Ugi Utilities 10Q 2011 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, 2011


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 29, 2011, there were 26,781,785 shares of UGI Utilities, Inc. Common Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI Corporation.

UGI UTILITIES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS


	PAGES

Part I Financial Information

Item 1. Financial Statements (unaudited)

Condensed Consolidated Balance Sheets as of June 30, 2011, September 30, 2010 and June 30, 2010		1

Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2011 and 2010		2

Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2011 and 2010		3

Notes to Condensed Consolidated Financial Statements		4 - 23

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		24 - 31

Item 3. Quantitative and Qualitative Disclosures about Market Risk		31 - 32

Item 4. Controls and Procedures		32

Part II Other Information

Item 1A. Risk Factors		33

Item 6. Exhibits		33 - 34

Signatures		35

Exhibit 12.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Thousands of dollars)


	June 30,			September 30,			June 30,
	2011			2010			2010
ASSETS

Current assets:
Cash and cash equivalents	$	108,914		$	4,318		$	38,055
Restricted cash		4,055			4,698			3,639
Accounts receivable (less allowances for doubtful accounts of $12,927, $7,072 and $17,297, respectively)		87,858			64,844			90,280
Accounts receivable — related parties		4,277			6,313			4,395
Accrued utility revenues		7,417			13,988			9,736
Inventories		58,751			118,858			67,611
Deferred income taxes		32,302			19,431			21,483
Regulatory assets		2,037			26,100			6,316
Derivative financial instruments		329			486			612
Prepaid expenses & other current assets		15,490			21,117			18,450

Total current assets		321,430			280,153			260,577

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $766,533, $734,739 and $727,484, respectively)		1,404,250			1,394,585			1,369,530

Goodwill		180,145			180,145			180,145
Regulatory assets		244,061			280,602			135,397
Other assets		8,678			4,091			4,205


Total assets	$	2,158,564		$	2,139,576		$	1,949,854


LIABILITIES AND STOCKHOLDER’S EQUITY

Current liabilities:
Bank loans	$	—		$	17,000		$	—
Accounts payable		41,487			61,297			49,500
Accounts payable — related parties		9,260			8,144			6,039
Deferred fuel refunds		22,451			8,295			16,576
Derivative financial instruments		5,334			10,564			828
Other current liabilities		142,797			133,935			110,360

Total current liabilities		221,329			239,235			183,303

Long-term debt		640,000			640,000			640,000
Deferred income taxes		327,039			281,101			222,568
Deferred investment tax credits		5,046			5,311			5,400
Pension and postretirement benefit obligations		113,235			161,338			143,987
Other noncurrent liabilities		69,898			78,137			70,797

Total liabilities		1,376,547			1,405,122			1,266,055

Commitments and contingencies (note 9)

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		468,323			467,631			467,571
Retained earnings		259,307			217,960			235,955
Accumulated other comprehensive loss		(5,872	)		(11,396	)		(79,986	)

Total common stockholder’s equity		782,017			734,454			683,799


Total liabilities and stockholder’s equity	$	2,158,564		$	2,139,576		$	1,949,854

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,
	2011			2010			2011			2010
Revenues	$	172,714		$	175,021		$	1,007,695		$	1,014,497


Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)		93,383			98,864			615,645			642,252
Operating and administrative expenses		42,910			40,515			134,103			133,369
Operating and administrative expenses — related parties		1,747			2,792			10,595			10,549
Taxes other than income taxes		3,523			4,167			13,350			13,589
Depreciation		12,058			12,728			37,347			37,847
Amortization		631			709			1,896			2,087
Other income, net		(1,024	)		(1,133	)		(7,716	)		(5,185	)

		153,228			158,642			805,220			834,508


Operating income		19,486			16,379			202,475			179,989
Interest expense		10,518			10,481			31,960			31,842


Income before income taxes		8,968			5,898			170,515			148,147
Income taxes		3,490			2,294			63,800			58,768


Net income	$	5,478		$	3,604		$	106,715		$	89,379

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,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	106,715		$	89,379
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		39,243			39,934
Deferred income taxes, net		18,700			49,532
Provision for uncollectible accounts		9,495			13,273
Other, net		8,712			11,330
Net change in:
Accounts receivable and accrued utility revenues		(23,902	)		(19,040	)
Inventories		60,107			128,987
Deferred fuel and power costs		32,951			(1,002	)
Accounts payable		(3,688	)		(6,472	)
Other current assets		5,340			(9,529	)
Other current liabilities		(17,988	)		(12,755	)

Net cash provided by operating activities		235,685			283,637


CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(59,590	)		(44,484	)
Net costs of property, plant and equipment disposals		(1,414	)		(1,848	)
Decrease (increase) in restricted cash		643			(3,639	)

Net cash used by investing activities		(60,361	)		(49,971	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends		(54,419	)		(55,134	)
Decrease in bank loans		(17,000	)		(154,000	)
Other		691			—

Net cash used by financing activities		(70,728	)		(209,134	)


Cash and cash equivalents increase	$	104,596		$	24,532


CASH AND CASH EQUIVALENTS:
End of period	$	108,914		$	38,055
Beginning of period		4,318			13,523

Increase	$	104,596		$	24,532

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)

Nature of Operations

UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”) own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.” PNG also has a heating, ventilation and air-conditioning service business (“UGI Penn HVAC Services, Inc.”) which operates principally in the PNG Gas service territory.

