Ugi Utilities 10-Q 2006 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2006

OR

¨ 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 incorporation or organization)	(I.R.S. Employer Identification No.)

UGI UTILITIES, INC.

100 Kachel Boulevard, Suite 400

Green Hills Corporate Center, Reading, PA

(Address of principal executive offices)

19607

(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  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨                             Accelerated filer  ¨                            Non-accelerated filer  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

At July 31, 2006, 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.

TABLE OF CONTENTS

		PAGES
Part I Financial Information
Item 1.	Financial Statements
	Condensed Balance Sheets as of June 30, 2006, September 30, 2005 and June 30, 2005	1
	Condensed Statements of Income for the three and nine months ended June 30, 2006 and 2005	2
	Condensed Statements of Cash Flows for the nine months ended June 30, 2006 and 2005	3
	Notes to Condensed Financial Statements	4 - 15
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16 - 24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24 - 25
Item 4.	Controls and Procedures	25
Part IIOther Information
Item 1.	Legal Proceedings	26
Item 1A.	Risk Factors	26
Item 6.	Exhibits	26 - 27
Signatures		28

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UGI UTILITIES, INC.

CONDENSED BALANCE SHEETS

(unaudited)

(Thousands of dollars)

	June 30, 2006		September 30, 2005		June 30, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	8,418	$	2,686	$	653
Accounts receivable (less allowances for doubtful accounts of $9,523, $4,562 and $7,222, respectively)		68,588		48,597		56,207
Accounts receivable - related parties		1,240		1,063		1,304
Accrued utility revenues		12,240		10,360		8,503
Inventories		53,594		71,584		39,198
Deferred income taxes		9,430		12,484		15,661
Derivative financial instruments		5,004		5,688		638
Prepaid expenses and other current assets		5,540		3,875		3,095
Total current assets		164,054		156,337		125,259
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $344,478, $330,329 and $327,961, respectively)		672,187		655,322		644,882
Regulatory assets		61,287		61,334		66,778
Other assets		26,460		30,680		29,012
Total assets	$	923,988	$	903,673	$	865,931
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	20,000	$	50,000	$	50,000
Bank loans		112,100		81,200		49,500
Accounts payable		23,359		38,430		23,243
Accounts payable - related parties		14,456		14,371		15,616
Employee compensation and benefits accrued		7,262		9,007		9,048
Customer deposits and refunds		19,893		20,064		12,178
Deferred fuel refunds		10,054		17,370		19,082
Accrued income taxes		10,733		—		12,264
Electric supplier collateral deposits		—		13,500		6,600
Other current liabilities		8,196		15,444		7,839
Total current liabilities		226,053		259,386		205,370
Long-term debt		217,000		187,030		187,060
Deferred income taxes		160,099		160,920		164,732
Deferred investment tax credits		6,901		7,193		7,290
Other noncurrent liabilities		16,367		14,213		17,691
Total liabilities		626,420		628,742		582,143
Commitments and contingencies (note 5)
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		80,622		80,622		79,773
Retained earnings		154,765		133,807		145,896
Accumulated other comprehensive income (loss)		1,922		243		(2,140	)
Total common stockholder’s equity		297,568		274,931		283,788
Total liabilities and stockholder’s equity	$	923,988	$	903,673	$	865,931

See accompanying notes to condensed financial statements.

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UGI UTILITIES, INC.

CONDENSED STATEMENTS OF INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended June 30,						Nine Months Ended June 30,
	2006			2005			2006			2005
Revenues	$	129,128		$	111,534		$	694,446		$	576,469
Costs and expenses:
Cost of sales-gas, fuel and purchased power		82,802			65,244			492,241			372,033
Operating and administrative expenses		22,050			21,698			71,495			70,239
Operating and administrative expenses - related parties		3,749			3,995			8,467			9,612
Taxes other than income taxes		3,172			3,152			10,154			10,079
Depreciation and amortization		6,373			6,019			18,856			17,785
Other income, net		(749	)		(1,242	)		(3,930	)		(4,486	)
		117,397			98,866			597,283			475,262
Operating income		11,731			12,668			97,163			101,207
Interest expense		5,344			4,394			16,300			13,543
Income before income taxes		6,387			8,274			80,863			87,664
Income taxes		2,928			3,367			32,450			35,083
Net income	$	3,459		$	4,907		$	48,413		$	52,581

See accompanying notes to condensed financial statements.

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UGI UTILITIES, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)

(Thousands of dollars)

	Nine Months Ended June 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	48,413		$	52,581
Adjustments to reconcile net income to net cash used by operating activities:
Depreciation and amortization		18,856			17,785
Deferred income tax expense (benefit), net		769			(3,531	)
Provision for uncollectible accounts		8,777			7,135
Other, net		6,566			2,136
Net change in:
Accounts receivable and accrued utility revenues		(30,181	)		(24,510	)
Inventories		17,990			25,979
Deferred fuel costs		(7,316	)		11,220
Accounts payable		(14,986	)		(23,848	)
Other current assets and liabilities		(10,779	)		6,453
Net cash provided by operating activities		38,109			71,400
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(34,946	)		(30,355	)
Net costs of property, plant and equipment disposals		(876	)		(873	)
Net cash used by investing activities		(35,822	)		(31,228	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends		(27,455	)		(28,140	)
Redemption of preferred shares subject to mandatory redemption		—			(20,000	)
Increase (decrease) in bank loans with maturities of three months or less		80,900			(11,400	)
Issuances of debt including bank loans with maturities greater than three months		70,000			60,000
Repayments of debt including bank loans with maturities greater than three months		(120,000	)		(40,000	)
Net cash provided (used) by financing activities		3,445			(39,540	)
Cash and cash equivalents increase	$	5,732		$	632
CASH AND CASH EQUIVALENTS:
End of period	$	8,418		$	653
Beginning of period		2,686			21
Increase	$	5,732		$	632

See accompanying notes to condensed financial statements.

