10-Q

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, 2013

OR

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

For the transition period from to

Commission file number 1-1398

UGI UTILITIES, INC.

(Exact name of registrant as specified in its charter)

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

UGI UTILITIES, INC.

2525 N. 12th Street, Suite 360

Reading, PA

(Address of principal executive offices)

19612

(Zip Code)

(610) 796-3400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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

Large accelerated filer o Accelerated filer o Non-accelerated filer þ Smaller reporting company o

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

At July 31, 2013, 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, 2013, September 30, 2012 and June 30, 2012	1
Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2013 and 2012	2
Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended June 30, 2013 and 2012	3
Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2013 and 2012	4
Notes to Condensed Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3. Quantitative and Qualitative Disclosures About Market Risk	24
Item 4. Controls and Procedures	26
Part II Other Information
Item 1A. Risk Factors	27
Item 6. Exhibits	27
Signatures	28

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Thousands of dollars)

	June 30, 2013			September 30, 2012			June 30, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	82,027		$	1,259		$	75,969
Restricted cash	2,636			—			1,604
Accounts receivable (less allowances for doubtful accounts of $9,166, $3,588 and $7,457, respectively)	78,677			47,362			61,072
Accounts receivable — related parties	4,086			4,571			4,311
Accrued utility revenues	11,836			16,911			14,970
Inventories	53,998			67,334			38,413
Deferred income taxes	38,619			46,436			33,595
Regulatory assets	3,747			6,473			2,681
Derivative financial instruments	8,228			5,468			545
Prepaid expenses & other current assets	9,766			29,313			17,890
Total current assets	293,620			225,127			251,050
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $846,941, $815,720 and $809,458, respectively)	1,531,440			1,479,949			1,458,654
Goodwill	182,145			182,145			182,145
Regulatory assets	317,216			331,932			288,366
Other assets	3,635			4,026			5,630
Total assets	$	2,328,056		$	2,223,179		$	2,185,845
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	133,000		$	133,000		$	40,000
Bank loans	—			9,200			—
Accounts payable	35,587			46,754			30,457
Accounts payable — related parties	17,176			10,192			10,175
Deferred fuel refunds	14,156			4,435			10,325
Derivative financial instruments	22,911			36,011			7,150
Other current liabilities	123,438			131,092			144,492
Total current liabilities	346,268			370,684			242,599
Long-term debt	467,000			467,000			600,000
Deferred income taxes	443,703			417,052			371,388
Deferred investment tax credits	4,355			4,612			4,698
Pension and postretirement benefit obligations	172,721			179,056			126,007
Other noncurrent liabilities	51,999			56,262			92,409
Total liabilities	1,486,046			1,494,666			1,437,101
Commitments and contingencies (note 8)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)	60,259			60,259			60,259
Additional paid-in capital	469,736			468,692			468,630
Retained earnings	327,298			229,379			246,286
Accumulated other comprehensive loss	(15,283		)	(29,817		)	(26,431		)
Total common stockholder’s equity	842,010			728,513			748,744
Total liabilities and stockholder’s equity	$	2,328,056		$	2,223,179		$	2,185,845

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,
	2013			2012			2013			2012
Revenues	$	148,798		$	143,644		$	818,496		$	770,087
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	64,332			62,701			415,394			412,377
Operating and administrative expenses	46,420			37,689			143,076			124,380
Operating and administrative expenses — related parties	1,940			2,107			6,757			7,013
Taxes other than income taxes	3,756			3,919			12,716			12,903
Depreciation	13,201			12,425			38,849			37,132
Amortization	832			826			2,467			2,292
Other income, net	(561		)	(1,323		)	(1,435		)	(4,362		)
	129,920			118,344			617,824			591,735
Operating income	18,878			25,300			200,672			178,352
Interest expense	9,690			10,575			29,587			31,859
Income before income taxes	9,188			14,725			171,085			146,493
Income taxes	3,815			6,265			70,641			57,494
Net income	$	5,373		$	8,460		$	100,444		$	88,999

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Thousands of dollars)

	Three Months Ended June 30,					Nine Months Ended June 30,
	2013		2012			2013		2012
Net income	$	5,373	$	8,460		$	100,444	$	88,999
Other comprehensive income (loss):
Net gains (losses) in fair value of derivative instruments (net of tax of $(5,301), $4,801, $(9,638) and $4,209, respectively)	7,475		(6,772		)	13,590		(5,938		)
Reclassifications of net losses on derivative instruments (net of tax of $(84), $(201), $(252) and $(725), respectively)	119		283			356		1,023
Benefit plans (net of tax of $(140), $(80), $(418) and $(242), respectively)	195		101			588		317
Other comprehensive income (loss)	7,789		(6,388		)	14,534		(4,598		)
Comprehensive income	$	13,162	$	2,072		$	114,978	$	84,401

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,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	100,444		$	88,999
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	41,316			39,424
Deferred income taxes, net	23,369			21,269
Provision for uncollectible accounts	8,297			5,592
Other, net	4,647			(12,809		)
Net change in:
Accounts receivable and accrued utility revenues	(34,052		)	(5,354		)
Inventories	13,336			65,850
Deferred fuel and power costs	20,549			8,133
Accounts payable	(4,183		)	(23,032		)
Other current assets	19,675			7,059
Other current liabilities	(4,753		)	7,467
Net cash provided by operating activities	188,645			202,598
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(94,480		)	(79,698		)
Net costs of property, plant and equipment disposals	(2,604		)	(2,400		)
(Increase) decrease in restricted cash	(2,636		)	2,704
Net cash used by investing activities	(99,720		)	(79,394		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	—			(54,809		)
Decrease in bank loans	(9,200		)	—
Other	1,043			307
Net cash used by financing activities	(8,157		)	(54,502		)
Cash and cash equivalents increase	$	80,768		$	68,702
CASH AND CASH EQUIVALENTS:
End of period	$	82,027		$	75,969
Beginning of period	1,259			7,267
Increase	$	80,768		$	68,702

See accompanying notes to condensed consolidated financial statements.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

1. Nature of Operations

UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”), own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania 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.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, 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 service territory (“HVAC Business”).

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

2. Significant Accounting Policies

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

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments that 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, 2012, condensed consolidated balance sheet data was 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, 2012 (“Company’s 2012 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.

Comprehensive Income. Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally reflects net gains (losses) on interest rate protection agreements qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.

