Ugi Utilities 10-Q 2010 Q3 Quarterly report

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, 2010

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    

Commission file number 1-1398

UGI UTILITIES, INC.

(Exact name of registrant as specified in its charter)

Pennsylvania	23-1174060
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

UGI UTILITIES, INC.
2525 N. 12th Street, Suite 360
Reading, PA
(Address of principal executive offices)
19612
(Zip Code)
(610) 796-3400
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yeso Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero Accelerated filero Non-accelerated filerþ Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yeso Noþ

At July 31, 2010, there were 26,781,785 shares of UGI Utilities, Inc. Common Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI Corporation.

UGI UTILITIES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

	PAGES
Part I Financial Information
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets as of June 30, 2010, September 30, 2009 and June 30, 2009		1
Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2010 and 2009		2
Condensed Consolidated Statements of Cash Flows for the three and nine months ended June 30, 2010 and 2009		3
Notes to Condensed Consolidated Financial Statements		4 - 20
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		21 - 27
Item 3. Quantitative and Qualitative Disclosures about Market Risk		27 - 28
Item 4T. Controls and Procedures		28
Part II Other Information
Item 1. Legal Proceedings		29
Item 1A. Risk Factors		29
Item 6. Exhibits		30
Signatures		31
Exhibit 10.1
Exhibit 10.2
Exhibit 12.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Thousands of dollars)

	June 30,			September 30,			June 30,
	2010			2009			2009
ASSETS
Current assets:
Cash and cash equivalents	$	38,055		$	13,523		$	6,758
Restricted cash		3,639			—			46,485
Accounts receivable (less allowances for doubtful accounts of $17,297, $11,384 and $22,818, respectively)		90,280			74,286			112,992
Accounts receivable — related parties		4,395			3,378			1,698
Accrued utility revenues		9,736			20,980			21,176
Inventories		67,611			196,598			106,250
Deferred income taxes		21,483			24,905			36,330
Regulatory assets		6,316			19,584			28,788
Derivative financial instruments		612			867			1,006
Prepaid expenses & other current assets		18,450			5,167			5,244
Total current assets		260,577			359,288			366,727
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $727,484, $692,082 and $691,592, respectively)		1,369,530			1,364,795			1,352,309
Goodwill		180,145			180,145			176,906
Regulatory assets		135,397			121,960			112,706
Other assets		4,205			4,049			10,008
Total assets	$	1,949,854		$	2,030,237		$	2,018,656
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Bank loans	$	—		$	154,000		$	110,000
Accounts payable		49,500			53,265			42,779
Accounts payable — related parties		6,039			8,746			8,927
Deferred fuel refunds		16,576			30,846			13,512
Derivative financial instruments		828			—			42,473
Other current liabilities		110,360			110,966			140,603
Total current liabilities		183,303			357,823			358,294
Long-term debt		640,000			640,000			640,000
Deferred income taxes		222,568			168,830			152,920
Deferred investment tax credits		5,400			5,670			5,762
Pension and postretirement benefit obligations		143,987			150,499			140,687
Other noncurrent liabilities		70,797			61,372			58,708
Total liabilities		1,266,055			1,384,194			1,356,371
Commitments and contingencies (note 8)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)		60,259			60,259			60,259
Additional paid-in capital		467,571			467,160			466,990
Retained earnings		235,955			201,710			216,991
Accumulated other comprehensive loss		(79,986	)		(83,086	)		(81,955	)
Total common stockholder’s equity		683,799			646,043			662,285
Total liabilities and stockholder’s equity	$	1,949,854		$	2,030,237		$	2,018,656

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues	$	175,021		$	208,300		$	1,014,497		$	1,236,252
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)		98,864			129,533			642,252			862,743
Operating and administrative expenses		40,515			43,633			133,369			151,556
Operating and administrative expenses — related parties		2,792			2,976			10,549			12,114
Taxes other than income taxes		4,167			4,244			13,589			13,870
Depreciation		12,728			12,156			37,847			36,269
Amortization		709			619			2,087			1,580
Other income, net		(1,133	)		(1,304	)		(5,185	)		(6,008	)
		158,642			191,857			834,508			1,072,124
Operating income		16,379			16,443			179,989			164,128
Interest expense		10,481			10,821			31,842			33,010
Income before income taxes		5,898			5,622			148,147			131,118
Income taxes		2,294			2,509			58,768			52,125
Net income	$	3,604		$	3,113		$	89,379		$	78,993

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Thousands of dollars)

	Nine Months Ended
	June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	89,379		$	78,993
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		39,934			37,849
Deferred income taxes, net		49,532			(9,805	)
Provision for uncollectible accounts		13,273			20,747
Other, net		11,330			11,408
Net change in:
Accounts receivable and accrued utility revenues		(19,040	)		(46,404	)
Inventories		128,987			77,606
Deferred fuel and power costs		(1,002	)		40,214
Accounts payable		(6,472	)		(29,742	)
Storage agreements security deposits		3,500			19,000
Other current assets		(13,029	)		(1,281	)
Other current liabilities		(12,755	)		26,685
Net cash provided by operating activities		283,637			225,270
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(44,484	)		(56,068	)
Net costs of property, plant and equipment disposals		(1,848	)		(1,866	)
Acquisition of CPG, net of cash acquired		—			(298,671	)
Proceeds from sale of CPG propane business assets		—			32,269
Increase in restricted cash		(3,639	)		(12,448	)
Net cash used by investing activities		(49,971	)		(336,784	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends		(55,134	)		(46,211	)
Issuance of long-term debt		—			108,000
(Decrease) increase in bank loans		(154,000	)		53,000
Net cash (used) provided by financing activities		(209,134	)		114,789
Cash and cash equivalents increase	$	24,532		$	3,275
CASH AND CASH EQUIVALENTS:
End of period	$	38,055		$	6,758
Beginning of period		13,523			3,483
Increase	$	24,532		$	3,275