-3-

UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

1. Basis of Presentation

UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), owns and operates a natural gas distribution utility (“Gas Utility”) in parts of eastern and southeastern Pennsylvania and an electricity distribution utility (“Electric Utility”) in northeastern Pennsylvania. We refer to Gas Utility and Electric Utility collectively as “the Company” or “we.” Gas Utility and Electric Utility are subject to regulation by the Pennsylvania Public Utility Commission (“PUC”).

The accompanying condensed 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, 2005 condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. These financial statements should be read in conjunction with the financial statements and the related notes included in our Annual Report on Form 10-K for the year ended September 30, 2005 (“Company’s 2005 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.

Comprehensive Income. The following table presents the components of comprehensive income for the three and nine months ended June 30, 2006 and 2005:

	Three Months Ended June 30,					Nine Months Ended June 30,
	2006		2005			2006		2005
Net income	$	3,459	$	4,907		$	48,413	$	52,581
Other comprehensive income (loss)		421		(1,509	)		1,679		(685	)
Comprehensive income	$	3,880	$	3,398		$	50,092	$	51,896

Other comprehensive income (loss) comprises changes in the fair value of interest rate protection and electricity price swap agreements qualifying as hedges, net of reclassifications to net income.

Equity-Based Compensation. Under UGI’s 2004 Omnibus Equity Compensation Plan (“OECP”), certain key employees of UGI Utilities may be granted stock options and other equity-based awards (“Units”) of UGI Common Stock. Such awards typically vest ratably over a period of three years. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or eliminate further service requirements. Stock options for UGI Common Stock generally can be exercised no later than ten years from the grant date. Effective October 1, 2005, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”). Prior to October 1, 2005, as permitted, we applied the provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock

-4-

UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

Issued to Employees” (“APB 25”), in recording compensation expense for grants of stock, stock options and other equity instruments to employees. Under APB 25, the Company did not record any compensation expense for stock options, but provided the required pro forma disclosures as if we had determined compensation expense under the fair value method prescribed by the provisions of SFAS No. 123. Under SFAS 123R, all equity-based compensation cost is measured on the grant date or at period end based on the fair value of that award and is recognized in the income statement over the requisite service period.

As permitted by SFAS 123R, under the modified prospective approach, effective October 1, 2005, we began recording compensation expense for awards that were not vested as of that date and did not restate any prior periods. For the periods prior to and subsequent to the adoption of SFAS 123R, we used the Black-Scholes option-pricing model to estimate the fair value of each option. The adoption of SFAS 123R resulted in pre-tax compensation expense associated with stock options of $107 ($63 after-tax) and $295 ($173 after-tax) during the three and nine months ended June 30, 2006, respectively. As of June 30, 2006, there was $514 of unrecognized compensation cost related to non-vested stock options that is expected to be recognized over a weighted average period of 1.9 years. Assuming no significant change in the level of future stock option grants to UGI Utilities’ employees, we do not believe that compensation expense associated with stock options will have a material impact on our financial position, results of operations or cash flows.

Both prior to and subsequent to the adoption of SFAS 123R, we measured and recorded compensation cost of Units awarded to employees prior to January 1, 2006 (that can be settled at UGI’s option in cash or shares of Common Stock, or a combination of both) based upon their fair value as of the end of each period. The fair value of Units is generally dependent upon UGI’s stock price and its performance in comparison to a group of peer companies. The fair value of these awards is expensed over requisite service periods.

Effective in June 2006, UGI modified the settlement terms of those Units awarded to employees having an original grant date of January 1, 2006. For these Unit awards, we used the Monte Carlo valuation model to estimate their fair value. Compensation costs associated with these modified awards are measured based upon the fair value on the date of modification and as of the end of each period, as appropriate. Compensation costs are recorded over requisite service periods. The Company did not incur any incremental compensation expense as a result of this modification.

We recorded total net pre-tax equity-based compensation expense associated with both Units and stock options of $467 ($273 after-tax) and $277 ($162 after-tax) during the three and nine months ended June 30, 2006, respectively. The lower net equity-based compensation expense recorded during the nine months ended June 30, 2006 is principally due to changes in the fair value of awards made under the OECP, largely resulting from changes in stock prices.

-5-

UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

The following table illustrates the effects on net income as if we had applied the provisions of SFAS 123R to all equity-based compensation awards for the comparable periods prior to the adoption of SFAS 123R.