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

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

3. Accounting Changes

New Accounting Standards Not Yet Adopted

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In February 2013, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance regarding disclosures for items reclassified out of accumulated other comprehensive income (“AOCI”). The new disclosure guidance is effective for fiscal years, and

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interim periods within those fiscal years, beginning after December 15, 2012. The new disclosures are to be applied prospectively, and early adoption is permitted. We expect to adopt the new guidance in Fiscal 2014. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities. In December 2011 (and amended in January 2013), the FASB issued new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 (Fiscal 2014) and interim periods within those annual periods, and is required to be applied retrospectively. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

4. 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. The HVAC Business 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 2012 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, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	148,798	$	126,725	$	21,535	$	538
Cost of sales	$	64,332	$	52,365	$	11,967	$	—
Depreciation and amortization	$	14,033	$	13,012	$	1,021	$	—
Operating income	$	18,878	$	16,054	$	2,584	$	240
Interest expense	$	9,690	$	9,172	$	518	$	—
Income before income taxes	$	9,188	$	6,882	$	2,066	$	240
Total assets (at period end)	$	2,328,056	$	2,164,435	$	163,621	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	38,961	$	37,224	$	1,737	$	—

Three Months Ended June 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	143,644	$	122,273	$	20,779	$	592
Cost of sales	$	62,701	$	51,401	$	11,300	$	—
Depreciation and amortization	$	13,251	$	12,332	$	919	$	—
Operating income	$	25,300	$	22,535	$	2,554	$	211
Interest expense	$	10,575	$	9,965	$	610	$	—
Income before income taxes	$	14,725	$	12,570	$	1,944	$	211
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	29,914	$	29,004	$	910	$	—

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Nine Months Ended June 30, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	818,496	$	743,614	$	73,604	$	1,278
Cost of sales	$	415,394	$	372,681	$	42,713	$	—
Depreciation and amortization	$	41,316	$	38,348	$	2,968	$	—
Operating income	$	200,672	$	191,592	$	8,597	$	483
Interest expense	$	29,587	$	28,071	$	1,516	$	—
Income before income taxes	$	171,085	$	163,521	$	7,081	$	483
Total assets (at period end)	$	2,328,056	$	2,164,435	$	163,621	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	94,480	$	90,173	$	4,307	$	—

Nine Months Ended June 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	770,087	$	696,814	$	71,888	$	1,385
Cost of sales	$	412,377	$	370,572	$	41,805	$	—
Depreciation and amortization	$	39,424	$	36,635	$	2,789	$	—
Operating income	$	178,352	$	168,735	$	9,147	$	470
Interest expense	$	31,859	$	30,148	$	1,711	$	—
Income before income taxes	$	146,493	$	138,587	$	7,436	$	470
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	79,698	$	76,470	$	3,228	$	—

5. Inventories

Inventories comprise the following:

	June 30, 2013		September 30, 2012		June 30, 2012
Gas Utility natural gas	$	43,052	$	57,663	$	27,761
Materials, supplies and other	10,946		9,671		10,652
Total inventories	$	53,998	$	67,334	$	38,413

At June 30, 2013, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”) with Energy Services, Inc. (“Energy Services”), a second-tier, wholly owned subsidiary of UGI, one of which expires in October 2013 and two of which expire in October 2015 (see Note 9). Pursuant to 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.

The carrying value of gas storage inventories released under UGI Utilities’ principal SCAAs at June 30, 2013, September 30, 2012 and June 30, 2012, comprising 5.6 billion cubic feet (“bcf”), 11.4 bcf and 6.0 bcf of natural gas, was $24,389, $32,627 and $15,787, respectively. In conjunction with these SCAAs, UGI Utilities held a total of security deposits received from its SCAA counterparties of $16,500 at June 30, 2013, and $22,500 at September 30, 2012 and June 30, 2012. These amounts are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets.

6. Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 4 to the Company’s 2012 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, 2013		September 30, 2012		June 30, 2012
Regulatory assets:
Income taxes recoverable	$	104,731	$	103,172	$	99,891
Underfunded pension and postretirement plans	177,846		188,222		144,613
Environmental costs	16,642		16,812		16,562
Deferred fuel and power costs	4,109		11,602		9,829
Removal costs, net	12,074		12,718		11,840
Other	5,561		5,879		8,312
Total regulatory assets	$	320,963	$	338,405	$	291,047
Regulatory liabilities:
Postretirement benefits	$	14,244	$	13,147	$	12,342
Environmental overcollections	2,906		2,883		3,726
Deferred fuel and power refunds	14,156		4,435		10,325
State tax benefits — distribution system repairs	8,024		7,385		6,961
Other	672		494		624
Total regulatory liabilities	$	40,002	$	28,344	$	33,978

Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and Electric Utility’s 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 natural 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. Net unrealized gains (losses) on such contracts at June 30, 2013, September 30, 2012, and June 30, 2012, were $(1,352), $5,303 and $280, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are recognized on the Condensed Consolidated Balance Sheet with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At June 30, 2013, September 30,

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

2012, and June 30, 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $6,060, $9,207 and $13,095, 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, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at June 30, 2013, September 30, 2012, and June 30, 2012, were not material.

Allentown, Pennsylvania Natural Gas Incident. On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff’s formal complaint, issued on June 11, 2012, pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $386 to $500; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

Transfers of Assets. On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11-mile natural gas pipeline, related facilities and right of way located in Delmar Township, Pennsylvania (“TL-96 line”) to Energy Services.   The PUC approved the transfer and in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services.  The net book value of the TL-96 line was approximately $2,650 which amount, net of related deferred income taxes, was recorded as a dividend of net assets.

7. 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 postretirement life insurance benefits to nearly all active and retired employees.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Service cost	$	2,052		$	1,756		$	51		43
Interest cost	5,196			5,594			143			165
Expected return on assets	(6,197		)	(5,940		)	(133		)	(127		)
Amortization of:
Prior service cost (benefit)	62			62			(105		)	(105		)
Actuarial loss	3,366			1,963			91			99
Net benefit cost	4,479			3,435			47			75
Change in associated regulatory liabilities	—			—			815			784
Net expense	$	4,479		$	3,435		$	862		$	859
	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Service cost	$	6,158		$	5,269		$	154		$	129
Interest cost	15,587			16,782			428			497
Expected return on assets	(18,594		)	(17,822		)	(396		)	(380		)
Amortization of:
Prior service cost (benefit)	187			187			(317		)	(317		)
Actuarial loss	10,098			5,890			273			296
Net benefit cost	13,436			10,306			142			225
Change in associated regulatory liabilities	—			—			2,446			2,353
Net expense	$	13,436		$	10,306		$	2,588		$	2,578

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 Plan 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 $2,500 to the Pension Plan during the remainder of Fiscal 2013. During the nine months endedJune 30, 2013 and 2012, the Company made contributions to the Pension Plan of $13,365 and $25,442, respectively. 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 endedJune 30, 2013 and 2012, nor are they expected to be material for all of Fiscal 2013.

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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

8. Commitments and Contingencies

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At June 30, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14,399 and $15,820, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of 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.