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

1. Nature of Operations

UGI Utilities, Inc., a wholly owned subsidiary of UGI Corporation (“UGI”), and its wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”) own and operate natural gas distribution utilities primarily located 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;” PNG’s natural gas distribution utility is referred to herein as “PNG Gas;” and CPG’s natural gas distribution utility is referred to herein as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas are collectively referred to as “Gas Utility.” PNG also has a heating, ventilation and air-conditioning service business (“UGI Penn HVAC Services, Inc.”) which operates principally in the PNG Gas service territory.

Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. 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.

2. Significant Accounting Policies

Basis of Presentation.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, 2009 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, 2009 (“Company’s 2009 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, 2010 and 2009:

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Net income	$	3,604	$	3,113	$	89,379	$	78,993
Other comprehensive income (loss)		1,034		170		3,100		(38,177	)
Comprehensive income	$	4,638	$	3,283	$	92,479	$	40,816

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Other comprehensive income (loss) includes reclassifications of losses on interest rate protection agreements and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income. On December 31, 2008, we merged two of our defined benefit pension plans that we sponsored. As a result of the merger, at December 31, 2008, the Company was required under GAAP to remeasure the combined plan’s assets and obligations and record the funded status in our Condensed Consolidated Balance Sheet. The associated after-tax charge to other comprehensive loss of $38,688 is included in the table above for the nine months ended June 30, 2009.

Restricted Cash.Restricted cash represents those cash balances in our futures brokerage accounts which are restricted from withdrawal.

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 2009 and December 2008 the Company reduced its unrecognized tax benefits. The reductions decreased income tax expense for the nine months ended June 30, 2010 and 2009 by $290 and $490, respectively.

The Company received Internal Revenue Service (“IRS”) consent to change its tax method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. The filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30,200 which has been, or will be, used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 stand alone Pennsylvania income tax return also produced an approximate $43,400 state net operating loss (“NOL”) carryforward, resulting in a net deferred tax benefit of approximately $2,800.

Under current Pennsylvania state income tax law, the NOL stated above can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded.

The Company’s determination of what constitutes a capital cost versus ordinary expense as it relates to the new tax method will likely be reviewed upon audit by the IRS and may be subject to subsequent adjustment. Accordingly, the status of this tax return position is uncertain at this time. In accordance with accounting guidance regarding uncertain tax positions, the Company has added $3,927 to its liability for unrecognized tax benefits related to this tax method. However, because this tax matter relates only to the timing of tax deductibility, we have recorded an offsetting deferred tax asset of an equal amount.

The previously discussed change in tax method did not affect the Company’s net income (loss) for any periods presented. For further information regarding the regulatory impact of this change, see Note 6.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

3. Accounting Changes

Adoption of New Accounting Standards

Intangible Asset Useful Lives.Effective October 1, 2009, we adopted new accounting guidance which 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 GAAP. The intent of the new guidance is to improve the consistency between the useful life of a recognized intangible asset under GAAP relating to intangible asset accounting and the period of expected cash flows used to measure the fair value of the asset under GAAP relating to business combinations and other applicable accounting literature. The new guidance must be applied prospectively to intangible assets acquired after the effective date. The adoption of the new guidance did not impact our financial statements.

Business Combinations.Effective October 1, 2009, we adopted new guidance on accounting for business combinations. The new guidance applies to all transactions or other events in which an entity obtains control of one or more businesses. The new guidance 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. The new guidance applies prospectively to business combinations for which the acquisition date is on or after October 1, 2009. Among the more significant changes in accounting for acquisitions are (1) transaction costs are generally expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, are generally 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 are recognized in operations (rather than as decreases in goodwill). The new guidance did not have an impact on our financial statements.

Fair Value Measurements.In January 2010, the Financial Accounting Standards Board (“FASB”) issued new guidance with respect to fair value measurements disclosures. The new guidance requires additional disclosure related to transfers between Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements related to Level 3. The new guidance clarifies existing disclosure guidance about inputs and valuation techniques for fair value measurements and levels of disaggregation. We apply fair value measurements to certain assets and liabilities, principally commodity and interest rate derivative instruments. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009 except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2009 (Fiscal 2011) and interim periods thereafter. The adoption of the new guidance that became effective during Fiscal 2010 did not have a material effect on our disclosures.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

New Accounting Standards Not Yet Adopted

Enhanced Disclosures of Postretirement Plan Assets.In December 2008, the FASB issued new guidance requiring more detailed disclosures about employers’ postretirement 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 annual disclosure guidance are effective for fiscal years ending after December 15, 2009 (Fiscal 2010). Because this new guidance relates to disclosure only, it will not impact the financial statements.