The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.

Significant Accounting Policies

Basis of Presentation.Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or “the Company”). We eliminate all significant intercompany accounts when we consolidate.

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments which we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2010 condensed consolidated balance sheet data were derived from audited financial statements but do not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read in conjunction with the financial statements and related notes included in our Annual Report on Form 10-K for the year ended September 30, 2010 (“Company’s 2010 Annual Financial Statements and Notes”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

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

Comprehensive Income.The following table presents the components of comprehensive income for the three and nine months ended June 30, 2011 and 2010:


	Three Months Ended					Nine Months Ended
	June 30,					June 30,
	2011			2010		2011		2010
Net income	$	5,478		$	3,604	$	106,715	$	89,379
Other comprehensive income		(1,696	)		1,034		5,524		3,100

Comprehensive income	$	3,782		$	4,638	$	112,239	$	92,479

Other comprehensive income (loss) in the 2011 periods principally reflects net gains or losses on interest rate protection agreements qualifying as cash flow hedges and, for all periods presented, includes actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.

Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets and an after-tax increase in other comprehensive income of $2,060 which is reflected in other comprehensive income in the nine months ended June 30, 2011 above (see Notes 6 and 7).

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

Use of Estimates.The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

New Accounting Standards Not Yet Adopted

Fair Value Measurements.In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04 “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments in ASU 2011-04 result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders’ equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance is effective for our interim period ending March 31, 2012 and is required to be applied prospectively. We do not expect that it will have a material impact on our results of operations or financial condition.

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

Presentation of Comprehensive Income.In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income,” which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) Topic 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. ASU 2011-05 does not change the items that must be reported in other comprehensive income. The change in presentation is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011 and the guidance is required to be applied retrospectively. Early adoption is permitted.

Segment Information

We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. UGI Penn HVAC Services, Inc. does not meet the quantitative thresholds for separate segment reporting under GAAP relating to business segment reporting and has been included in “Other.”

The accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s 2010 Annual Financial Statements and Notes. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.

No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States and all of our reportable segments’ long-lived assets are located in the United States.

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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, 2011:


			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	172,714	$	148,104	$	24,022	$	588
Cost of sales	$	93,383	$	78,811	$	14,572	$	—
Depreciation and amortization	$	12,689	$	11,596	$	1,093	$	—
Operating income	$	19,486	$	17,171	$	2,432	$	(117	)
Interest expense	$	10,518	$	9,852	$	666	$	—
Income before income taxes	$	8,968	$	7,319	$	1,766	$	(117	)

Total assets (at period end)	$	2,158,564	$	2,002,033	$	156,531	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	21,932	$	20,902	$	1,030	$	—

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	$	16,379	$	13,733	$	2,666	$	(20	)
Interest expense	$	10,481	$	9,994	$	487	$	—
Income 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	$	—

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

Nine Months Ended June 30, 2011:


			Reportable Segments
			Gas		Electric
	Total		Utility		Utility		Other
Revenues	$	1,007,695	$	921,655	$	84,673	$	1,367
Cost of sales	$	615,645	$	562,251	$	53,394	$	—
Depreciation and amortization	$	39,243	$	36,126	$	3,117	$	—
Operating income	$	202,475	$	193,206	$	9,025	$	244
Interest expense	$	31,960	$	30,202	$	1,758	$	—
Income before income taxes	$	170,515	$	163,004	$	7,267	$	244

Total assets (at period end)	$	2,158,564	$	2,002,033	$	156,531	$	—
Goodwill (at period end)	$	180,145	$	180,145	$	—	$	—
Capital expenditures	$	59,590	$	54,453	$	5,137	$	—

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	$	—

Inventories

Inventories comprise the following:


	June 30,		September 30,		June 30,
	2011		2010		2010
Gas Utility natural gas	$	50,082	$	111,531	$	60,272
Materials, supplies and other		8,669		7,327		7,339

Total inventories	$	58,751	$	118,858	$	67,611

At June 30, 2011, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”) two of which expire in October 2012 and one of which expires in October 2013 (see Note 10). Pursuant to these and predecessor SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.

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

The carrying value of gas storage inventories released under the SCAAs at June 30, 2011, September 30, 2010 and June 30, 2010 comprising 6.0 billion cubic feet (“bcf”), 11.7 bcf, and 6.4 bcf of natural gas, was $28,633, $62,653 and $35,322, respectively. In conjunction with the SCAAs, at June 30, 2011, September 30, 2010 and June 30, 2010, UGI Utilities held a total of $22,500 of security deposits received from its SCAA counterparties. These amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets.

Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 5 to the Company’s 2010 Annual Financial Statements and Notes. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:


	June 30,		September 30,		June 30,
	2011		2010		2010
Regulatory assets:
Income taxes recoverable	$	92,695	$	82,525	$	95,334
Underfunded pension and postretirement plans		116,003		159,154		10,260
Environmental costs		20,712		22,587		24,328
Deferred fuel and power costs		7,836		36,597		6,316
Other		8,852		5,839		5,475

Total regulatory assets	$	246,098	$	306,702	$	141,713


Regulatory liabilities:
Postretirement benefits	$	11,558	$	10,472	$	10,261
Environmental overcollections		6,182		7,211		8,354
Deferred fuel and power refunds		22,451		8,298		16,576
State tax benefits — distribution system repairs		6,166		6,685		10,983

Total regulatory liabilities	$	46,357	$	32,666	$	46,174

Underfunded pension and postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and postretirement benefits which is probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP relating to accounting for retirement benefits. These costs are amortized over the average remaining future service lives of the plan participants.

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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, 2011, September 30, 2010 and June 30, 2010 were $1,050, $1,359 and $558, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. As more fully described in Note 12, during Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value, with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities and Electric Utility’s DS procurement, implementation and contingency plans. At June 30, 2011 and September 30, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $10,082 and $19,702, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010 through DS rates, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power — costs or refunds. Unrealized gains on FTRs at June 30, 2011, September 30, 2010 and June 30, 2010 were not material.

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

Other Regulatory Matters

Transfer of CPG Storage Assets.On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of UGI Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011 the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets transferred was $10,949. Compliance with the provisions of the PUC Order approving the transfer of the storage assets is not expected to have a material impact on the results of operations of UGI Utilities. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.

CPG Base Rate Filing.On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16,500 annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase to allow for investigation and public hearing. On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. Under the terms of the Joint Petition, CPG will be permitted to increase distribution rates by $8,000 in additional base rate revenue as well as $900 in revenues per year for use in CPG’s Energy and Efficiency Conservation Program. On July 19, 2011, a recommended decision was issued by the two assigned administrative law judges (“ALJs”) who recommended that the PUC approve the Joint Petition without modification. The recommended decision of the ALJs is subject to PUC approval. It is anticipated that this process will conclude by the end of Fiscal 2011.

Defined Benefit Pension and Other Postretirement Plans

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

- 11 -

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,
	2011			2010			2011			2010
Service cost	$	1,751		$	1,745		$	54		$	40
Interest cost		5,564			5,284			182			212
Expected return on assets		(5,972	)		(5,858	)		(131	)		(126	)
Amortization of:
Prior service cost (benefit)		80			9			(174	)		(102	)
Actuarial loss		1,570			1,333			122			89

Net benefit cost		2,993			2,513			53			113
Change in associated regulatory liabilities		—			—			785			736

Net expense	$	2,993		$	2,513		$	838		$	849


	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Service cost	$	5,426		$	5,235		$	161		$	121
Interest cost		16,483			15,852			547			635
Expected return on assets		(17,965	)		(17,575	)		(392	)		(378	)
Amortization of:
Prior service cost (benefit)		222			27			(522	)		(305	)
Actuarial loss		5,268			3,999			364			268

Net benefit cost		9,434			7,538			158			341
Change in associated regulatory liabilities		—			—			2,356			2,208

Net expense	$	9,434		$	7,538		$	2,514		$	2,549

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $15,978 to the Pension Plan during the next twelve months. During the nine months ended June 30, 2011, the Company made contributions to the Pension Plan of $16,682. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the nine months ended June 30, 2011, nor are they expected to be material for all of Fiscal 2011.

- 12 -

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

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

Effective December 31, 2010, UGI Utilities merged its two defined benefit pension plans. The merged plan maintains the separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger and in accordance with GAAP relating to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010 which decreased pension and postretirement benefit obligations by $46,672; decreased associated regulatory assets by $43,150; and increased pre-tax other comprehensive income by $3,522 (see Notes 2 and 6).

The following table provides a reconciliation of the projected benefit obligation (“PBO”), plan assets and the funded status of the merged Pension Plan as of December 31, 2010:


	Three Months
	Ended
	December 31,
	2010
Change in benefit obligations:
Benefit obligations — October 1, 2010	$	464,976
Service cost		2,188
Interest cost		5,805
Actuarial gain		(30,639	)
Benefits paid		(4,664	)

Benefit obligations — December 31, 2010	$	437,666


Change in plan assets:
Fair value of plan assets — October 1, 2010	$	287,902
Actual gain on assets		19,285
Employer contribution		1,788
Benefits paid		(4,664	)

Fair value of plan assets — December 31, 2010	$	304,311


Funded status of the merged plan — December 31, 2010	$	(133,355	)


Liabilities recorded in the balance sheet:
Unfunded liabilities — included in other current liabilities	$	(20,303	)
Unfunded liabilities — included in other noncurrent liabilities		(113,052	)

Net amount recognized	$	(133,355	)

Amounts recorded in regulatory assets and liabilities:
Prior service cost	$	257
Net actuarial loss		112,733

Total	$	112,990

Amounts recorded in stockholder’s equity:
Prior service cost	$	29
Net actuarial loss		9,925

Total	$	9,954

- 13 -

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

The accumulated benefit obligation (“ABO”) of the merged plan at December 31, 2010 is $391,192. Actuarial assumptions for the merged plan at December 31, 2010 are as follows: discount rate — 5.5%; expected return on plan assets — 8.5%; rate of increase in salary levels — 3.8%.