The Company 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 (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At June 30, 2013, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.

From time to time, UGI Utilities is notified of 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 generally investigate the extent of environmental contamination or perform environmental remediation. 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.

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012. There have been no recent developments in this matter.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Other Matters

Allentown, Pennsylvania Natural Gas Incident. 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 “Incident”). UGI Utilities has received and settled all wrongful death claims and substantially all property and personal injury claims in connection with the Incident. UGI Utilities maintains liability insurance for personal injury, wrongful death and property and casualty damages subject to a $500 deductible. We expect that the remaining claims will be covered by UGI Utilities’ insurance. As a result, the Incident did not and we continue to believe it will not have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

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

9. Related Party Transactions

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

At June 30, 2013, UGI Utilities was a party to three three-year SCAAs with Energy Services one of which expires October 31, 2013, and two of which expire October 31, 2015 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 $21,570 and $26,596 during the three and nine months ended June 30, 2013, respectively, and $8,396 and $13,726 during the three and nine months ended June 30, 2012. 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 $16,500 as of June 30, 2013, and $15,000 as of September 30, 2012 and June 30, 2012.

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, 2013, comprising approximately 5.6 bcf of natural gas, was $24,389. The carrying value of these gas storage inventories at September 30,

- 13 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

2012, comprising approximately 7.6 bcf of natural gas, was $21,217. The carrying value of these gas storage inventories at June 30, 2012, comprising approximately 4.1 bcf of natural gas, was $10,512.

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 aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the nine months ended June 30, 2013 and 2012, totaled $32,526 and $30,752, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2013, revenues associated with such sales to Energy Services totaled $14,956 and $60,208, respectively. During the three and nine months ended June 30, 2012, revenues associated with such sales to Energy Services totaled $12,067 and $52,744, respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three and nine months ended June 30, 2013, the aggregate amount of such purchases totaled $24,426 and $61,659, respectively. During the three and nine months ended June 30, 2012, such purchases totaled $13,158 and $36,477, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

- 14 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

10. Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of June 30, 2013, September 30, 2012 and June 30, 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	103		$	—		$	—	$	103
Interest rate contracts	$	—		$	8,125		$	—	$	8,125
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,885	)	$	(5,759	)	$	—	$	(7,644	)
Interest rate contracts	$	—		$	(15,306	)	$	—	$	(15,306	)
September 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5,468		$	—		$	—	$	5,468
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(671	)	$	(8,766	)	$	—	$	(9,437	)
Interest rate contracts	$	—		$	(30,522	)	$	—	$	(30,522	)
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	545		$	—		$	—	$	545
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,457	)	$	(12,099	)	$	—	$	(13,556	)
Interest rate contracts	$	—		$	(28,917	)	$	—	$	(28,917	)

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. There were no transfers between Level 1 and Level 2 during the periods presented.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for 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, 2013, were $600,000 and $663,178, respectively. The carrying amount and estimated fair value of our long-term debt at June 30, 2012, were $640,000 and $742,165, 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 (Level 2).

11. 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, including the cost of financial instruments used to hedge purchased gas costs. 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. At June 30, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.7 million dekatherms and 13.2 million dekatherms, respectively. At June 30, 2013, the maximum period over which Gas Utility is hedging natural gas market price risk is 16 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with accounting guidance related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 6).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At June 30, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising net losses of $6,060 and $13,095, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At June 30, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 327.4 million kilowatt hours and 654.7 million kilowatt hours, respectively. At June 30, 2013, the maximum period over which these contracts extend is 11 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly 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. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 6). At June 30, 2013 and 2012, the volumes associated with Electric Utility FTRs

- 16 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

totaled 260.6 million kilowatt hours and 261.0 million kilowatt hours, respectively. At June 30, 2013, the maximum period over which we are hedging electricity congestion with FTRs is 11 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, 2013 and 2012, the total notional amounts of unsettled IRPAs 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 2013.

UGI Utilities reclassified pre-tax losses of $682 from AOCI into income during the nine months ended June 30, 2012 as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in “Other income, net” on the Condensed Consolidated Statements of Income.

At June 30, 2013, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $2,203.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2013, there was $2,636 restricted cash in brokerage accounts. At June 30, 2012, restricted cash in brokerage accounts totaled $1,604.

- 17 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of June 30, 2013 and 2012:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	8,125	$	—	Derivative financial instruments and Other noncurrent liabilities	$	(15,306	)	$	(28,917	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	67		545		Derivative financial instruments and Other noncurrent liabilities	(7,644		)	(13,539		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	36		—		Derivative financial instruments	—			(17		)
Total Derivatives		$	8,228	$	545		$	(22,950	)	$	(42,473	)

- 18 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for three and nine months ended June 30, 2013 and 2012:

Three Months Ended June 30, :
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013			2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	12,776		$	(11,573	)	$	(203	)	$	(484	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
	2013			2012
Commodity contracts	$	(93	)	$	(127	)							Operating expenses/other income, net
Nine Months Ended June 30, :
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013			2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	23,228		$	(10,147	)	$	(608	)	$	(1,748	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
	2013			2012
Commodity contracts	$	12		$	78								Operating expenses/other income, net

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 and contracts that provide for the purchase and delivery, or sale, 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.

- 19 -

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, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 that 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 and the impact of regulatory enforcement activity related thereto, ranging from financial penalties, required reporting or operational measures up to suspension of applicable certificates of public convenience; (13) political, regulatory and economic conditions in the United States; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity market prices resulting in significantly higher cash collateral requirements.

These factors, and those factors set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012, 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, 2013 (“2013 three-month period”) with the three months ended June 30, 2012 (“2012 three-month period”) and the nine months ended June 30, 2013 (“2013 nine-month period”) with the nine months ended June 30, 2012 (“2012 nine-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 4 to the condensed consolidated financial statements.