4. 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 2009 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.

UGI Penn HVAC Services, Inc. does not meet the quantitative thresholds for separate business segment reporting under GAAP and has been included in “Other.”

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Financial information by business segment follows:

Three Months Ended June 30, 2010:

			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	175,021	$	149,043	$	25,377	$	601
Cost of sales	$	98,864	$	83,050	$	15,814	$	—
Depreciation and amortization	$	13,437	$	12,445	$	992	$	—
Operating income (loss)	$	16,379	$	13,733	$	2,666	$	(20	)
Interest expense	$	10,481	$	9,994	$	487	$	—
Income (loss) before income taxes	$	5,898	$	3,739	$	2,179	$	(20	)
Total assets (at period end)	$	1,949,854	$	1,829,427	$	120,427	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	18,314	$	16,043	$	2,271	$	—

Three Months Ended June 30, 2009:

			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	208,300	$	176,937	$	30,741	$	622
Cost 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	$	122
Interest expense	$	10,821	$	10,379	$	442	$	—
Income before income taxes	$	5,622	$	2,569	$	2,931	$	122
Total assets (at period end)	$	2,018,656	$	1,900,874	$	116,155	$	1,627
Goodwill (at period end)	$	176,906	$	176,906	$	—	$	—
Capital expenditures	$	19,237	$	18,146	$	1,091	$	—

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Nine Months Ended June 30, 2010:

			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	1,014,497	$	922,247	$	90,929	$	1,321
Cost of sales	$	642,252	$	584,243	$	58,009	$	—
Depreciation and amortization	$	39,934	$	36,960	$	2,974	$	—
Operating income	$	179,989	$	168,573	$	11,118	$	298
Interest expense	$	31,842	$	30,498	$	1,344	$	—
Income before income taxes	$	148,147	$	138,075	$	9,774	$	298
Total assets (at period end)	$	1,949,854	$	1,829,427	$	120,427	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	44,484	$	40,582	$	3,902	$	—

Nine Months Ended June 30, 2009:

			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	1,236,252	$	1,130,099	$	104,780	$	1,373
Cost 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	$	443
Interest expense	$	33,010	$	31,731	$	1,279	$	—
Income before income taxes	$	131,118	$	118,117	$	12,558	$	443
Total assets (at period end)	$	2,018,656	$	1,900,874	$	116,155	$	1,627
Goodwill (at period end)	$	176,906	$	176,906	$	—	$	—
Capital expenditures	$	56,068	$	52,530	$	3,538	$	—

5. Inventories

Inventories comprise the following:

	June 30,		September 30,		June 30,
	2010		2009		2009
Gas Utility natural gas	$	60,272	$	189,747	$	99,012
Materials, supplies and other		7,339		6,851		7,238
Total inventories	$	67,611	$	196,598	$	106,250

From time to time UGI Utilities enters into storage contract administrative agreements (“SCAAs”) pursuant to which it has, among other things, released certain storage and transportation contracts for the terms of the storage agreements. At June 30, 2010, UGI Utilities had three SCAAs, one that is scheduled to expire in October 2010 and two that are scheduled to expire in October 2012 (see Note 9).

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Pursuant to the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs.

The historical cost of natural gas storage inventories released under 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) are included in the caption “Gas Utility natural gas” in the table above. The carrying value of gas storage inventories released under these agreements at June 30, 2010, September 30, 2009 and June 30, 2009, comprising 6.4 billion cubic feet (“bcf”), 9.0 bcf, and 5.0 bcf of natural gas, was $35,322, $77,948 and $43,683, respectively. In conjunction with the SCAAs, at June 30, 2010, September 30, 2009 and June 30, 2009, UGI Utilities held a total of $22,500, $19,000 and $19,000, respectively, of security deposits received from its SCAAs’ counterparties which amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets.

6. Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 5 to the Company’s 2009 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,
	2010		2009		2009
Regulatory assets:
Income taxes recoverable	$	95,334	$	79,492	$	76,645
Postretirement benefits		1,688		2,473		3,017
Recoverable costs — CPG Gas postretirement benefit plans		8,572		8,572		5,545
Environmental costs		24,328		26,877		20,583
Deferred fuel and power costs		6,316		19,584		28,788
Other		5,475		4,546		6,916
Total regulatory assets	$	141,713	$	141,544	$	141,494
Regulatory liabilities:
Postretirement benefits	$	10,261	$	9,310	$	9,971
Environmental overcollections		8,354		8,720		9,724
Deferred fuel refunds		16,576		30,846		13,512
State tax benefits — distribution system repairs		10,983		—		—
Total regulatory liabilities	$	46,174	$	48,876	$	33,207

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Deferred fuel and power — costs and refunds.Gas Utility’s tariffs and, commencing January 1, 2010 Electric Utility’s default service tariffs, contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) rates in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Unrealized losses on such contracts at June 30, 2010 and June 30, 2009 were $(558) and $(42,473), respectively. There were no such unrealized gains or losses at September 30, 2009.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its default service costs commencing January 1, 2010 through DS rates, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power — costs or refunds. Unrealized gains on FTRs at June 30, 2010 were not material.

State Income Tax Benefits – Distribution System Repairs.As previously mentioned in Note 2 to condensed consolidated financial statements, the Company received IRS consent to change its tax method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of these repairs and maintenance expenses which expenses are capitalized for regulatory and GAAP reporting purposes. The state tax benefits associated with these repairs and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.

