
described in Note 9.
  -25-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 ITEM 2.
    
    MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 Forward-Looking Statements
     -26-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 ANALYSIS OF RESULTS OF OPERATIONS
  2009 three-month period compared with 2008 three-month period
 IncreaseThree Months Ended June 30,
    
    2009
    
    
    2008
    
    
    (Decrease)(Millions of dollars)Gas Utility:Revenues
    
    $
    176.9
    
    
    $
    202.1
    
    
    $
    (25.2
    )
    
    
    (12.5
    )%Total margin (a)
    
    $
    67.1
    
    
    $
    54.8
    
    
    $
    12.3
    
    
    
    22.4
    %Operating income
    
    $
    12.9
    
    
    $
    12.4
    
    
    $
    0.5
    
    
    
    4.0
    %Income before income taxes
    
    $
    2.6
    
    
    $
    4.0
    
    
    $
    (1.4
    )
    
    
    (35.0
    )%System throughput  bcf
    
    
    25.8
    
    
    
    23.4
    
    
    
    2.4
    
    
    
    10.3
    %Heating degree days  % (warmer)
than normal (b)
    
    
    (6.5
    )%
    
    
    (2.7
    )%
    
    
    
    
    
    
    Electric Utility:Revenues
    
    $
    30.7
    
    
    $
    32.8
    
    
    $
    (2.1
    )
    
    
    (6.4
    )%Total margin (a)
    
    $
    9.4
    
    
    $
    13.2
    
    
    $
    (3.8
    )
    
    
    (28.8
    )%Operating income
    
    $
    3.4
    
    
    $
    7.5
    
    
    $
    (4.1
    )
    
    
    (54.7
    )%Income before income taxes
    
    $
    2.9
    
    
    $
    7.1
    
    
    $
    (4.2
    )
    
    
    (59.2
    )%Distribution sales  gwh
    
    
    209.8
    
    
    
    224.9
    
    
    
    (15.1
    )
    
    
    (6.7
    )%
 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 $1.7 million and $1.9 million during the
three-month periods ended June 30, 2009 and 2008, respectively. For financial statement
purposes, revenue-related taxes are included in Taxes other than income taxes in the
Condensed Consolidated Statements of Income.(b)
    
    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.
  -27-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
    Electric Utility.
   -28-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
  2009 nine-month period compared with 2008 nine-month period
 IncreaseNine Months Ended June 30,
    
    2009
    
    
    2008
    
    
    (Decrease)(Millions of dollars)Gas Utility:Revenues
    
    $
    1,130.1
    
    
    $
    1,005.6
    
    
    $
    124.5
    
    
    
    12.4
    %Total margin (a)
    
    $
    334.4
    
    
    $
    266.3
    
    
    $
    68.1
    
    
    
    25.6
    %Operating income
    
    $
    149.8
    
    
    $
    138.1
    
    
    $
    11.7
    
    
    
    8.5
    %Income before income taxes
    
    $
    118.1
    
    
    $
    109.7
    
    
    $
    8.4
    
    
    
    7.7
    %System throughput  bcf
    
    
    126.4
    
    
    
    112.4
    
    
    
    14.0
    
    
    
    12.5
    %Heating degree days  % colder (warmer)
than normal (b)
    
    
    3.9
    %
    
    
    (2.2
    )%
    
    
    
    
    
    
    Electric Utility:Revenues
    
    $
    104.8
    
    
    $
    103.3
    
    
    $
    1.5
    
    
    
    1.5
    %Total margin (a)
    
    $
    32.0
    
    
    $
    37.8
    
    
    $
    (5.8
    )
    
    
    (15.3
    )%Operating income
    
    $
    13.8
    
    
    $
    21.4
    
    
    $
    (7.6
    )
    
    
    (35.5
    )%Income before income taxes
    
    $
    12.6
    
    
    $
    19.9
    
    
    $
    (7.3
    )
    
    
    (36.7
    )%Distribution sales  gwh
    
    
    735.8
    
    
    
    758.4
    
    
    
    (22.6
    )
    
    
    (3.0
    )%
 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 $5.7 million and $5.9 million during the
nine-month periods ended June 30, 2009 and 2008, respectively. For financial statement
purposes, revenue-related taxes are included in Taxes other than income taxes in the
Condensed Consolidated Statements of Income.(b)
    
    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.
  -29-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
    Electric Utility.
    -30-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 FINANCIAL
CONDITION AND LIQUIDITY
 Financial Condition
   Acquisition of PPL Gas Utilities Corporation
    -31-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
  Merger of Defined Benefit Pension Plans
  Effect of Recent Market Conditions
     -32-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
  Cash Flows
 Operating activities.
  Investing activities.
  -33-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 Financing activities.
 Regulatory Matters
 UGIPNG and CPG Base Rate Filings.
 Electric Utility.
  -34-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
   
 ITEM 3.
    
    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
    -35-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
       -36-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 
 ITEM 4T.
    
    CONTROLS AND PROCEDURES
 (a)
    
    Evaluation of Disclosure Controls and Procedures
 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 designed and
functioning effectively 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 Securities and Exchange Commission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 disclosure.
 (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.
  -37-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 
 PART II OTHER INFORMATION
 
 ITEM 1.
    
    LEGAL PROCEEDINGS
 Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc.
 
 ITEM 1A.
    
    RISK FACTORS
   -38-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 
 ITEM 6.
    
    EXHIBITS
  Incorporation by Reference
 Exhibit No.
    
    Exhibit
    
    Registrant
    
    Filing
    
    Exhibit12.1
    
    
    Computation of
ratio of earnings
to fixed charges31.1
    
    
    Certification by
the Chief Executive
Officer relating to
the Registrants
Report on Form 10-Q
for the quarter
ended June 30,
2009, pursuant to
Section 302 of the
Sarbanes-Oxley Act
of 200231.2
    
    
    Certification by
the Chief Financial
Officer relating to
the Registrants
Report on Form 10-Q
for the quarter
ended June 30,
2009, pursuant to
Section 302 of the
Sarbanes-Oxley Act
of 200232
    
    
    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 June 30,
2009, pursuant to
Section 906 of the
Sarbanes-Oxley Act
of 2002
  -39-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 
 SIGNATURES
  UGI Utilities, Inc.
(Registrant)Date:  August 7, 2009
    By:
    /s/ John C. BarneyJohn C. BarneySenior Vice President  Finance and
Chief Financial Officer  -40-




---



##### Table of Contents



UGI UTILITIES, INC. AND SUBSIDIARIES
 
 EXHIBIT INDEX
 12.1
    
    
    Computation of ratio of earnings to fixed charges31.1
    
    
    Certification by the Chief Executive Officer relating to the Registrants Report
on Form 10-Q for the quarter ended June 30, 2009, pursuant to Section 302 of the
Sarbanes-Oxley Act of 200231.2
    
    
    Certification by the Chief Financial Officer relating to the Registrants Report
on Form 10-Q for the quarter ended June 30, 2009 , pursuant to Section 302 of the
Sarbanes-Oxley Act of 200232
    
    
    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 June 30, 2009,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002