2013 three-month period compared with 2012 three-month period

Three Months Ended June 30,	2013			2012			Increase (Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	126.7		$	122.3		$	4.4		3.6	%
Total margin (a)	$	74.4		$	70.9		$	3.5		4.9	%
Operating income	$	16.1		$	22.5		$	(6.4	)	(28.4	)%
Income before income taxes	$	6.9		$	12.6		$	(5.7	)	(45.2	)%
System throughput — billions of cubic feet (“bcf”)
Core market	8.8			8.3			0.5			6.0	%
Total	35.9			36.2			(0.3		)	(0.8	)%
Heating degree days — % (warmer) than normal (b)	(7.1		)%	(19.0		)%	—			—
Electric Utility:
Revenues	$	21.5		$	20.8		$	0.7		3.4	%
Total margin (a)	$	8.4		$	8.4		$	—		—	%
Operating income	$	2.6		$	2.6		$	—		—	%
Income before income taxes	$	2.1		$	1.9		$	0.2		10.5	%
Distribution sales — millions of kilowatt-hours (“gwh”)	222.5			221.4			1.1			0.5	%

(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 $1.2 million and $1.1 million during the three-month periods ended June 30, 2013 and 2012, 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 2013 three-month period based upon heating degree days were 7.1% warmer than normal but 14.4% colder than the prior-year three-month period. Total distribution system throughput decreased slightly, notwithstanding an increase in core market throughput and greater large firm delivery service throughput, principally reflecting lower throughput to certain low-margin, interruptible delivery service customers. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers. Gas Utility system throughput to core-market customers was above last year principally reflecting the effects of the colder weather and, to a much lesser extent, customer growth, due principally to conversions from oil prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $4.4 million during the 2013 three-month period principally reflecting higher revenues from core market customers ($1.9 million), greater revenues from large firm delivery service customers on the higher throughput, and slightly higher revenues from off-system sales ($1.5 million). The increase in core market revenues principally reflects the effects of the higher core market volumes partially offset by the effects of lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices ($7.0 million). 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

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 $52.4 million in the 2013 three-month period compared with $51.4 million in the prior-year period principally reflecting the effects of the greater retail core-market volumes sold ($6.3 million) and the higher off-system sales ($1.5 million) partially offset by the effects of the lower average PGC rates.

Gas Utility total margin increased $3.5 million in the 2013 three-month period principally reflecting higher core market total margin ($1.3 million) and greater large firm delivery service total margin ($1.7 million). The higher core market and large firm delivery service total margin reflects the effects of the greater throughput to these customers.

The decreases in Gas Utility operating income and income before income taxes during the 2013 three-month period, notwithstanding the increase in total margin, principally reflects higher operating and administrative expenses ($9.4 million) including, among other things, higher uncollectible accounts expense ($2.4 million), higher pension and benefits expenses ($1.8 million) and higher injuries and damages and distribution system expenses ($1.4 million).

Electric Utility. Temperatures based upon heating degree days during the 2013 three-month period were approximately 9% warmer than normal but approximately 9% colder than the 2012 three-month period. Cooling degree days in the current-year and prior-year three-month periods were comparable. The increase in Electric Utility revenues reflects the effects of slightly higher average default service (“DS”) rates, reflecting the pass through of slightly higher electricity costs, and the effects of the slightly higher sales. Electric Utility cost of sales increased to $12.0 million in the 2013 three-month period from $11.3 million in the 2012 three-month period principally reflecting the effects of the greater DS rates and the higher sales.

Electric Utility total margin and operating income in the 2013 three-month period were equal to the prior-year period.

Interest Expense and Income Taxes. Our consolidated interest expense in the 2013three-month period was lower than the prior year principally reflecting lower average long-term debt outstanding. Our effective income tax rate for the three months ended June 30, 2013, was slightly higher than in the prior-year period as the prior-year period reflects the regulatory effects of greater state tax depreciation.

2013 nine-month period compared with 2012 nine-month period

							Increase
Nine Months Ended June 30,	2013			2012			(Decrease)
(Millions of dollars)
Gas Utility:
Revenues	$	743.6		$	696.8		$	46.8		6.7	%
Total margin (a)	$	370.9		$	326.2		$	44.7		13.7	%
Operating income	$	191.6		$	168.7		$	22.9		13.6	%
Income before income taxes	$	163.5		$	138.6		$	24.9		18.0	%
System throughput — billions of cubic feet (“bcf”)
Core market	65.4			54.7			10.7			19.6	%
Total	158.5			146.0			12.5			8.6	%
Heating degree days — % (warmer) than normal (b)	(1.2		)%	(16.6		)%	—			—
Electric Utility:
Revenues	$	73.6		$	71.9		$	1.7		2.4	%
Total margin (a)	$	26.9		$	26.1		$	0.8		3.1	%
Operating income	$	8.6		$	9.1		$	(0.5	)	(5.5	)%
Income before income taxes	$	7.1		$	7.4		$	(0.3	)	(4.1	)%
Distribution sales — millions of kilowatt-hours (“gwh”)	753.4			724.0			29.4			4.1	%

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UGI UTILITIES, INC. AND SUBSIDIARIES

(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 $4.0 million during each of the nine-month periods ended June 30, 2013 and 2012. 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 NOAA for airports located within Gas Utility’s service territory.

Gas Utility. Temperatures in the Gas Utility service territory in the 2013 nine-month period based upon heating degree days were 1.2% warmer than normal but 14.9% colder than the prior-year period. Total distribution system throughput increased principally reflecting significantly higher throughput to core market customers and, to a lesser extent, greater net volumes associated with lower margin firm and interruptible delivery service customers. Gas Utility system throughput to core-market customers was above last year principally reflecting the effects of the significantly colder weather and, to a much lesser extent, customer growth, principally conversions from oil prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $46.8 million during the 2013 nine-month period principally reflecting higher revenues from core market customers ($44.2 million) and higher large firm delivery service revenues ($7.7 million) partially offset by lower off-system sales revenues ($6.1 million). The increase in core market revenues principally reflects the effects of the higher core market volumes on PGC revenues ($52.0 million) and greater core market delivery service revenues partially offset by the effects of lower average PGC rates on retail core-market revenues ($46.7 million). Gas Utility’s cost of gas was $372.7 million in the 2013 nine-month period compared with $370.6 million in the prior-year period principally reflecting the effects on cost of sales of the greater retail core-market volumes ($52.0 million) substantially offset by the effects of lower average PGC rates ($46.7 million) and the lower off-system sales.

Gas Utility total margin increased $44.7 million in the 2013 nine-month period principally reflecting higher core market margin ($34.5 million) and higher large firm delivery service total margin ($8.1 million). The higher core market total margin reflects the effects of the greater core market volumes.

The increase in Gas Utility operating income during the 2013 nine-month period principally reflects the increase in total margin ($44.7 million) partially offset by higher operating and administrative expenses ($17.0 million) including, among other things, higher pension and benefits expenses ($3.0 million), higher uncollectible accounts expenses ($2.8 million) on higher core market volumes, and greater injuries and damages and distribution system expenses ($4.0 million). The greater income before income taxes in the 2013 nine-month period reflects the higher operating income ($22.9 million) and slightly lower interest expense on lower long-term debt outstanding.

Electric Utility. Temperatures based upon heating degree days during the 2013 nine-month period were approximately 2.5% warmer than normal but approximately 17% colder than the prior-year period. The increase in revenues reflects the effects of the higher sales principally a result of the colder weather partially offset by lower average DS rates reflecting the pass through of lower electricity costs. Electric Utility cost of sales increased to $42.7 million in the 2013 nine-month period compared to $41.8 million in the 2012 nine-month period principally reflecting the effects of the greater sales offset by the lower average DS rates.