7. Defined Benefit Pension and Other Postretirement Plans

We currently sponsor two defined benefit pension plans (“Pension Plans”) for employees hired prior to January 1, 2009 of UGI Utilities, PNG, CPG, UGI and certain of UGI’s other wholly owned domestic subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and a limited number of active employees, and postretirement life insurance benefits to nearly all active and retired employees.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Net periodic pension expense and other postretirement benefit costs relating to our employees include the following components:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Service cost	$	1,745		$	1,321		$	40		$	33
Interest cost		5,284			3,813			212			211
Expected return on assets		(5,858	)		(4,262	)		(126	)		(130	)
Amortization of:
Prior service cost (benefit)		9			6			(102	)		(87	)
Actuarial loss		1,333			950			89			30
Net benefit cost		2,513			1,828			113			57
Change in associated regulatory liabilities		—			—			736			803
Net expense	$	2,513		$	1,828		$	849		$	860

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Service cost	$	5,235		$	3,741		$	121		$	99
Interest cost		15,852			11,532			635			633
Expected return on assets		(17,575	)		(12,994	)		(378	)		(391	)
Amortization of:
Prior service cost (benefit)		27			19			(305	)		(260	)
Actuarial loss		3,999			2,089			268			89
Net benefit cost		7,538			4,387			341			170
Change in associated regulatory liabilities		—			—			2,208			2,410
Net expense	$	7,538		$	4,387		$	2,549		$	2,580

Pension Plans’ assets are held in trust and consist principally of equity and fixed income mutual funds. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $9,500 to the Pension Plans during the next twelve months. 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 GAAP 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, 2010, nor are they expected to be material for all of Fiscal 2010.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

We also sponsor an unfunded and non-qualified defined benefit supplemental executive retirement plan. Net benefit costs associated with this plan for all periods presented were not material.

8. 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. At June 30, 2010, neither UGI Gas’ undiscounted nor its accrued liability for environmental investigation and cleanup costs was material.

UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating three claims against it relating to out-of-state sites.

Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.

South Carolina Electric & Gas Company v. UGI Utilities, Inc.On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserts that it has spent approximately $22,000 in remediation costs and paid $26,000 in third-party claims relating to the site and estimates that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14,000. Trial took place in March 2009 and the court’s decision is pending.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

Frontier Communications Company v. UGI Utilities, Inc. et al.In April 2003, Citizens Communications Company, now known as Frontier Communications Company (“Frontier”), served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of any costs Frontier would be required to pay to the City for cleaning up tar deposits in the Penobscot River. Frontier alleged that through ownership and control of a subsidiary, Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Frontier made similar allegations of control against another third-party defendant, CenterPoint Energy Resources Corporation (“CenterPoint”), whose predecessor owned the Bangor subsidiary from 1928 to 1944. Frontier’s third-party claims were stayed pending a resolution of the City’s suit against Frontier, which was tried in September 2005. On June 27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup costs, which were estimated at $18,000. On February 14, 2007, Frontier and the City entered into a settlement agreement pursuant to which Frontier agreed to pay $7,600. Frontier subsequently filed the current action against the original third-party defendants, repeating its claims for contribution. On September 22, 2009, the court granted summary judgment in favor of co-defendant CenterPoint. UGI Utilities believes that it also has good defenses and has filed a motion for summary judgment with respect to 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.

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

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

approximately $215,000 and asserted that UGI Utilities is responsible for approximately $103,000 of this amount. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites, Waterbury North, pursuant to a lease. In April 2009, the court conducted a trial to determine whether UGI Utilities operated any of the nine remaining sites that were owned and operated by former subsidiaries. On May 22, 2009, the court granted judgment in favor of UGI Utilities with respect to all nine sites. The Northeast Companies are expected to complete additional environmental investigations at Waterbury North by the end of 2010, after which there will be a second phase of the trial to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25,000.

We cannot predict with certainty the final results of any of the environmental claims or legal actions described above. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. While the results of these other pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, the final outcome of such other matters will not have a significant effect on our consolidated financial position, results of operations or cash flows.

9. Related Party Transactions

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

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

From time to time, UGI Utilities is a party to SCAAs with UGI Energy Services, Inc., a second-tier wholly owned subsidiary of UGI (“Energy Services”). At June 30, 2010, UGI Utilities was a party to a three-year SCAA with Energy Services expiring October 31, 2012 and, during the periods covered by the financial statements, was a party to other one-year SCAAs with Energy Services. Under all of the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $6,783 and $14,362 during the three and nine months ended June 30, 2010, respectively, and $18,144 and $38,005 during the three and nine months ended June 30, 2009, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amount of such security deposits, which amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets, was $7,500, $15,000 and $15,000 as of June 30, 2010, September 30, 2009 and June 30, 2009, respectively.