	Three Months Ended June 30, 2005			Nine Months Ended June 30, 2005
Net income, as reported	$	4,907		$	52,581
Add: Equity-based employee compensation expense included in reported net income, net of related tax effects		307			888
Deduct: Total equity-based employee compensation expense determined under the fair value method for all awards, net of related tax effects		(337	)		(1,042	)
Pro forma net income	$	4,877		$	52,427

During the nine months ended June 30, 2006, a portion of vested Unit awards were settled in shares of UGI Common Stock and $384 in cash. As of June 30, 2006, there was a total of $873 of unrecognized compensation expense associated with 66,234 Unit awards that are expected to be recognized over a weighted average period of 1.9 years. At June 30, 2006, total liabilities of $1,126 associated with Unit awards are reflected in other current liabilities and other noncurrent liabilities in the Condensed Balance Sheet.

The following table illustrates the number of unvested Unit awards:

	Number of UGI Units		Weighted-Average Grant Date Fair Value (per Unit)
Non-vested awards - September 30, 2005	27,182		$	20.82
Granted	19,500		$	23.26
Vested	(17,599	)	$	20.79
Non-vested awards - June 30, 2006	29,083		$	22.47

Reclassifications.We have reclassified certain prior-year balances to conform to the current period presentation.

Use of Estimates. We make estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States of America. 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.

Recently Issued Accounting Pronouncements.In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes,” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 provides guidance on the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also

-6-

UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition. FIN 48 is effective for our fiscal year beginning October 1, 2007. We are currently evaluating the impact that this standard will have on our Financial Statements.

2. 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 2005 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.

-7-

UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

Financial information by business segment follows:

Three Months Ended June 30, 2006:

	Total		Gas Utility		Electric Utility
Revenues	$	129,128	$	106,263	$	22,865
Cost of sales - gas, fuel and purchased power		82,802		71,631		11,171
Depreciation and amortization		6,373		5,533		840
Operating income		11,731		6,553		5,178
Interest expense		5,344		4,680		664
Income before income taxes		6,387		1,873		4,514
Total assets at period end		923,988		817,488		106,500
Three Months Ended June 30, 2005:
	Total		Gas Utility		Electric Utility
Revenues	$	111,534	$	89,504	$	22,030
Cost of sales - gas, fuel and purchased power		65,244		54,612		10,632
Depreciation and amortization		6,019		5,240		779
Operating income		12,668		7,692		4,976
Interest expense		4,394		3,923		471
Income before income taxes		8,274		3,769		4,505
Total assets at period end		865,931		768,723		97,208

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UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

Nine Months Ended June 30, 2006:

	Total		Gas Utility		Electric Utility
Revenues	$	694,446	$	622,280	$	72,166
Cost of sales - gas, fuel and purchased power		492,241		454,540		37,701
Depreciation and amortization		18,856		16,376		2,480
Operating income		97,163		82,161		15,002
Interest expense		16,300		14,380		1,920
Income before income taxes		80,863		67,781		13,082
Total assets at period end		923,988		817,488		106,500
Nine Months Ended June 30, 2005:
	Total		Gas Utility		Electric Utility
Revenues	$	576,469	$	506,584	$	69,885
Cost of sales - gas, fuel and purchased power		372,033		338,500		33,533
Depreciation and amortization		17,785		15,470		2,315
Operating income		101,207		84,379		16,828
Interest expense		13,543		12,034		1,509
Income before income taxes		87,664		72,345		15,319
Total assets at period end		865,931		768,723		97,208

-9-

UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

3. Long-Term Debt

In December 2005, UGI Utilities refinanced $50,000 of its maturing 7.14% Medium-Term Notes with proceeds from the issuance of $50,000 of 5.64% Medium-Term Notes due in December 2015. These Medium-Term Notes were issued pursuant to the Company’s $125,000 shelf registration statement with the SEC.

4. Defined Benefit Pension and Other Postretirement Plans

We sponsor a defined benefit pension plan (“UGI Utilities Pension Plan”) for employees of UGI, UGI Utilities and certain of UGI’s other wholly owned subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all active and retired employees. Net periodic pension expense and other postretirement benefit costs relating to UGI Utilities’ employees include the following components:

	Pension Benefits Three Months Ended June 30,						Other Postretirement Benefits Three Months Ended June 30,
	2006			2005			2006			2005
Service cost	$	1,309		$	1,090		$	32		$	29
Interest cost		3,220			2,998			204			368
Expected return on assets		(4,444	)		(3,975	)		(152	)		(119	)
Amortization of:
Transition obligation		—			—			—			169
Prior service cost (benefit)		196			155			(55	)		—
Actuarial loss		427			308			48			81
Net benefit cost		708			576			77			528
Change in regulatory and other assets and liabilities		(96	)		—			698			247
Net expense	$	612		$	576		$	775		$	775
	Pension Benefits Nine Months Ended June 30,						Other Postretirement Benefits Nine Months Ended June 30,
	2006			2005			2006			2005
Service cost	$	3,930		$	3,270		$	97		$	86
Interest cost		9,662			8,994			612			1,105
Expected return on assets		(13,336	)		(11,925	)		(457	)		(357	)
Amortization of:
Transition obligation		—			—			—			507
Prior service cost (benefit)		588			465			(166	)		—
Actuarial loss		1,280			924			144			244
Net benefit cost		2,124			1,728			230			1,585
Change in regulatory and other assets and liabilities		(278	)		—			2,095			740
Net expense	$	1,846		$	1,728		$	2,325		$	2,325

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UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

UGI Utilities Pension Plan 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 UGI Utilities Pension Plan during the year ending September 30, 2006. Pursuant to orders previously issued by the PUC, UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to fund and pay UGI Utilities’ 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 Utilities rates is deferred for future recovery from, or refund to, ratepayers. During the nine months ended June 30, 2006, the Company made contributions of approximately $560 to the VEBA and expects to contribute a total of approximately $750 during the twelve months ending September 30, 2006.