Electric Utility total margin increased $0.8 million in the 2013 nine-month period reflecting in large part the higher distribution sales and greater transmission revenue.

Notwithstanding the increase in total margin, Electric Utility 2013 nine-month period operating income and income before income taxes decreased reflecting greater operating and administrative costs including distribution system repair and maintenance costs principally associated with Hurricane Sandy early in the 2013 nine-month period.

Interest Expense and Income Taxes. Our consolidated interest expense in the 2013 nine-month period was lower than the prior-year period on lower long-term debt outstanding. Our effective income tax rate for the nine months ended June 30, 2013, was slightly higher than in the prior-year period as the prior-year period reflects the regulatory effects of greater state tax depreciation.

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

The Company’s total debt outstanding at June 30, 2013, was $600 million compared to debt outstanding of $609.2 million at September 30, 2012, which amount includes $9.2 million of bank loans. UGI Utilities’ total debt outstanding at June 30, 2013, comprises $383 million of Senior Notes and $217 million of Medium-Term Notes.

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UGI UTILITIES, INC. AND SUBSIDIARIES

UGI Utilities may borrow up to a total of $300 million under its credit agreement (“2011 Credit Agreement”). The 2011 Credit Agreement expires in October 2015. There were no amounts outstanding under the 2011 Credit Agreement at June 30, 2013. During the 2013 and 2012nine-month periods, average daily bank loan borrowings were $27.3 million and $21.3 million, respectively, and peak bank loan borrowings totaled $79 million and $70.6 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January.

We believe that we have sufficient liquidity in the forms of cash and cash equivalents on hand, cash expected to be generated from Gas Utility and Electric Utility operations, and bank loan borrowings available under the 2011 Credit Agreement to meet our anticipated contractual and projected cash commitments. In addition, UGI Utilities has an aggregate $133 million of Senior Notes and Medium-Term Notes maturing late in Fiscal 2013 which UGI Utilities intends to refinance on a long-term basis.

Cash Flows

Operating activities. Due to the seasonal nature of UGI Utilities’ businesses, cash flows from our operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas and electricity consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally accounts receivable and inventories, is generally greatest. UGI Utilities uses borrowings under the 2011 Credit Agreement to manage seasonal cash flow needs.

Cash provided by operating activities was $188.6 million in the 2013 nine-month period compared to $202.6 million in the prior-year nine-month period. Cash flow from operating activities before changes in operating working capital was $178.1 million in the 2013 nine-month period compared to $142.5 million recorded in the prior-year nine-month period principally reflecting the greater 2013 nine-month period operating results and lower pension plan contributions. Changes in operating working capital provided $10.6 million of operating cash flow during the 2013 nine-month period compared to $60.1 million of cash provided during the prior-year nine-month period. The lower cash from changes in operating working capital in the 2013 nine-month period reflects, among other things, greater cash required to fund changes in accounts receivable principally resulting from the greater sales in the current-year period and lower cash from changes in inventories. The effect of these changes in working capital were partially offset, among other things, by the timing and amount of cash provided by changes in deferred fuel collections and current income taxes.

Investing activities. Cash used by investing activities was $99.7 million in the 2013 nine-month period compared to $79.4 million in the 2012 nine-month period. Total capital expenditures were $94.5 million in the 2013 nine-month period compared with $79.7 million recorded in the prior-year period. The 2013 nine-month period principally reflects higher Gas Utility capital expenditures. Changes in restricted cash in futures brokerage accounts required $2.6 million of cash compared with $2.7 million of cash provided in the prior-year period.

Financing activities. Cash used by financing activities was $8.2 million in the 2013 nine-month period compared with cash used by financing activities of $54.5 million in the 2012 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. During the 2013 nine-month period there were net bank loan repayments of $9.2 million compared with no net borrowings or repayments during the prior-year nine-month period. Cash dividends in the prior-year nine-month period totaled $54.8 million. There have been no cash dividends paid during the nine months ended June 30, 2013.

Regulatory Matters

On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff’s formal complaint, issued on June 11, 2012, pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $0.4 million to $0.5 million; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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UGI UTILITIES, INC. AND SUBSIDIARIES

Our primary market risk exposures are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers, including the cost of financial instruments used to hedge purchased gas costs. 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 NYMEX to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these 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, 2013, UGI Utilities had $2.6 million of restricted cash associated with futures accounts. At June 30, 2012, UGI Utilities had $1.6 million of restricted cash associated with natural gas futures accounts with brokers. At June 30, 2013 and 2012, the fair values of our natural gas futures and option contracts were net (losses) gains of $(1.4) million and $0.3 million, respectively.

Electric Utility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, 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. At June 30, 2013 and 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $6.1 million and $13.1 million, respectively. At June 30, 2013 and 2012, the fair values of FTRs were not material.

In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). The fair values of unsettled IRPAs held at June 30, 2013 and 2012, were net losses of $7.2 million and $28.9 million, respectively. A hypothetical 10% adverse change in the six-month LIBOR would result in a decrease in fair value of $9.2 million at June 30, 2013.

In addition, 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, 2013 and 2012, were not material.

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UGI UTILITIES, INC. AND SUBSIDIARIES

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, 2012, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

ITEM 6. EXHIBITS

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

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.1	UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.
10.2	UGI Corporation Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.	UGI	Form 10-Q (6/30/2013)	10.1
10.3	Letter Agreement, dated as of June 10, 2013, amending SST Service Agreement No. 79133 dated March 29, 2012 between Columbia Gas Transmission, LLC and UGI Utilities, Inc.
10.4	FTS Service Agreement No. 46284 dated July 23, 2013 between Columbia Gas Transmission, LLC and UGI Utilities, Inc.	UGI Utilities, Inc.	Form 8-K (7/23/2013)	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, 2013, 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, 2013, 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, 2013, 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 Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

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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 2, 2013	By:	/s/ Donald E. Brown
			Donald E. Brown Vice President - Finance and Chief Financial Officer
Date:	August 2, 2013	By:	/s/ Matthew J. Nolan
			Matthew J. Nolan  Controller

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UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX

10.1	UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.
10.3	Letter Agreement, dated as of June 10, 2013, amending SST Service Agreement No. 79133 dated March 29, 2012 between Columbia Gas Transmission, LLC and UGI Utilities, Inc.
12.1	Computation of ratio of earnings to fixed charges.
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, 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, 2013, 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, 2013, 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 Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

EX-10.1

EXHIBIT 10.1

UGI UTILITIES, INC.

SENIOR EXECUTIVE EMPLOYEE

SEVERANCE PLANAs amended as of November 16, 2012

UGI UTILITIES, INC.