The volumes and carrying amounts of gas storage inventories released under Energy Services’ SCAAs at June 30, 2010, September 30, 2009 and June 30, 2009 are as follows: at June 30, 2010, gas storage inventories comprising approximately 2.2 bcf of natural gas totaling $12,140; at September 30, 2009, gas storage inventories comprising approximately 7.7 bcf of natural gas totaling $67,436; and at June 30, 2009, gas storage inventories comprising approximately 4.2 bcf of natural gas totaling $36,951.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the months of November through March. In addition, from time to time, Gas Utility purchases natural gas or pipeline capacity from Energy Services. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three and nine months ended June 30, 2010 totaled $3,905 and $25,941, respectively. During the nine months ended June 30, 2009, such transactions totaled $23,064.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2010, revenues associated with such sales to Energy Services totaled $15,489 and $43,074, respectively. During the three and nine months ended June 30, 2009, such revenues totaled $3,625 and $24,438, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to the transactions already described above). During the three and nine months ended June 30, 2010, the aggregate amount of such purchases totaled $7,145 and $22,034, respectively. During the three and nine months ended June 30, 2009, such transactions totaled $2,409 and $12,549, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

10. Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of June 30, 2010, September 30, 2009 and June 30, 2009:

	Quoted
	Prices in
	Active
	Markets for			Significant
	Identical			Other
	Assets and			Observable		Unobservable
	Liabilities			Inputs		Inputs
	(Level 1)			(Level 2)		(Level 3)		Total
June 30, 2010:
Derivative financial instruments:
Assets	$	315		$	297	$	—	$	612
Liabilities	$	(828	)	$	—	$	—	$	(828	)
September 30, 2009:
Derivative financial instruments:
Assets	$	102		$	765	$	—	$	867
Liabilities	$	—		$	—	$	—	$	—
June 30, 2009:
Derivative financial instruments:
Assets	$	4		$	1,002	$	—	$	1,006
Liabilities	$	(42,473	)	$	—	$	—	$	(42,473	)

The fair values of our Level 1 exchange-traded derivative contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments, which are designated as Level 2, are generally based upon recent market transactions and related market indicators.

Other Financial Instruments

The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at June 30, 2010 were $640,000 and $734,356, respectively. The carrying amount and estimated fair value of our long-term debt at June 30, 2009 were $640,000 and $657,832, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

11. Disclosures About Derivative Instruments, Hedging Activities and Financial Instruments

We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations.

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states.

At June 30, 2010 and 2009, the volume of natural gas associated with our unsettled NYMEX natural gas futures contracts totaled 11.3 million dekatherms and 8.2 million dekatherms, respectively. The volume of transmission congestion that is subject to FTRs at June 30, 2010 and 2009 totaled 739.3 million kilowatt-hours and 1,277.0 million kilowatt-hours, respectively.

With respect to natural gas futures and option contracts associated with Gas Utility, gains and losses on unsettled natural gas futures contracts and gains on natural gas option contracts are recorded in deferred fuel costs on the Condensed Consolidated Balance Sheets in accordance with the FASB’s guidance in Accounting Standards Codification (“ASC”) 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism. 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, gains and losses on FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets and liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 6). Gains and losses associated with periods prior to January 1, 2010 are reflected in cost of sales.

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. The volumes of gasoline under these contracts were not material for all periods presented.

Interest Rate Risk

Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in accumulated other comprehensive income (“AOCI”), to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At June 30, 2010 there were no unsettled IRPA contracts outstanding. The amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $1,165.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts are guaranteed by the NYMEX and have limited credit risk. These contracts generally require cash deposits in margin accounts. At June 30, 2010 and 2009, Gas Utility’s restricted cash in brokerage accounts totaled $3,639 and $46,485, respectively. We generally do not have credit-risk-related contingent features in our derivative contracts.

The following table provides information regarding the balance sheet location and fair values of derivative assets and liabilities existing as of June 30, 2010 and 2009:

As of June 30:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2010		2009		Location	2010			2009
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	$	287	$	—	Derivative financial instruments	$	(828	)	$	(42,473	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments		325		1,006
Total Derivatives		$	612	$	1,006		$	(828	)	$	(42,473	)

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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)

During the three and nine months ended June 30, 2010 and 2009, the amount of IRPA net losses included in AOCI that were reclassified into net income, and the impact on net income from changes in the fair value of FTRs not accounted for under ASC 980 and gasoline futures and swap contracts, were not material.

We are also a party to a number of contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sale exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

Information contained in this 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) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability for environmental claims; (8) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor relations; (10) large customer, counterparty or supplier defaults; (11) increased uncollectible accounts expense; (12) liability for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas, including liability in excess of insurance coverage; (13) political, regulatory and economic conditions in the United States; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity market prices resulting in significantly higher cash collateral requirements.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on our businesses, financial condition or future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended June 30, 2010 (“2010 three-month period”) with the three months ended June 30, 2009 (“2009 three-month period”) and the nine months ended June 30, 2010 (“2010 nine-month period”) with the nine months ended June 30, 2009 (“2009 nine-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 4 to the condensed consolidated financial statements.