We also sponsor an unfunded and non-qualified supplemental executive retirement income plan. We recorded pre-tax expense for this plan of $105 and $306 for the three and nine months ended June 30, 2006, respectively, and $116 and $332 for the three and nine months ended June 30, 2005, respectively.

5. 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, UGI Utilities divested all of its utility operations other than those which now constitute Gas Utility 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 Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. 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. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.

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UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

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.

By letter dated July 14, 2006, SCANA Corporation (“SCANA”) demanded contribution from UGI Utilities for a portion of past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. According to the letter, the plant operated from 1855 to 1954. SCANA alleges that UGI Utilities controlled operations of the plant from 1910 to 1926. SCANA asserts that it has spent approximately $22,000 in remediation costs and $26,000 in third-party claims relating to the site. It estimates that future remediation costs could be as high as $2,500 and asserts that it has received a demand from the United States Justice Department for natural resource damages. SCANA claims that UGI Utilities is liable for 47% of the costs associated with the site. UGI Utilities is in the process of reviewing the information provided by SCANA and is investigating this claim.

In April 2003, Citizens Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District for the District of Maine. In that action, the plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18,000 to clean up the river. Citizens’ third party claims have been stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March of 2005 that it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of Maine related to gas plant contaminants at this site. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. The amount of Citizens’ liability has not been finally determined. UGI Utilities believes that it has good defenses to Citizens’ claim and to any claim that the DEP may bring to recover its costs, and is defending the Citizens’ suit.

By letter dated July 29, 2003, Atlanta Gas Light Company (“AGL”) served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8,000 incurred by AGL in the investigation and remediation of a former MGP site in St.

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UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. In March 2005, the court granted UGI Utilities’ motion for summary judgment dismissing AGL’s complaint. AGL has appealed.

AGL previously informed UGI Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL has informed UGI Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55,000. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site.

On September 20, 2001, Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70,000.

The trial court granted UGI Utilities’ motion for summary judgment and dismissed ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court’s decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. On October 7, 2005, UGI Utilities filed for reconsideration of the panel’s order. On January 17, 2006, the Second Circuit denied UGI Utilities’ request for reconsideration of the panel’s order.

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 go as high as $20,000. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.

By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together the “Northeast

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UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

Companies”), demanded 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. By letter dated March 17, 2006, the Northeast Companies estimated that remediation costs for all of the sites would total approximately $215,000 and claimed that UGI Utilities is responsible for approximately $103,000 of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23,000. UGI Utilities believes that it will have good defenses to any action that may arise out of the remaining sites.

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 environmental and 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.

6. Related Party Transactions

UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct and for an allocated share of indirect corporate expenses incurred or paid on behalf of UGI Utilities. These billed expenses are classified as operating and administrative expenses-related parties in the Condensed 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.

Effective December 1, 2004, following a competitive bidding process, UGI Utilities entered into a Storage Contract Administrative Agreement (“Storage Agreement”) with UGI Energy Services, Inc., a second-tier wholly owned subsidiary of UGI (“Energy Services”). The Storage Agreement was initially scheduled to expire on October 31, 2005, but effective November 1, 2005, UGI Utilities and Energy Services agreed to extend the Storage Agreement through October 31, 2008. Under the Storage Agreement, Energy Services provides a firm natural gas delivery service to UGI Utilities. UGI Utilities has released certain gas transportation and storage contracts through October 31, 2008 and transferred associated gas storage inventories to Energy Services. UGI Utilities may recall such released transportation and storage contracts without penalty if recalled

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UGI UTILITIES, INC.

Notes to Condensed Financial Statements

(unaudited)

(Thousands of dollars, except per share amounts)

to meet operational requirements, and if not recalled, the releases will terminate at the end of the term of the Storage Agreement. In exchange for the ability to utilize these assets, Energy Services pays a monthly fee to UGI Utilities. During the three and nine months ended June 30, 2006, UGI Utilities incurred costs associated with purchases of natural gas storage inventories from Energy Services and incurred associated pipeline transportation and storage capacity charges pursuant to the Storage Agreement totaling $31,627 and $53,106, respectively. During the three and nine months ended June 30, 2005, UGI Utilities incurred costs associated with purchases of natural gas storage inventories from Energy Services and incurred associated pipeline transportation and storage capacity charges pursuant to the Storage Agreement totaling $36,659 and $44,396, 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 June 30, 2006, comprising approximately 5.5 billion cubic feet of natural gas, was $46,702.