SENIOR EXECUTIVE EMPLOYEE

SEVERANCE PLAN

TABLE OF CONTENTS

Page

Article I	Purpose and Term of Plan	1
Article II	Definitions	2
Article III	Participation and Eligibility for Benefits	6
Article IV	Benefits	8
Article V	Method and Duration of Benefit Payments	11
Article VI	Administration	12
Article VII	Amendment and Termination	14
Article VIII	Duties of the Company	15
Article IX	Claims Procedures	16
Article X	Miscellaneous	18
Appendix A	Change in Control	A-1

i

ARTICLE I

PURPOSE AND TERM OF PLAN

Section 1.01Purpose of the Plan. This Senior Executive Employee Severance Plan is applicable to Executive Employees (as defined below) of UGI Utilities, Inc. and its Affiliates (as defined below). The Plan is intended to help alleviate financial hardships that may be experienced by Executive Employees whose employment is involuntary terminated. The Plan is intended to be a “severance pay plan” for purposes of ERISA (as defined below). The benefits paid by the Plan are not deferred compensation, and no employee shall have a vested right to such benefits. The Plan has been drafted to give the Company (as defined below) broad discretion in designating individuals who are eligible for benefits and the amount of such benefits. All actions taken by the Company shall be in its role as the plan sponsor and not as a fiduciary.

Section 1.02Term of the Plan. The Plan has been amended and restated as of November 16, 2012. The Plan will continue until such time as the Company, acting in its sole discretion, elects to modify, supersede or terminate it in accordance with the further provisions hereof.

1

ARTICLE II

DEFINITIONS

Section 2.01“Administrative Committee” shall mean the administrative committee designated pursuant to Article VI of the Plan to administer the Plan in accordance with its terms, or its delegate.

Section 2.02“Affiliate” shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended.

Section 2.03“Annual Compensation” shall mean the Participant’s annual base salary and applicable target annual bonus amount (if any) in effect on the Participant’s Employment Termination Date.

Section 2.04“Benefit” or “Benefits” shall mean any or all of the benefits that a Participant is entitled to receive pursuant to Article IV of the Plan.

Section 2.05“Board of Directors” shall mean the Board of Directors of the Company, or any successor thereto.

Section 2.06“Change in Control” shall mean a change of control of the Company or UGI Corporation as defined in the attached Appendix A, as amended from time to time by the Committee, in its discretion.

Section 2.07“Change in Control Agreement” shall mean a written Change in Control Agreement between an employee and the Company or an Affiliate.

Section 2.08“Chief Executive Officer” shall mean the individual serving as the Chief Executive Officer of the Company as of the date of reference.

Section 2.09“COBRA Cost” shall mean the applicable premium under section 4980B(f)(4) of the Code for continued medical and dental COBRA coverage under the benefit plans of the Company or an Affiliate.

Section 2.10“COBRA Coverage” shall mean continued medical and dental coverage under benefit plans of the Company or an Affiliate, as determined under section 4980B of the Code.

Section 2.11“Code” shall mean the Internal Revenue Code of 1986, as amended.

Section 2.12“Company” shall mean UGI Utilities, Inc. and any corporation succeeding to the business of UGI Utilities, Inc. by merger, consolidation, liquidation, purchase of assets or stock or similar transaction.

2

Section 2.13“Compensation Committee” shall mean the Compensation and Management Development Committee of the Board of Directors.

Section 2.14“Employment Commencement Date” shall mean the most recent date on which a Participant became an employee of the Company or an Affiliate of the Company or, if the Company determines that service before an acquisition shall be taken into account, the most recent date on which a Participant became an employee of an entity whose business or assets have been acquired by the Company or an Affiliate.

Section 2.15“Employment Termination Date” shall mean the date on which the Participant separates from service with the Company and its Affiliates within the meaning of section 409A of the Code.

Section 2.16“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended.

Section 2.17“Executive Annual Bonus Plan” shall mean the UGI Utilities, Inc. Executive Annual Bonus Plan as in effect from time to time.

Section 2.18“Executive Employee” shall mean any of the following employees who are employed in the United States:

(a)An executive level employee of the Company who participates in the Executive Annual Bonus Plan and who has a Change in Control Agreement in effect with the Company or an Affiliate; or

(b)An executive level employee of the Company or an Affiliate who is employed in the United States and who is designated in writing by the Compensation Committee as eligible to participate in this Plan.

Notwithstanding the foregoing, if an employee is employed by more than one company within the UGI Corporation controlled group and if the Company is not the employee’s primary employer, the employee shall not be eligible to participate in this Plan, unless otherwise designated in writing by the Compensation Committee. In no event shall any of the following persons be considered an employee for purposes of the Plan: (i) employees who are employed outside the United States, (ii) independent contractors, (iii) persons performing services pursuant to an arrangement with a third party leasing organization, (iv) any person whom the Company determines, in its sole discretion, is not a common law employee, whether or not any such person is later determined to have been a common law employee of the Company or an Affiliate, or (v) employees who are eligible to participate in another severance plan maintained by the Company or an Affiliate.

Section 2.19“Executive Equity Plan” shall mean any long-term equity incentive plan of the Company or any of its Affiliates, including without limitation the UGI Corporation 2004 Omnibus Equity Compensation Plan, the UGI Corporation 2013 Omnibus Incentive

3

Compensation Plan, the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan, and the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan.

Section 2.20“Just Cause” shall mean dismissal of an Executive Employee due to (i) misappropriation of funds, (ii) substance abuse or habitual insobriety that adversely affects the Executive Employee’s ability to perform his or her job, (iii) conviction of a crime involving moral turpitude, or (iv) gross negligence in the performance of duties. Disputes with respect to whether Just Cause exists shall be resolved in accordance with Article IX.

Section 2.21“Key Employee” shall mean an employee who, at any time during the 12-month period ending on the identification date, is a “specified employee” under section 409A of the Code, as determined by the Compensation Committee or its delegate. The determination of Key Employees, including the number and identity of persons considered specified employees and the identification date, shall be made by the Compensation Committee or its delegate in accordance with the provisions of section 409A of the Code and the regulations issued thereunder.

Section 2.22“Month of Service” shall mean each calendar month (with each partial month counted as a full month) of continuous service with the Company and its Affiliates beginning on the Participant’s Employment Commencement Date and ending on the Participant’s Employment Termination Date. Months of Service with an entity whose business or assets have been acquired by the Company or an Affiliate shall be counted only if so determined by the Company.

Section 2.23“Monthly Compensation” shall mean the Participant’s Annual Compensation divided by 12.

Section 2.24“Paid Notice” shall mean the cash amount payable to a Participant in lieu of notice as determined pursuant to Section 4.01(a).