UGI Utilities 2011 Credit Agreement

On May 25, 2011, UGI Utilities entered into an unsecured, revolving credit agreement (the “2011 Credit Agreement”) with a group of banks providing for borrowings up to $300,000 (including a $100,000 sublimit for letters of credit). Concurrently with entering into the 2011 Credit Agreement, UGI Utilities terminated its then-existing $350,000 revolving credit agreement dated as of August 11, 2006. Under the 2011 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The 2011 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. This 2011 Credit Agreement is currently scheduled to expire in May 2012, but may be extended by UGI Utilities to October 2015 if on or before May 23, 2012, the Company satisfies certain requirements relating to approval by the PUC. The Company is in the process of seeking such regulatory approval.

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, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

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

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

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.

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 they are responsible for an equitable share of any clean up costs Frontier would be required to pay to the City. Frontier alleged that through ownership and control of a subsidiary, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to Frontier’s claims. On October 19, 2010, the magistrate judge recommended the Court grant UGI Utilities’ motion. On November 19, 2010, the Court affirmed the recommended decision of the magistrate judge granting summary judgment in favor of UGI Utilities. On July 1, 2011, Frontier appealed the Court’s decision to the United States Court of Appeals for the First Circuit.

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.

- 15 -

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

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. The Northeast Companies alleged that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. 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 in Waterbury, CT (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s judgment in favor of UGI Utilities. A second phase of the trial is scheduled for August 2011 to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25,000.

Other Matters

Allentown, Pennsylvania Natural Gas Explosion.On February 9, 2011, a natural gas explosion occurred in Allentown, Pennsylvania which resulted in five deaths, several personal injuries and significant property damage. The PUC is investigating the Allentown accident and UGI Utilities is cooperating with that investigation. Based on a visual inspection, UGI Utilities identified a fracture in a segment of its cast iron natural gas pipeline in the area of the accident. The affected segment of pipeline is undergoing forensic testing by an expert, independent laboratory; however, the cause of the fracture has not yet been determined.

UGI Utilities has received claims as a result of the explosion, although no lawsuits have yet been filed. UGI Utilities maintains liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of a $500 deductible, will be recovered through UGI Utilities’ insurance. We believe that claims and expenses associated with the explosion will not have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

- 16 -

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

We cannot predict the final results of any of the claims, potential 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. We believe, after consultation with counsel, the final outcome of such other matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

10.

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.

From time to time, UGI Utilities is a party to SCAAs with Energy Services. At June 30, 2011, UGI Utilities was a party to two three-year SCAAs with Energy Services expiring October 31, 2012 and October 31, 2013 and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $16,566 and $19,156 during the three and nine months ended June 30, 2011, respectively, and $6,783 and $14,362 during the three and nine months ended June 30, 2010, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, were $15,000, $7,500 and $7,500 as of June 30, 2011, September 30, 2010 and June 30, 2010, respectively.

- 17 -

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

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, 2011, comprising approximately 4.0 bcf of natural gas, was $19,035. The carrying value of these gas storage inventories at September 30, 2010, comprising approximately 4.1 bcf of natural gas, was $20,749. The carrying value of these gas storage inventories at June 30, 2010, comprising approximately 2.2 bcf of natural gas, was $12,140.

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 heating season months of November through March. The amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the nine months ended June 30, 2011 and 2010 totaled $30,093 and $25,941, respectively. There were no such transactions during the three months ended June 30, 2011 or 2010.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2011, revenues associated with such sales to Energy Services totaled $13,529 and $74,589, respectively. During the three and nine months ended June 30, 2010, such revenues totaled $15,489 and $43,074, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to those transactions already described above) and beginning April 1, 2011, purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under a one-year agreement. During the three and nine months ended June 30, 2011, the aggregate amount of such transactions totaled $9,351 and $44,849, respectively. During the three and nine months ended June 30, 2010, such transactions totaled $7,145 and $22,034, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

- 18 -

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

11.

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, 2011, September 30, 2010 and June 30, 2010:


	Asset (Liability)
	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, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	128		$	201		$	—	$	329
Interest rate contracts	$	—		$	5,047		$	—	$	5,047
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(2,330	)	$	(8,802	)	$	—	$	(11,132	)

September 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	61		$	425		$	—	$	486
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(3,263	)	$	(17,798	)	$	—	$	(21,061	)

June 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	315		$	297		$	—	$	612
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(828	)	$	—		$	—	$	(828	)

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

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, 2011 were $640,000 and $715,954 respectively. The carrying amount and estimated fair value of our long-term debt at June 30, 2010 were $640,000 and $734,356, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt.