UGI Utilities has a Gas Supply and Delivery Service Agreement 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 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 months ended June 30, 2006 and 2005, totaled $3,227 and $190, respectively, and during the nine months ended June 30, 2006 and 2005, totaled $12,161 and $8,256, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and nine month periods ended June 30, 2006 and 2005, 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.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

Information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this Quarterly Report 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) competitive pressures from the same and alternative energy sources; (5) liability for environmental claims; (6) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (7) adverse labor relations; (8) large customer, counterparty or supplier defaults; (9) increased uncollectible accounts expense; (10) 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; (11) political, regulatory and economic conditions in the United States; and (12) reduced access to capital markets and interest rate fluctuations.

These factors 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 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.

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for (1) the three months ended June 30, 2006 (“2006 three-month period”) with the three months ended June 30, 2005 (“2005 three-month period”) and (2) the nine months ended June 30, 2006 (“2006 nine-month period”) with the nine months ended June 30, 2005 (“2005 nine-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 2 to the Condensed Financial Statements.

2006 three-month period compared with 2005 three-month period

Three Months Ended June 30, (Millions of dollars)	2006			2005			Increase (Decrease)
Gas Utility:
Revenues (a)	$	106.3		$	89.5		$	16.8			18.8	%
Total margin (a) (b)	$	34.6		$	34.9		$	(0.3	)		(0.9	)%
Operating income	$	6.6		$	7.7		$	(1.1	)		(14.3	)%
Income before income taxes	$	1.9		$	3.8		$	(1.9	)		(50.0	)%
System throughput - bcf (a)		14.3			15.3			(1.0	)		(6.5	)%
Heating degree days - % warmer than normal (c)		13.5	%		3.5	%		—			—
Electric Utility:
Revenues (a)	$	22.9		$	22.0		$	0.9			4.1	%
Total margin (a) (b)	$	10.5		$	10.2		$	0.3			2.9	%
Operating income	$	5.2		$	5.0		$	0.2			4.0	%
Income before income taxes	$	4.5		$	4.5		$	—		$	0.0	%
Distribution sales - gwh (a)		222.4			222.5			(0.1	)		(0.0	)%

bcf - billions of cubic feet. gwh - millions of kilowatt-hours.

(a) Beginning in Fiscal 2006, Gas Utility and Electric Utility adjusted their methods of estimating unbilled sales volumes and associated revenues for service provided through the end of the month by more closely correlating such estimated sales volumes to distribution system sendout data. The Company believes that the new methods of estimating unbilled sales volumes results in a more accurate quarterly estimate of unbilled revenues and associated total margin. The change in the method of estimating Gas Utility’s unbilled sales volumes did not have a material impact on Gas Utility’s throughput, revenues or margin for the 2006 three-month period. The change in the method of estimating Electric Utility’s unbilled sales volumes resulted in a 1.6 gwh decrease in distribution system sales and associated decreases in Electric Utility revenues and total margin of $0.1 million, for the 2006 three-month period.

(b) Gas Utility’s total margin represents total revenues less 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 $1.2 million in each of the three-month periods ended June 30, 2006 and 2005. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” on the Condensed Statements of Income.

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UGI UTILITIES, INC.

(c) Deviation from average heating degree days based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for four airports located within our service territory. The 2005 three-month period degree day statistics have been restated to reflect the current-year, four-location average from the previous single location statistic.

Gas Utility. Weather in Gas Utility’s service territory based upon heating degree days was 13.5% warmer than normal during the 2006 three-month period compared to 3.5% warmer than normal in the prior-year three-month period. Notwithstanding year-over-year growth in the number of Gas Utility’s customers, total distribution system throughput decreased 6.5% in the 2006 three-month period reflecting a 0.7 bcf decrease in sales to firm- residential, commercial and industrial (“retail core-market”) customers and lower firm delivery service volumes. The decrease in retail core-market throughput largely reflects the effects of significantly warmer spring weather and, to a lesser extent, the continued effects of lower average usage per customer resulting from significantly higher natural gas prices.

Notwithstanding the decline in distribution system throughput, Gas Utility revenues increased $16.8 million during the 2006 three-month period principally reflecting (1) a $10.9 million increase in revenues from low-margin off-system sales and (2) increased retail core-market revenues, reflecting the result of higher average purchased gas cost (“PGC”) rates partially offset by the effects of the lower volumes sold. Increases or decreases in retail core-market customer revenues and cost of sales result principally from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under this recovery mechanism, 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 amount 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 $71.6 million in the 2006 three-month period compared to $54.6 million in the 2005 three-month period largely reflecting greater costs associated with the higher off-system sales and the impact of the higher retail core-market purchased gas costs.

Gas Utility total margin in the 2006 three-month period decreased $0.3 million reflecting decreased retail core-market margin principally resulting from the lower sales to retail core-market customers partially offset by higher total margin from interruptible customers reflecting higher interruptible unit margins.

Gas Utility operating income decreased to $6.6 million in the 2006 three-month period from $7.7 million in the 2005 three-month period principally reflecting the $0.3 million decrease in total margin, slightly lower other income and higher depreciation and amortization expense. Total operating and administrative expenses were comparable to the prior-year period as higher uncollectible accounts and customer assistance program costs were largely offset by lower incentive compensation and distribution system expenses.

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UGI UTILITIES, INC.

The decrease in Gas Utility income before income taxes reflects the previously mentioned decrease in operating income and an increase in interest expense. The increase in interest expense is principally attributable to higher short-term debt outstanding, largely reflecting the effects of higher natural gas prices, and higher short-term interest rates.