Section 2.25“Participant” shall mean any Executive Employee who receives Benefits under the Plan.

Section 2.26“Plan” shall mean the UGI Utilities, Inc. Senior Executive Employee Severance Plan, as set forth herein, and as the same may from time to time be amended.

Section 2.27“Plan Year” shall mean each fiscal year of the Company during which this Plan is in effect.

Section 2.28“Postponement Period” shall mean, for a Key Employee, the period of six months after separation from service (or such other period as may be required by section 409A of the Code), during which deferred compensation may not be paid to the Key Employee under section 409A of the Code.

Section 2.29“Release” shall mean a release and discharge of the Company, all of its Affiliates, and all affiliated persons and entities from any and all claims, demands and causes of

4

action, other than as to amounts or benefits due to the Participant under any qualified employee retirement plan of the Company or an Affiliate, which shall be in such form as may be proscribed by the Company, acting as Plan sponsor and not as a fiduciary, from time to time and with such modifications as the Company deems appropriate for the Participant’s particular situation.

Section 2.30“Restricted Awards” shall mean restricted stock, stock units, performance units, restricted units, dividend equivalents, distribution equivalents and other equity-based awards, other than stock options, that are granted to a Participant under an Executive Equity Plan.

Section 2.31“Salary Continuation Period” shall mean (i) the number of months of Paid Notice plus (ii) one business day for each month that is included in the Participant’s Months of Service, up to a maximum of one year. Each calendar week is considered to consist of five business days for this purpose.

Section 2.32“Separation Pay” shall mean the cash amount payable to a Participant as determined pursuant to Section 4.01(b).

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ARTICLE III
PARTICIPATIONAND ELIGIBILITY FOR BENEFITS

Section 3.01General Eligibility Requirement. In its sole discretion, acting in its role as Plan sponsor and not as a fiduciary, the Company may grant a Benefit under this Plan to any Executive Employee whose employment is terminated by the Company or an Affiliate other than for Just Cause, death, or continuous illness, injury or incapacity for a period of six consecutive months. Notwithstanding anything herein to the contrary, an Executive Employee will not be considered to have incurred a termination by the Company or an Affiliate for purposes of this Plan if his or her employment is discontinued due to voluntary resignation or the expiration of a leave of absence, as determined by the Company, acting in its role as Plan sponsor and not as a fiduciary. In addition, the Executive Employee must meet the requirements of Section 3.03 in order to receive a Benefit under this Plan.

Section 3.02Substantially Comparable Employment. Notwithstanding anything herein to the contrary, no Benefits shall be due hereunder to an Executive Employee in connection with the disposition of a business, division or affiliated company by the Company or an Affiliate if substantially comparable terms of employment, as determined by the Company, have been offered to the Executive Employee by the transferee; provided, however, that the Company, acting in its role as Plan sponsor and not as a fiduciary, may determine that the Company or an Affiliate will provide some or all of the Benefits to an Executive Employee whose employment with the Company and its Affiliates is terminated as described in Section 3.01. For purposes of this Plan, “substantially comparable terms of employment” shall mean an executive level position with (i) no reduction in the Executive Employee’s annual base salary as of the date of the transaction, and (ii) no material change in the geographic location at which the Executive Employee must perform services (which, for purposes of this Plan, means a location that is not more than 50 miles from the Executive Employee’s principal place of business immediately before the transaction).

Section 3.03Conditions to Entitlement to Benefits.

(a)As further conditions to entitlement to Benefits under the Plan, all Participants must, prior to the payment of any Benefits due hereunder, (i) sign and not rescind or contest the enforceability of a Release; (ii) ratify any patent assignment, confidentiality, non-solicitation, non-competition and other post-employment activities agreement in effect between the Participant and the Company or an Affiliate; (iii) return to the Company and its Affiliates any and all property of the Company and its Affiliates held by the Participant, including, but not limited to, all reports, manuals, memoranda, computer disks, tapes and data made available to the Participant during the performance of the Participant’s duties, including all copies; (iv) hold confidential any and all information concerning the Company and its Affiliates, whether with respect to its business, subscribers, providers, customers, operations, finances, employees, contractors, or otherwise; and (v) cooperate fully with the Company and its Affiliates to complete the transition of matters with which the Participant is familiar or responsible to other employees and make himself or herself available to answer questions or assist in matters which may require

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attention after the Participant’s Employment Termination Date. Notwithstanding the foregoing, accrued vacation described in Section 4.01(d) shall be paid without regard to the Participant’s execution of a Release, to the extent required by applicable state law.

(b)If the Administrative Committee determines, in its sole discretion, that the Participant has violated one or more of the foregoing conditions to entitlement to Benefits, the Administrative Committee may determine that the Participant will not receive the Benefits or the Company may discontinue the payment of Benefits under the Plan. Any remedy under this Section 3.03 shall be in addition to, and not in place of, any other remedy the Company and its Affiliates may have, at law or otherwise.

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ARTICLE IV

BENEFITS

Section 4.01Amount of Immediate Cash Benefit. The Company, acting in its role as Plan sponsor and not as a fiduciary, shall determine which Executive Employees shall be awarded a Benefit hereunder and the amount of any such Benefit. The Company may take into account any factors it determines to be relevant in deciding which Executive Employees shall be awarded Benefits and the amount of such Benefits, and need not apply its determinations in a uniform manner to terminated Executive Employees similarly situated. All such decisions shall be final, binding and conclusive with respect to the Executive Employee. Unless the Company determines otherwise, subject in all events to Section 3.03, the amount to be paid to a Participant eligible to receive Benefits under Section 3.01 hereof upon the Participant’s separation from service shall be paid in a lump sum as provided in Section 5.01 hereof and shall equal the sum of the amounts described in subsections (a) through (d), less the amount described in subsection (e), except that any payment under paragraph (c) below will be excluded from the lump sum payment and paid separately as provided below:

(a)Paid Notice as follows:

(i)In the case of the Chief Executive Officer, an amount of Paid Notice equal to 12 months of the Chief Executive Officer’s Monthly Compensation.

(ii)In the case of all other Participants, an amount of Paid Notice equal to six months of the Participant’s Monthly Compensation, unless otherwise designated in writing by the Company.

(b)An amount of Separation Pay equal to one day’s pay (calculated by dividing the Participant’s Annual Compensation by 260) for each Month of Service; provided, however, that such amount shall not exceed 100% of the Participant’s Annual Compensation.