- 19 -

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

12.

Disclosures About Derivative Instruments and Hedging Activities

We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk 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. Gains and losses on Gas Utility natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with ASC No. 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 5).

Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At June 30, 2011, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $10,082 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the Condensed Consolidated Balance Sheet. In accordance with ASC 980 related to rate regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets on the June 30, 2011 Condensed Consolidated Balance Sheet.

- 20 -

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

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs associated with certain default service customers, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 relating to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 6). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At June 30, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 287.3 million kilowatt hours and 739.3 million kilowatt hours, respectively. The maximum period which we are currently hedging FTRs is 11 months.

At June 30, 2011, the volume of natural gas associated with our unsettled NYMEX natural gas futures and option contracts totaled 18.6 million dekatherms and the maximum period over which we are currently hedging natural gas futures and option contracts is 16 months. At June 30, 2010, the volume of natural gas associated with unsettled NYMEX natural gas futures contracts and option contracts totaled 11.3 million dekatherms. At June 30, 2011, the volume of electricity under Electric Utility’s forward electricity purchase contracts was 874.4 million kilowatt hours and the maximum period over which these contracts extend is 35 months.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. Associated volumes, fair values and effects on net income 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. As of June 30, 2011, the total notional amount of our unsettled IRPA contracts was $173,000. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of long-term debt forecasted to occur in September 2012 and September 2013. There were no unsettled IPRA contracts outstanding at June 30, 2010.

- 21 -

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

We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in AOCI, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At June 30, 2011, the amount of net losses associated with previously settled IRPAs expected to be reclassified into earnings during the next twelve months is $1,165.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures and options contracts are guaranteed by the NYMEX and have limited credit risk. These contracts generally require cash deposits in margin accounts. At June 30, 2011 and 2010, restricted cash in margin accounts totaled $4,055 and $3,639, respectively. We generally do not have credit-risk-related contingent features in our derivative contracts.

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2011 and 2010:

As of June 30:


	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2011		2010		Location	2011			2010
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Other assets	$	5,047	$	—

Derivatives Accounted for Under ASC 980:

Commodity contracts	Derivative financial instruments		201		287	Derivative financial instruments and Other noncurrent liabilities	$	(11,132	)	$	(828	)

Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments		128		325

Total Derivatives		$	5,376	$	612		$	(11,132	)	$	(828	)

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

There amounts of derivative gains or losses representing ineffectiveness were not material in the three or nine months ended June 30, 2011 and 2010. During the three and nine months ended June 30, 2011 and 2010, the amounts of IRPA net losses included in AOCI that were reclassified into net income were not material. Additionally, during nine months ended June 30, 2010, the impact on net income from changes in the fair value of FTRs not accounted for under ASC 980 was not material.

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

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UGI UTILITIES, INC. AND SUBSIDIARIES


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

Forward-Looking Statements

Information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability of oil, electricity and natural gas and the capacity to transport them to market areas; (3) changes in laws and regulations, including safety, tax and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability for environmental claims; (8) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor relations; (10) large customer, counterparty or supplier defaults; (11) increased uncollectible accounts expense; (12) liability for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas, including liability in excess of insurance coverage; (13) political, regulatory and economic conditions in the United States; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity market prices resulting in significantly higher cash collateral requirements.

These factors, and those factors set forth in Item 1A. Risk Factors of our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2011 and Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on our business, financial condition or future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

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UGI UTILITIES, INC. AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended June 30, 2011 (“2011 three-month period”) with the three months ended June 30, 2010 (“2010 three-month period”) and the nine months ended June 30, 2011 (“2011 nine-month period”) with the nine months ended June 30, 2010 (“2010 nine-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 3 to the condensed consolidated financial statements.

2011 three-month period compared with 2010 three-month period


							Increase
Three Months Ended June 30,	2011			2010			(Decrease)
(Millions of dollars)

Gas Utility:
Revenues	$	148.1		$	149.0		$	(0.9	)	(0.6	)%
Total margin (a)	$	69.3		$	66.0		$	3.3		5.0	%
Operating income	$	17.2		$	13.7		$	3.5		25.5	%
Income before income taxes	$	7.3		$	3.7		$	3.6		97.3	%
System throughput — bcf		33.4			28.0			5.4		19.3	%

Heating degree days — % (warmer) than normal (b)		(17.3	)%		(25.7	)%		—		—

Electric Utility:
Revenues	$	24.0		$	25.4		$	(1.4	)	(5.5	)%
Total margin (a)	$	8.1		$	8.1		$	—		0.0	%
Operating income	$	2.4		$	2.7		$	(0.3	)	(11.1	)%
Income before income taxes	$	1.8		$	2.2		$	(0.4	)	(18.2	)%
Distribution sales — gwh		224.7			218.6			6.1		2.8	%