Electric Utility.Electric Utility’s 2006 three-month period kilowatt-hour sales were comparable to the prior-year period. Electric Utility revenues increased by $0.9 million in the 2006 three-month period largely reflecting the effects of a 3% increase in its Provider of Last Resort (“POLR”) rates effective January 1, 2006. Electric Utility’s cost of sales increased to $11.2 million in the 2006 three-month period from $10.6 million in the 2005 three-month period reflecting higher per unit purchased power costs.

Electric Utility total margin in the 2006 three-month period increased $0.3 million principally reflecting lower 2006 three-month period transmission and congestion costs and the higher POLR rates partially offset by the higher per unit purchased power costs.

Operating income increased in the 2006 three-month period principally reflecting the increase in total margin. The increase in income before income taxes was comparable to the prior year as the increase in operating income was offset by higher interest expense on short-term debt.

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UGI UTILITIES, INC.

2006 nine-month period compared with 2005 nine-month period

Nine Months Ended June 30, (Millions of dollars)	2006			2005			Increase (Decrease)
Gas Utility:
Revenues (a)	$	622.3		$	506.6		$	115.7		22.8	%
Total margin (a) (b)	$	167.7		$	168.1		$	(0.4	)	(0.2	)%
Operating income	$	82.2		$	84.4		$	(2.2	)	(2.6	)%
Income before income taxes	$	67.8		$	72.3		$	(4.5	)	(6.2	)%
System throughput - bcf (a)		64.4			69.2			(4.8	)	(6.9	)%
Heating degree days - % warmer than normal (c)		8.8	%		0.7	%		—		—
Electric Utility:
Revenues (a)	$	72.2		$	69.9		$	2.3		3.3	%
Total margin (a) (b)	$	30.5		$	32.5		$	(2.0	)	(6.2	)%
Operating income	$	15.0		$	16.8		$	(1.8	)	(10.7	)%
Income before income taxes	$	13.1		$	15.3		$	(2.2	)	(14.4	)%
Distribution sales - gwh (a)		748.8			753.7			(4.9	)	(0.7	)%

(a) Beginning in Fiscal 2006, Gas Utility and Electric Utility adjusted their methods of estimating unbilled sales volumes and associated revenues for service provided through the end of the month by more closely correlating such estimated sales volumes to distribution system sendout data. The Company believes that the new methods of estimating unbilled sales volumes results in a more accurate quarterly estimate of unbilled revenues and associated total margin. The change in the method of estimating unbilled sales volumes did not have a material effect on Gas Utility or Electric Utility sales volumes, revenues or margin for the nine months ended June 30, 2006.

(b) Gas Utility’s total margin represents total revenues less 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 $4.0 million and $3.9 million in the nine month periods ended June 30, 2006 and 2005, respectively. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” on the Condensed Statements of Income.

(c) Deviation from average heating degree days based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for four airports located within our service territory. The 2005 nine-month period degree day statistics have been restated to reflect the current-year, four-location average from the previous single location statistic.

Gas Utility. Weather in Gas Utility’s service territory based upon heating degree days was 8.8% warmer than normal during the 2006 nine-month period and approximately normal in the prior-year nine-month period. Notwithstanding year-over-year growth in the number of our customers, total distribution system throughput decreased 4.8 bcf due to a decrease in sales to retail core-market customers reflecting the warmer weather and price-induced customer conservation, and lower volumes transported for firm and interruptible delivery service customers.

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UGI UTILITIES, INC.

Gas Utility revenues increased $115.7 million during the 2006 nine-month period principally reflecting an $81.9 million increase in retail core-market revenues, the result of higher average PGC rates, and a $33.8 million increase in revenues from low-margin off-system sales. Gas Utility’s cost of gas was $454.5 million in the 2006 nine-month period compared to $338.5 million in the 2005 nine-month period reflecting the impact of the previously mentioned higher retail core-market purchased gas costs and greater costs associated with the higher off-system sales.

Gas Utility total margin in the 2006 nine-month period was comparable to the prior-year nine-month period as the decrease in retail core-market margin resulting from the lower sales was offset by higher total margin from interruptible customers and customer assistance tariff revenues.

Gas Utility operating income decreased $2.2 million in the 2006 nine-month period principally reflecting $0.9 million of increased depreciation and amortization expense, a $0.6 million decrease in other income and a $0.4 million increase in operating and administrative expenses. The increase in operating and administrative expenses reflects increased required environmental remediation reserves and higher uncollectible accounts and customer assistance expenses largely offset by lower 2006 nine-month period stock-based incentive compensation costs and lower distribution system maintenance expenses resulting, in large part, from the mild heating-season weather.

The decrease in Gas Utility income before income taxes reflects the previously mentioned decrease in operating income and an increase in interest expense attributable to higher short-term debt outstanding, largely reflecting the effects of higher natural gas prices, and higher short-term interest rates.

Electric Utility.Electric Utility’s 2006 nine-month period kilowatt-hour sales decreased 0.7% compared to the prior-year period. Electric Utility revenues increased $2.3 million in the 2006 nine-month period largely reflecting higher POLR electric generation rates partially offset by the effects of the lower sales. Electric Utility’s cost of sales increased to $37.7 million in the 2006 nine-month period from $33.5 million in the 2005 nine-month period reflecting higher per unit purchased power costs partially offset by the effects of lower sales.