2010 three-month period compared with 2009 three-month period

							Increase
Three Months Ended June 30,	2010			2009			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	149.0		$	176.9		$	(27.9	)	(15.8	)%
Total margin (a)	$	66.0		$	67.1		$	(1.1	)	(1.6	)%
Operating income	$	13.7		$	12.9		$	0.8		6.2	%
Income before income taxes	$	3.7		$	2.6		$	1.1		42.3	%
System throughput — bcf		28.0			25.8			2.2		8.5	%
Heating degree days — % (warmer) than normal (b)		(26.4	)%		(6.5	)%		—		—
Electric Utility:
Revenues	$	25.4		$	30.7		$	(5.3	)	(17.3	)%
Total margin (a)	$	8.1		$	9.4		$	(1.3	)	(13.8	)%
Operating income	$	2.7		$	3.4		$	(0.7	)	(20.6	)%
Income before income taxes	$	2.2		$	2.9		$	(0.7	)	(24.1	)%
Distribution sales — gwh		218.6			209.8			8.8		4.2	%

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 $1.4 million and $1.7 million during the three-month periods ended June 30, 2010 and 2009, respectively. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” in the Condensed Consolidated Statements of Income.
(b)	Deviation from average heating degree days for the 15-year period 1990-2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Gas Utility. Temperatures in the Gas Utility service territory based upon heating degree days were 26.4% warmer than normal in the 2010 three-month period compared with temperatures that were 6.5% warmer than normal in the prior-year period. Total distribution system throughput increased 2.2 bcf in the 2010 three-month period principally due to greater delivery service volumes including certain low margin interruptible delivery service volumes. The increase in delivery service volumes was partially offset by a decline in volumes sold and transported to Gas Utility’s core-market customers resulting in large part from the warmer spring weather. Gas Utility’s core-market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Gas Utility revenues decreased $27.9 million during the 2010 three-month period principally reflecting a decline in revenues from retail core-market customers partially offset by a $6.1 million increase in low-margin off-system sales. The decrease in retail core-market revenues principally resulted from lower retail core-market volumes sold and lower average purchased gas cost (“PGC”) rates partially offset by the effects of the PNG Gas and CPG Gas base operating revenue increases that became effective August 28, 2009. Under Gas Utility’s PGC recovery mechanisms, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $83.1 million in the 2010 three-month period compared with $109.8 million in the prior-year period principally reflecting the lower average PGC rates and, to a much lesser extent, the lower retail core-market sales.

Notwithstanding the PNG Gas and CPG Gas base rate increases, Gas Utility total margin decreased $1.1 million in the 2010 three-month period. The decrease reflects the impact of the previously mentioned decline in retail core-market volumes.

Gas Utility operating income during the 2010 three-month period increased $0.8 million principally reflecting lower operating and administrative costs partially offset by the previously mentioned decrease in total margin. The 2010 three-month period operating and administrative costs include, among other things, lower customer accounts-related expenses and lower costs associated with environmental matters. The $1.1 million increase in income before income taxes reflects the previously mentioned higher operating income and slightly lower interest expense on lower bank loan borrowings.

Electric Utility. Electric Utility’s kilowatt-hour sales in the 2010 three-month period were 4.2% higher than in the prior year. The increase in sales reflects the effects of warmer late spring and early summer 2010 three-month period weather on air-conditioning-related sales volumes. Electric Utility revenues decreased $5.3 million principally as a result of lower default service (“DS”) rates which became effective January 1, 2010. Electric Utility decreased its DS rates effective January 1, 2010 pursuant to a January 22, 2009 settlement of its DS rate filing with the PUC. This reduced average costs to a residential general and residential heating customer by nearly 10% and 4%, respectively, over such costs in Fiscal 2009 and also reduced rates to commercial and industrial customers. Under DS rates, Electric Utility is no longer subject to electricity price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under previous Provider of Last Resort (“POLR”) rates in effect prior to January 1, 2010. Electric Utility cost of sales declined to $15.8 million in the 2010 three-month period compared to $19.7 million in the 2009 three-month period principally reflecting lower purchased power costs.

Electric Utility total margin declined $1.3 million in the 2010 three-month period reflecting the reduction in margin resulting from implementation of lower DS rates effective January 1, 2010.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Electric Utility operating income and income before income taxes in the 2010 three-month period were both $0.7 million lower principally reflecting the previously mentioned lower total margin partially offset by slightly lower operating and administrative costs.

2010 nine-month period compared with 2009 nine-month period

							Increase
Nine Months Ended June 30,	2010			2009			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	922.2		$	1,130.1		$	(207.9	)	(18.4	)%
Total margin (a)	$	338.0		$	334.4		$	3.6		1.1	%
Operating income	$	168.6		$	149.8		$	18.8		12.6	%
Income before income taxes	$	138.1		$	118.1		$	20.0		16.9	%
System throughput — bcf		124.9			126.4			(1.5	)	(1.2	)%
Heating degree days — % (warmer) colder than normal (b)		(4.5	)%		3.9	%		—		—
Electric Utility:
Revenues	$	90.9		$	104.8		$	(13.9	)	(13.3	)%
Total margin (a)	$	27.9		$	32.0		$	(4.1	)	(12.8	)%
Operating income	$	11.1		$	13.8		$	(2.7	)	(19.6	)%
Income before income taxes	$	9.8		$	12.6		$	(2.8	)	(22.2	)%
Distribution sales — gwh		723.8			735.8			(12.0	)	(1.6	)%

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 $5.0 million and $5.7 million during the nine-month periods ended June 30, 2010 and 2009, respectively. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” in the Condensed Consolidated Statements of Income.
(b)	Deviation from average heating degree days for the 15-year period 1990-2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Gas Utility. Temperatures in the Gas Utility service territory based upon heating degree days were 4.5% warmer than normal in the 2010 nine-month period compared with temperatures that were 3.9% colder than normal in the prior-year period. Total distribution system throughput decreased 1.5 bcf in the 2010 nine-month period principally reflecting the effects of the warmer weather on core-market customers, the lingering effects of the economic recession and customer conservation partially offset by an increase in delivery service volumes, principally low margin interruptible volumes.