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 in each of the three-month periods ended June 30, 2011 and 2010, 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 1995-2009 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 in the 2011 three-month period based upon heating degree days were 17.3% warmer than normal and 11.3% colder than the prior-year period. Total distribution system throughput increased 19.3% principally reflecting the effects of higher throughput to certain low-margin interruptible delivery service customers, the impact of colder early spring weather on throughput to core market customers, and the benefits of an improving economy. 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 $0.9 million during the 2011 three-month period, notwithstanding the greater throughput, principally reflecting a decline in revenues from retail core market customers ($1.9 million). The decrease in retail core market revenues principally reflects lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices ($11.9 million) partially offset by the greater retail core market volumes. 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 $78.8 million in the 2011 three-month period compared with $83.1 million in the prior-year period reflecting the previously mentioned lower average PGC rates.

Gas Utility total margin increased $3.3 million in the 2011 three-month period. The increase reflects a $4.0 million increase in core market margin resulting from the higher core market throughput.

The increases in Gas Utility operating income and income before income taxes during the 2011 three-month period principally reflects the previously mentioned increase in total margin ($3.3 million).

Electric Utility. Electric Utility’s kilowatt-hour sales in the 2011 three-month period were 2.8% higher than in the prior-year three-month period on heating degree day weather that was 17% colder. Notwithstanding the effects on heating-related sales from the colder weather, Electric Utility revenues were less than the prior year principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service. Electric Utility cost of sales declined to $14.6 million in the 2011 three-month period compared to $15.8 million in the 2010 three-month period principally reflecting the effects of the previously mentioned electricity generation supplier customer switching.

Electric Utility total margin was $8.1 million in the 2011 three-month period, equal to the margin recorded in the prior-year period.

Electric Utility 2011 three-month period operating income and income before income taxes declined $0.3 million and $0.4 million, respectively, principally reflecting slightly higher operating expenses and, with respect to income before income taxes, higher allocated interest charges.

Interest Expense and Income Taxes.Our consolidated interest expense in the 2011 three-month period was about equal to interest expense in the prior-year three-month period. Our annual estimated effective tax rate in the 2011 three-month period was about equal to the effective tax rate reflected in the prior-year three-month period.

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UGI UTILITIES, INC. AND SUBSIDIARIES

2011 nine-month period compared with 2010 nine-month period


							Increase
Nine Months Ended June 30,	2011			2010			(Decrease)
(Millions of dollars)

Gas Utility:
Revenues	$	921.7		$	922.2		$	(0.5	)	(0.1	)%
Total margin (a)	$	359.4		$	338.0		$	21.4		6.3	%
Operating income	$	193.2		$	168.6		$	24.6		14.6	%
Income before income taxes	$	163.0		$	138.1		$	24.9		18.0	%
System throughput — bcf		143.5			124.9			18.6		14.9	%

Heating degree days — % colder (warmer) than normal (b)		4.2	%		(3.9	)%		—		—

Electric Utility:
Revenues	$	84.7		$	90.9		$	(6.2	)	(6.8	)%
Total margin (a)	$	26.5		$	27.9		$	(1.4	)	(5.0	)%
Operating income	$	9.0		$	11.1		$	(2.1	)	(18.9	)%
Income before income taxes	$	7.3		$	9.8		$	(2.5	)	(25.5	)%
Distribution sales — gwh		754.2			723.8			30.4		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 $4.8 million and $5.0 million during the nine-month periods ended June 30, 2011 and 2010, 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 1995-2009 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 4.2% colder than normal in the 2011 nine-month period compared with temperatures that were 3.9% warmer than normal in the prior-year period. Total distribution system throughput increased 18.6 bcf reflecting higher throughput to certain low-margin interruptible delivery service customers, the effects of the colder weather on core market customers and the benefits of an improving economy.

Gas Utility revenues were about equal to the prior-year period principally reflecting a decline in revenues from core market customers ($34.5 million) partially offset by a $33.1 million increase in revenues from low-margin off-system sales. The decrease in core market revenues principally resulted from lower average retail core market PGC rates reflecting lower natural gas prices ($80.2 million) offset by the effects of the higher throughput. Gas Utility’s cost of gas was $562.3 million in the 2011 nine-month period compared with $584.2 million in the prior-year period principally reflecting the lower average PGC rates offset in part by an increase in retail core-market sales.

Gas Utility total margin increased $21.4 million in the 2011 nine-month period. The increase principally reflects a $20.1 million increase in core market margin reflecting the increase in core market throughput.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Gas Utility operating income and income before income taxes during the 2011 nine-month period increased $24.6 million and $24.9 million, respectively, principally reflecting the previously mentioned increase in total margin ($21.4 million) and higher other income ($2.6 million).