Electric Utility total margin in the 2006 nine-month period decreased $2.0 million compared to the 2005 nine-month period principally reflecting the higher per unit purchased power costs partially offset by the increase in POLR electric generation rates.

Operating income decreased in the 2006 nine-month period principally reflecting the decrease in total margin partially offset by slightly lower operating and administrative expenses. The decrease in income before income taxes principally reflects the lower operating income and higher interest expense on short-term debt.

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UGI UTILITIES, INC.

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

The Company’s total debt outstanding at June 30, 2006 was $349.1 million (including $112.1 million in bank loans) compared with $318.2 million (including $81.2 million in bank loans) at September 30, 2005. In December 2005, we refinanced $50 million of maturing 7.14% Medium-Term Notes with proceeds from the issuance of $50 million of 5.64% Medium-Term Notes due 2015.

The Company has revolving credit agreements under which it may borrow up to $110 million. These agreements expire in June 2007 through June 2008. From time to time, UGI Utilities makes short-term borrowings under uncommitted arrangements with major banks in order to meet liquidity needs. At June 30, 2006, UGI Utilities had $40 million in short-term borrowings outstanding under such uncommitted arrangements and $72.1 million in borrowings outstanding under the revolving credit agreements. Short-term borrowings, including borrowings under revolving credit agreements, are classified as bank loans on the Condensed Balance Sheets. During the nine months ended June 30, 2006 and 2005, average daily bank loan borrowings were $111.8 million and $50.4 million, respectively, and peak bank loan balances were $175.9 million and $90.4 million, respectively. The increase in average and peak bank loan borrowings during the 2006 nine-month period reflects, in large part, borrowings to fund increased working capital resulting from higher natural gas prices. UGI Utilities expects to increase its revolving credit agreement commitments to $350 million prior to September 30, 2006. The size of the increase takes into account expected working capital requirements of PG Energy (see “UGI’s PG Energy Acquisition” described below). UGI Utilities also has an effective shelf registration statement with the Securities and Exchange Commission under which it may issue up to an additional $75 million of Medium-Term Notes or other debt securities.

Cash Flows

Operating activities.Due to the seasonal nature of UGI Utilities’ businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for 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 short-term borrowings, primarily borrowings under its revolving credit agreements as well as borrowings under uncommitted arrangements, to manage these seasonal cash flow needs.

Cash flow provided by operating activities was $38.1 million for the nine months ended June 30, 2006 compared with cash provided by operating activities of $71.4 million in the prior-year nine-month period. The significant decrease in cash flow from operating activities reflects a $45.3 million decrease in cash flow from changes in operating working capital, principally greater cash required to fund accounts receivable and inventories, a decrease in cash flow as a result of

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UGI UTILITIES, INC.

purchased gas cost undercollections during the period and the refund of $13.5 million in electricity supplier collateral deposits. The greater cash requirements to fund working capital principally reflect the effects of higher natural gas costs in the 2006 nine-month period and higher natural gas storage inventory volumes at the end of the 2006 nine-month period. Cash flow from operating activities before changes in operating working capital was $83.4 million in the 2006 nine-month period compared with $76.1 million for the 2005 nine-month period.

Investing activities.Cash used by investing activities was $35.8 million in the 2006 nine-month period compared to cash used by investing activities of $31.2 million in the 2005 nine-month period. An increase in 2006 nine-month period capital expenditures principally reflects greater information system capital expenditures and greater Electric Utility capital expenditures principally associated with substation improvements.

Financing activities.Cash provided by financing activities was $3.4 million in the 2006 nine-month period compared with cash used by financing activities of $39.5 million in the 2005 nine-month period. Financing activity cash flows are primarily the result of issuances and repayments of long-term debt, net short-term borrowings including borrowings under revolving credit agreements and other uncommitted arrangements, cash dividends to UGI, and capital contributions from UGI. During the 2006 and 2005 nine-month periods, we paid dividends to UGI totaling $27.5 million and $28.1 million, respectively. During the 2006 nine-month period, net bank loan borrowings totaled $30.9 million compared with net bank loan repayments of $11.4 million in the prior-year nine-month period. Included in the 2006 nine-month period net bank loan borrowings are repayments of two $35 million borrowings with maturities greater than three months and a $20 million borrowing made on June 1, 2006, which matures on September 8, 2006. The increase in short-term borrowings in the 2006 nine-month period reflects borrowings needed to finance the higher working capital requirements resulting from the previously mentioned higher natural gas costs. In December 2005, we refinanced $50 million of 7.14% maturing Medium-Term Notes through the issuance of $50 million of 5.64% Medium-Term Notes due in 2015.

UGI’s PG Energy Acquisition

On January 26, 2006, UGI signed a definitive agreement to acquire the natural gas utility assets of PG Energy from Southern Union Company for approximately $580 million in cash, subject to certain adjustments. PG Energy serves approximately 158,000 customers in thirteen counties in northeastern and central Pennsylvania. The proposed transaction is subject to PUC approval and is expected to close during the fourth fiscal quarter ending September 30, 2006. We anticipate that we will acquire and operate, through a subsidiary, the regulated assets of PG Energy immediately following UGI’s completion of the acquisition. We expect to fund the acquisition with a combination of equity and debt.