Gas Utility revenues decreased $207.9 million during the 2010 nine-month period principally reflecting a decline in revenues from retail core-market customers. The decrease in retail core-market revenues principally resulted from the lower retail core-market volumes and lower average PGC rates partially offset by the effects of the PNG Gas and CPG Gas base operating revenue increases that became effective August 28, 2009. Gas Utility’s cost of gas was $584.2 million in the 2010 nine-month period compared with $795.7 million in the prior-year period principally reflecting the lower retail core-market sales and the lower average PGC rates.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notwithstanding the decrease in distribution system volumes, Gas Utility total margin increased $3.6 million in the 2010 nine-month period. The increase is principally the result of the PNG Gas and CPG Gas base operating revenue increases partially offset by the effect on margin from the lower core-market volumes.

Gas Utility operating income during the 2010 nine-month period increased $18.8 million principally reflecting lower operating and administrative costs and the previously mentioned increase in total margin. The 2010 nine-month period operating and administrative costs include, among other things, lower charges associated with environmental matters, lower provisions for uncollectible accounts and lower UGI corporate allocated expenses. These decreases in operating and administrative expenses were partially offset by higher 2010 nine-month period pension expense. The increase in income before income taxes reflects the previously mentioned higher operating income and lower interest expense due to lower average bank loan borrowings.

Electric Utility. Temperatures based upon heating degree days were approximately 5.9% warmer than in the prior-year period. Electric Utility’s kilowatt-hour sales in the 2010 nine-month period were 1.6% lower than in the prior year. The decline in sales principally reflects the effects of the warmer 2010 nine-month period weather on heating-related sales volumes and the lingering effects of the economic recession. These decreases were partially offset by higher air-conditioning sales on warmer late spring and early 2010 summer weather. Electric Utility revenues decreased $13.9 million principally as a result of the previously mentioned lower DS rates effective January 1, 2010 and the lower sales. Electric Utility cost of sales declined to $58.0 million in the 2010 nine-month period compared to $67.1 million in the 2009 nine-month period principally reflecting lower purchased power costs and the effects of the lower sales.

Electric Utility total margin declined $4.1 million in the 2010 nine-month period reflecting the reduction in margin resulting from the implementation of lower DS rates effective January 1, 2010 and, to a much lesser extent, the effects of the lower 2010 nine-month period sales.

Electric Utility operating income and income before income taxes in the 2010 nine-month period declined $2.7 million and $2.8 million, respectively, reflecting the lower total margin partially offset by lower operating and administrative expenses.

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

The Company’s total debt outstanding at June 30, 2010 was $640 million compared to total debt outstanding of $794 million at September 30, 2009. The decrease in total debt reflects a decrease in bank loan borrowings.

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UGI UTILITIES, INC. AND SUBSIDIARIES

UGI Utilities has a $350 million Revolving Credit Agreement which expires in August 2011. At June 30, 2010 there were no amounts outstanding under the Revolving Credit Agreement. At September 30, 2009, UGI Utilities had $178 million of borrowings outstanding under its Revolving Credit Agreement. Borrowings under the Revolving Credit Agreement are classified as bank loans on the Condensed Consolidated Balance Sheets. During the nine months ended June 30, 2010 and 2009, average daily bank loan borrowings were $93.1 million and $239.8 million, respectively, and peak bank loan borrowings totaled $203 million and $312 million, respectively. Peak bank loan borrowings typically occur during the peak heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is greatest. Revolving Credit Agreement borrowings were higher in the prior-year period due in large part to higher margin deposits associated with natural gas futures accounts as a result of declines in wholesale natural gas prices.

Income Taxes – Change in Tax Accounting for Utility Repairs and Maintenance Expenses.The Company received Internal Revenue Service (“IRS”) consent to change its tax method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. The filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30.2 million which has been, or will be, used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 stand alone Pennsylvania income tax return also produced an approximate $43.4 million state net operating loss (“NOL”) carryforward, resulting in a net deferred tax benefit of approximately $2.8 million.

Under current Pennsylvania state income tax law, the NOL stated above can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded. The change in tax method did not affect the Company’s net income (loss) for any periods presented. For further information, See Note 2 to condensed consolidated financial statements.

Cash Flows

Operating activities. Due to the seasonal nature of UGI Utilities’ businesses, cash flows from our operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas and electricity consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally accounts receivable and inventories, is generally greatest. UGI Utilities uses borrowings under its Revolving Credit Agreement to manage seasonal cash flow needs.

Cash flow provided by operating activities was $283.6 million in the 2010 nine-month period compared to $225.3 million in the prior-year nine-month period. Cash flow from operating activities before changes in operating working capital increased to $203.4 million in the 2010 nine-month period from $139.2 million in the prior-year nine-month period. The increase principally reflects higher net income and greater noncash charges for deferred income taxes. Changes in operating working capital provided $80.2 million of operating cash flow during the 2010 nine-month period compared with $86.1 million provided during the prior-year nine-month period.