Electric Utility.Electric Utility’s kilowatt-hour sales in the 2011 nine-month period were 4.2% higher than in the prior-year nine-month period on heating degree day weather that was 8.1% colder. Notwithstanding the effects of the colder weather, Electric Utility revenues decreased $6.2 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service and, to a much lesser extent, lower average default service (“DS”) rates compared to the provider of last resort (“POLR”) rates that were in effect through December 31, 2009. Under DS rates, Electric Utility is no longer subject to electricity price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under POLR rates. Electric Utility cost of sales declined to $53.4 million in the 2011 nine-month period compared to $58.0 million in the 2010 nine-month period principally reflecting the effects of the previously mentioned electricity generation supplier customer switching.

Electric Utility total margin declined $1.4 million in the 2011 nine-month period, notwithstanding the greater sales, principally reflecting the absence of margin from electric generation service beginning January 1, 2010.

Electric Utility 2011 nine-month period operating income and income before income taxes declined $2.1 million and $2.5 million, respectively, principally reflecting the previously mentioned lower total margin, higher operating and maintenance expenses and, with respect to income before income taxes, higher allocated interest expense.

Interest Expense and Income Taxes.Our consolidated interest expense in the 2011 nine-month period was about equal to interest expense in the prior-year nine-month period. Our annual estimated effective tax rate was lower in the 2011 nine-month period principally reflecting the regulatory effects of greater state tax depreciation (as further described below under “Financial Condition & Liquidity”).

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

The Company’s total debt outstanding at June 30, 2011 was $640 million compared to total debt outstanding at September 30, 2010 of $657 million which includes $17 million outstanding under UGI Utilities’ Credit Agreement (as further described below).

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UGI UTILITIES, INC. AND SUBSIDIARIES

On May 25, 2011, UGI Utilities entered into an unsecured revolving credit agreement (the “2011 Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit). Concurrently with entering into the 2011 Credit Agreement, UGI Utilities terminated its then-existing $350 million revolving credit agreement dated as of August 11, 2006. The 2011 Credit Agreement is currently scheduled to expire in May 2012, but may be extended by UGI Utilities to October 2015 if on or before May 23, 2012, the Company satisfies certain requirements relating to approval by the PUC. The Company is in the process of seeking regulatory approval. At June 30, 2011, there were no amounts outstanding under the 2011 Credit Agreement. Borrowings under the 2011 Credit Agreement and a predecessor credit agreement are classified as bank loans. During the 2011 and 2010 nine-month periods, average daily bank loan borrowings were $23.5 million and $93.1 million, respectively, and peak bank loan borrowings totaled $90 million and $203 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is greatest. Based upon cash expected to be generated from Gas Utility and Electric Utility operations and bank loan borrowings, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2011.

In 2010, U.S. federal tax legislation was enacted that allows taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010 through the end of calendar 2011, when such property is placed in service before 2012. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers will also be permitted to fully deduct such qualifying capital expenditures for Pennsylvania state corporate net income tax purposes. In accordance with Pennsylvania utility ratemaking practice, UGI Utilities’ Fiscal 2011 effective tax rate reflects the beneficial effects of this greater state tax depreciation. The additional state and federal tax depreciation deductions described above will reduce federal and state income taxes otherwise payable and increase UGI Utilities deferred income tax liabilities.

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 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 credit agreement borrowings to manage seasonal cash flow needs. Due to the impact of strong operating cash flows reflecting the greater operating results, lower cash paid for income taxes due to in large part to accelerated tax depreciation deductions, and the continuing effects of low natural gas prices, our cash and cash equivalents at June 30, 2011 increased to $108.9 million compared to $4.3 million at September 30, 2010 and there were no amounts outstanding under our 2011 Credit Agreement.

Cash flow provided by operating activities was $235.7 million in the 2011 nine-month period compared to $283.6 million in the prior-year nine-month period. Cash flow from operating activities before changes in operating working capital decreased to $182.9 million in the 2011 nine-month period from $203.4 million in the prior-year nine-month period, notwithstanding the increase in operating results, primarily due to lower noncash charges for deferred income taxes. Changes in operating working capital provided $52.8 million of operating cash flow during the 2011 nine-month period compared to $80.2 million provided during the prior-year nine-month period. Among other things, the lower cash flow from changes in operating working capital in the 2011 nine-month period reflects lower cash from changes in natural gas inventories partially offset by greater cash from deferred fuel recoveries.

- 29 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Investing activities. Cash used by investing activities was $60.4 million in the 2011 nine-month period compared to $50.0 million in the 2010 nine-month period. Total capital expenditures were $59.6 million in the 2011 nine-month period compared with $44.5 million recorded in the prior-year period. The 2011 nine-month period principally reflects higher UGI Gas capital expenditures and an increase in Electric Utility capital expenditures associated with an electricity transmission capacity project in its service territory.

Financing activities.Cash used by financing activities was $70.7 million in the 2011 nine-month period compared with $209.1 million in the 2010 nine-month period. Financing activity cash flows are primarily the result of net borrowings and repayments under our revolving credit agreements, cash dividends paid to UGI and capital contributions from UGI. We paid cash dividends to UGI totaling $54.4 million and $55.1 million during the 2011 and 2010 nine-month periods, respectively. During the 2011 nine-month period, net bank loan repayments totaled $17 million compared with net bank loan repayments of $154 million in the prior-year nine-month period.