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UGI UTILITIES, INC.

Recently Issued Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes,” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” We are currently evaluating the impact that this standard will have on our financial position or results of operations. See Note 1 to the Condensed Financial Statements for additional information.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Gas Utility’s tariffs contain clauses that permit recovery of substantially all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for a periodic adjustment 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 our Gas Utility operations. Gas Utility uses exchange-traded natural gas call option contracts to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these call option contracts, net of any associated gains, is included in Gas Utility’s PGC recovery mechanism.

Electric Utility purchases power from wholesale electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market, to provide retail POLR electric generation service to its customers that do not elect to receive such service from alternate suppliers. Currently, the rates it may charge its customers for POLR service are set at or below certain levels established in settlements approved by the PUC. Under a settlement approved in 2004, Electric Utility increased its POLR rates for all metered customers by a total of 4.5% effective January 2005 and an additional 3% effective January 2006, above the total rates in effect on December 31, 2004. In June 2006, the PUC approved a settlement permitting system average increases in maximum POLR rates, on a total bill basis, of 37.8% for 2007, and additional increases of 5.7% and 1.1% for 2008 and 2009, respectively. Wholesale prices for electricity can be volatile, especially during periods of high demand or tight supply. Currently, Electric Utility’s fixed-price power and capacity contracts with electricity suppliers mitigate a substantial portion of its commodity price risk associated with POLR service rate limits in effect through December 31, 2009. With respect to its existing fixed-price power and capacity contracts, should any of the counterparties fail to provide electric power or capacity under the terms of such contracts, any increases in the cost of replacement power or capacity could negatively impact Electric Utility results. In order to reduce the risk associated with non-performance, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. From time to time, Electric Utility enters into electric price swap agreements to reduce the volatility in the cost of a portion of its anticipated electricity requirements.

Our variable-rate debt includes short-term borrowings, including borrowings under our revolving credit agreements. These agreements provide for interest rates on borrowings that are indexed to

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short-term market interest rates. Our long-term debt is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we expect to refinance such debt with new debt having an interest rate that is more or less than the refinanced debt. In order to reduce interest rate risk associated with near-term issuances of fixed-rate debt, we may enter into interest rate protection agreements.

The fair values of our unsettled market risk sensitive derivative instruments reflect the estimated amount that we would expect to receive or pay to terminate the contract based upon quoted market prices of comparable contracts at June 30, 2006. At June 30, 2006, the fair value of our electricity price swap was a gain of $6.7 million. An adverse change in electricity prices of ten percent would result in a $1.4 million decrease in the fair value of the swap. At June 30, 2006, the fair value of our unsettled interest rate protection agreements, which have been designated and qualify as cash flow hedges, was a gain of $1.6 million. An adverse change in interest rates on ten-year U.S. treasury notes of ten percent would result in a $6.0 million decrease in the fair value of these interest rate protection agreements.

ITEM 4. 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.

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PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Charleston, South Carolina Gas Plant Matter. By letter dated July 14, 2006, SCANA Corporation (“SCANA”), demanded contribution from UGI Utilities for a portion of past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. According to the letter, the plant operated from 1855 to 1954. SCANA alleges that UGI Utilities controlled operations of the plant from 1910 to 1926. SCANA asserts that it has spent approximately $22 million in remediation costs and $26 million in third-party claims relating to the site. It estimates that future remediation costs could be as high as $2.5 million and asserts that it has received a demand from the United States Justice Department for natural resource damages. SCANA claims that UGI Utilities is liable for 47% of the costs associated with the site. UGI Utilities is in the process of reviewing the information provided by SCANA and is investigating this claim.

City of Bangor, Maine v. Citizens Communications Co. In April 2003, Citizens Communications Company (“Citizens”) 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 Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18 million to clean up the river. Citizens’ third-party claims have been stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March of 2005 that it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of Maine related to gas plant contaminants at this site. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. The amount of Citizens’ liability has not been finally determined. UGI Utilities believes that it has good defenses to Citizens’ claim and to any claim that the DEP may bring to recover its costs, and is defending the Citizens’ suit.

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend another $11 million 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 million. KeySpan believes that the cost could go as high as $20 million. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.

ITEM 1A. RISK FACTORS

In addition to the other information set forth 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, 2005, 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.

ITEM 6. EXHIBITS

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.1	Description of UGI Corporation Senior Executive Employee Severance Pay Plan, amended July 25, 2006, for Messrs. Trego, Barney, Greenberg, Walsh and Knauss	UGI Corporation	10-Q (8/8/2006)	10.1

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Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.2	Description of July 25, 2006 Amendment to the UGI Corporation Supplemental Executive Retirement Plan for Messrs. Trego, Barney, Greenberg, Walsh and Knauss	UGI Corporation	10-Q (8/8/2006)	10.2
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 June 30, 2006, 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 June 30, 2006, 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 June 30, 2006, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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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: August 7, 2006	By:	/s/ John C. Barney
		John C. Barney Senior Vice President - Finance (Principal Financial Officer)

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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 June 30, 2006, 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 June 30, 2006, 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 June 30, 2006, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.