Investing activities. Cash used by investing activities was $50.0 million in the 2010 nine-month period compared to $336.8 million in the 2009 nine-month period. The 2009 nine-month period reflects net cash paid in conjunction with the acquisition of CPG (“CPG Acquisition”) of $298.7 million less $32.3 million of net cash received from the sale of the propane assets of a CPG subsidiary to AmeriGas Propane, L.P., an affiliate of UGI. In addition, changes in restricted cash associated with our commodity futures brokerage accounts required $3.6 million of cash in the 2010 nine-month period compared with $12.4 million of such cash required in the prior-year period. Capital expenditures were lower in the 2010 nine-month period due in large part to lower 2010 nine-month period Gas Utility growth capital expenditures.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Financing activities.Cash used by financing activities was $209.1 million in the 2010 nine-month period compared with cash provided by financing activities of $114.8 million in the 2009 nine-month period. Financing activity cash flows are primarily the result of issuances and repayments of long-term debt, net borrowings and repayments under our Revolving Credit Agreement, cash dividends paid to UGI, and capital contributions from UGI. We paid cash dividends to UGI totaling $55.1 million and $46.2 million during the 2010 and 2009 nine-month periods, respectively. During the 2010 nine-month period, net bank loan repayments totaled $154 million compared with net bank loan borrowings of $53 million in the prior-year nine-month period. The higher net cash from bank loan borrowings in the prior-year nine-month period was due in large part to the timing and use of cash contributions made by UGI on September 25, 2008 to fund the CPG Acquisition on October 1, 2008. A $120 million cash contribution made by UGI on September 25, 2008 was temporarily used by UGI Utilities in September 2008 to reduce bank loan borrowings. This amount was then reborrowed on October 1, 2008, along with additional bank loan borrowings, to fund a portion of the CPG Acquisition. During the 2009 nine-month period, UGI Utilities issued $108 million of 6.375% Senior Notes due 2013 the proceeds of which were used to fund a portion of the CPG Acquisition. There were no long-term debt transactions during the 2010 nine-month period.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The fair value of natural gas futures contracts at June 30, 2010 was a loss of $0.6 million. The cost of natural gas derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At June 30, 2010 Gas Utility had $3.6 million of restricted cash associated with natural gas and other futures accounts with brokers.

Beginning January 1, 2010, Electric Utility’s default service tariffs contain clauses which permit recovery of all prudently incurred power costs through the application of DS rates. The clauses provide for periodic adjustments to DS rates for differences between the total amount of power costs collected from customers and recoverable power costs incurred. Because of this ratemaking mechanism, beginning January 1, 2010 there is limited power cost risk, including the cost of financial transmission rights (“FTRs”), associated with our Electric Utility operations. Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, through purchases at monthly PJM auctions. FTRs are financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electricity transmission grid. 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, 2010, the fair value of FTRs was a gain of $0.3 million.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at June 30, 2010 were not material.

Our variable-rate debt comprises borrowings under our Revolving Credit Agreement. This agreement provides for interest rates on borrowings that are indexed to 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 interest rates reflecting then-current market conditions. In order to reduce interest rate risk associated with near or medium term issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements. There were no unsettled interest rate protection agreements outstanding as of June 30, 2010.

Our unsettled derivative instruments at June 30, 2010 comprise (1) Gas Utility’s exchange-traded natural gas futures and options contracts, which are included in Gas Utility’s PGC recovery mechanism; (2) Electric Utility’s FTRs, which are included in Electric Utility’s GS recovery mechanism; and (3) exchange-traded gasoline futures and swap contracts.

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.

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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. 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 million and asserted that UGI Utilities is responsible for approximately $103 million of this amount. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites, Waterbury North, pursuant to a lease. In April 2009, the court conducted a trial to determine whether UGI Utilities operated any of the nine remaining sites that were owned and operated by former subsidiaries. On May 22, 2009, the court granted judgment in favor of UGI Utilities with respect to all nine sites. The Northeast Companies are expected to complete additional environmental investigations at Waterbury North by the end of 2010, after which there will be a second phase of the trial to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25 million.

ITEM 1A. RISK FACTORS

In addition to the other information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2009, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ITEM 6. EXHIBITS

The exhibits filed as part of this report are as follows (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):

Incorporation by Reference

Exhibit
No.	Exhibit	Registrant	Filing	Exhibit
10.1	Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, Inc. effective as of May 1, 2007
10.2	SST Service Agreement No. 79133 dated November 1, 2004 between Columbia Gas Transmission Corporation and UGI Utilities, Inc.
10.3	UGI Corporation 2009 Deferral Plan as Amended and Restated Effective June 1, 2010	UGI	Form 10-Q (6/30/10)		10.1
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, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2010, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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UGI UTILITIES, INC. AND SUBSIDIARIES

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	UGI Utilities, Inc. (Registrant)
Date: August 6, 2010	By:	/s/ Donald E. Brown
		Donald E. Brown
		Vice President — Finance and Chief Financial Officer

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UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX

10.1	Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, Inc. effective as of May 1, 2007
10.2	SST Service Agreement No. 79133 dated November 1, 2004 between Columbia Gas Transmission Corporation and UGI Utilities, Inc.
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, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2010, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002