On July 29, 2011, after the end of the June 2011 quarter, UGI Utilities paid a cash dividend to UGI of 45.1 million.

Merger of Pension Plans

Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. The merged plan maintains the separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger and in accordance with GAAP related to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010. The remeasurement resulted in a decrease in pension and postretirement benefit obligations associated regulatory assets, and an increase in other comprehensive income (see Notes 2, 6 and 7). The remeasurement will result in an approximate $1.4 million decrease in Fiscal 2011 pension expense beginning January 1, 2011.

Transfer of CPG Storage Assets

On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of UGI Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011 the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets transferred was $10.9 million. Compliance with the provisions of the PUC Order approving the transfer of the storage assets is not expected to have a material impact on the results of operations of UGI Utilities. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CPG Base Rate Filing

On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 million annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase to allow for investigation and public hearing. On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. Under the terms of the Joint Petition, CPG will be permitted to increase distribution rates by $8.0 million in additional base rate revenue as well as $0.9 million in revenues per year for use in CPG’s Energy and Efficiency Conservation Program. On July 19, 2011, a recommended decision was issued by the two assigned administrative law judges (“ALJs”) who recommended that the PUC approve the Joint Petition without modification. The recommended decision of the ALJs is subject to PUC approval. It is anticipated that this process will conclude by the end of Fiscal 2011.


ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of natural gas derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At June 30, 2011 and 2010, Gas Utility had $4.1 million and $3.6 million, respectively, of restricted cash associated with natural gas futures accounts with brokers. At June 30, 2011, the fair values of our natural gas futures and option contracts were losses of $1.1 million.

Beginning January 1, 2010, Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs through the application of DS rates. 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”) and forward electricity purchase contracts, associated with our Electric Utility operations. 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 electricity transmission grid. Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, through purchases at monthly PJM auctions. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. At June 30, 2011 the fair values of FTRs were not material.

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, 2011 and 2010 were not material.

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UGI UTILITIES, INC. AND SUBSIDIARIES

In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). The fair value of unsettled IRPAs held at June 30, 2011 was an asset of $5.0 million. A hypothetical 10% adverse change in the three-month LIBOR would result in a decrease in fair value of $5.9 million. There were no unsettled IRPAs outstanding at June 30, 2010.

Our unsettled derivative instruments at June 30, 2011 comprise (1) Gas Utility’s exchange-traded natural gas futures and options contracts, which are included in Gas Utility’s PGC recovery mechanism; (2) Electric Utility’s FTRs and electricity forward purchase contracts, which are included in Electric Utility’s DS recovery mechanism; (3) exchange-traded gasoline futures and swap contracts; and (4) IRPAs.


ITEM 4.		CONTROLS AND PROCEDURES

(a)

Evaluation of Disclosure Controls and Procedures

The Company’s disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were effective at the reasonable assurance level.

(b)

Change in Internal Control over Financial Reporting

No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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UGI UTILITIES, INC. AND SUBSIDIARIES

PART II OTHER INFORMATION


ITEM 1A.		RISK FACTORS

In addition to the other information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010 and in Part II, “Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2011, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K and Quarterly Report on Form 10-Q 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):

Incorporation by Reference

Exhibit

No.

Exhibit

Registrant

Filing

Exhibit

10.1

Credit Agreement, dated as of May 25, 2011 among UGI Utilities, Inc., as borrower, and PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and RBS Citizens, N.A., as joint lead arrangers and joint bookrunners, and PNC Bank, National Association, Citizens Bank of Pennsylvania, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, The Bank of New York Mellon, and the other financial institutions from time to time parties thereto.

UGI Utilities

Form 8-K (5/25/2011)

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, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

- 33 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Exhibit

No.

Exhibit

Registrant

Filing

Exhibit

31.2

Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101

.INS*

XBRL Instance

101

.SCH*

XBRL Taxonomy Extension Schema

101

.CAL*

XBRL Taxonomy Extension Calculation

101

.DEF*

XBRL Taxonomy Extension Definition

101

.LAB*

XBRL Taxonomy Extension Labels

101

.PRE*

XBRL Taxonomy Extension Presentation


*		XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information.

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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 5, 2011	By:	/s/ Donald E. Brown
		Donald E. Brown
		Vice President — Finance and Chief Financial Officer

Date: August 5, 2011	By:	/s/ Matthew J. Nolan
		Matthew J. Nolan
		Controller

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UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX



12.1		Computation of ratio of earnings to fixed charges

31.1		Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2011, 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, 2011, 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, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101	.INS*	XBRL.Instance

101	.SCH*	XBRL Taxonomy Extension Schema

101	.CAL*	XBRL Taxonomy Extension Calculation

101	.DEF*	XBRL Taxonomy Extension Definition

101	.LAB*	XBRL Taxonomy Extension Labels

101	.PRE*	XBRL Taxonomy Extension Presentation


*		XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Ugi Utilities Inactive 10-Q2011 Q3 Quarterly report

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