(c)The Administrative Committee may determine in its sole discretion that an annual bonus will be paid for the year of termination. The Administrative Committee may take into account factors such as Company and Affiliate performance, individual performance and the portion of the year elapsed prior to the Employment Termination Date. The annual bonus shall not exceed a pro rata portion of the Participant’s target annual bonus for the year of termination. The bonus, if any, shall be paid within 60 days after the Employment Termination Date, unless the Executive Annual Bonus Plan in effect for the year specifically provides otherwise with respect to termination of employment. If a bonus is payable to the Participant under the Executive Annual Bonus Plan for the year of termination, no bonus will be payable under this Plan.

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(d)An amount equal to the Participant’s earned and accrued vacation entitlement, including banked vacation time, and personal holidays through the Participant’s Employment Termination Date.

(e)If the Participant’s employment with the Company and its Affiliates terminates before a Change in Control, the cash amount computed in subsections (a) through (c) above shall be reduced by the amount of cash and the fair market value of any stock, partnership units or other property that is payable to the Participant under Restricted Awards after the Participant’s termination of employment, as determined by the Company, provided that the Restricted Awards are not considered deferred compensation under section 409A of the Code. In order to implement this reduction, if the Company cannot determine the amount payable under Restricted Awards at the Participant’s Employment Termination Date, any amounts payable under such Restricted Awards shall be reduced by the amount of the Benefit paid under subsections (a) through (c) above, provided the Restricted Awards are not considered deferred compensation under section 409A of the Code. In no event shall a Participant be required to return to the Company or an Affiliate any amounts previously paid under this Plan.

(f)The reduction described in subsection (e) shall not apply if the Participant’s employment with the Company and its Affiliates terminates at or after a Change in Control. In addition, the reduction described in subsection (e) shall not apply to any Restricted Awards for which all requirements for payment have been met before the Participant’s Employment Termination Date (for example, if the restriction period for a Restricted Award ends on December 31, 2013, the Restricted Award is payable on February 1, 2014 and the Participant’s employment is terminated on January 15, 2014, the Restricted Award shall not be reduced by the Benefits under this Plan).

Section 4.02Executive Benefits.

(c)If a Participant receives Benefits under Section 4.01, the Company shall pay to the Participant a single lump sum payment, as provided in Section 5.01 and subject to Section 3.03, equal to the COBRA Cost that the Participant would incur if the Participant continued medical and dental coverage under the Company’s benefit plans through the end of the Salary Continuation Period, based on the benefits in effect for the Participant (and where applicable, his or her spouse and dependents) at the Participant’s Employment Termination Date, less the amount that the Participant would be required to contribute for medical and dental coverage if such Participant were an active employee. The cash payment shall include an additional payment equal to 75% of the lump sum payment described in the preceding sentence.

(d)A Participant who receives Benefits under Section 4.01 may elect continuation coverage under the Company’s applicable medical and dental plans during the Salary Continuation Period by paying the COBRA Cost of such coverage, provided such continued coverage would not result in adverse tax consequences to the Participant, Company or an Affiliate and provided such continued coverage is permitted under the applicable medical and dental plans. If the Participant elects such coverage,the Participant shall be responsible for paying the COBRA Cost of such coverage during the Salary Continuation Period in order to be eligible for the coverage. Notwithstanding anything herein to the contrary, any such continued

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coverage shall be discontinued if, and at the time, the Participant obtains other employment and becomes eligible to participate in the plan of, or is provided similar coverage by, a new employer. Any applicable conversion rights shall be provided to the Participant at the time coverage ceases.COBRA Coverage shall run concurrently with the Salary Continuation Period, and nothing in this Section shall limit the Employee’s right to elect COBRA Coverage for the full period permitted by law.

(e)If a Participant who receives Benefits under Section 4.01 is entitled to receive tax preparation services immediately before his or her termination of employment, the Participant shall be entitled to receive tax preparation services for the final calendar year of his or her employment under the terms of the Company’s tax preparation reimbursement policy. The Company shall reimburse the Participant for the services within 60 days following the Company’s receipt of proof of payment for the services, but in no event later than December 31 of the calendar year following the calendar year in which the expense is incurred, provided that the Company receives proof of payment for the services at least 60 days before such December 31.

(f)The Company shall provide to each Participant who receives benefits under Section 4.01 outplacement services for up to 12 months following his or her Employment Termination Date through a vendor selected by the Company.

Section 4.03Retirement Plans. This Plan shall not govern and shall in no way affect the Participant’s interest in, or entitlement to benefits under, any of the qualified retirement plans of the Company or an Affiliate and any payments received under any such plan shall not affect a Participant’s right to any Benefit hereunder.

Section 4.04Effect on Other Benefits.

(a)After a Participant’s termination of employment, the Participant shall not accrue benefits under any benefit plan of the Company or an Affiliate, and a terminated Participant shall not accrue vacation days, paid holidays, paid sick days or other benefits for any part of the Salary Continuation Period.

(b)Notwithstanding anything in this Plan to the contrary, no benefits shall be paid under this Plan if the Participant receives severance benefits under a Change in Control Agreement or any other severance agreement or arrangement with the Company or an Affiliate.

(c)Notwithstanding anything herein to the contrary, the Benefits payable under this Plan to any Participant may be reduced by any and all payments required to be made by the Company or an Affiliate under federal, state and local law, including the Worker Adjustment and Retraining Notification Act, 29 U.S.C. Section 2101 et. seq. or under any employment agreement or special severance arrangement, as determined by the Company, acting as Plan sponsor and not as a fiduciary.

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ARTICLE V

METHOD AND DURATION OF BENEFIT PAYMENTS

Section 5.01Method of Payment. The cash Benefit to which a Participant is entitled, pursuant to Article IV, shall be paid in a lump sum payment. Payment shall be made within 60 days following the Participant’s Employment Termination Date, subject to the fulfillment of all conditions for payment of the Benefit set forth in Section 4.01 and compliance with all requirements of Section 3.03. Payment shall be made by mail to the last address provided by the Participant to the Company or an Affiliate. All payments under the Plan are subject to applicable federal, state and local taxes.

Section 5.02Section 409A.

(a)Notwithstanding any provision of the Plan to the contrary, if required by section 409A of the Code and if a Participant is a Key Employee, no Benefits shall be paid to the Participant during the Postponement Period. If a Participant is a Key Employee and payment of Benefits is required to be delayed for the Postponement Period under section 409A, the accumulated amounts withheld on account of section 409A of the Code shall be paid in a lump sum payment within 30 days after the end of the Postponement Period. If the Participant dies during the Postponement Period prior to the payment of Benefits, the amounts withheld on account of section 409A of the Code shall be paid to the Participant’s estate within 60 days after the Participant’s death.

(b)This Agreement is intended to meet the requirements of the “short-term deferral” exception, the “separation pay” exception and other exceptions under section 409A of the Code. Notwithstanding anything in this Plan to the contrary, if required by section 409A, payments may only be made under this Plan upon an event and in a manner permitted by section 409A, to the extent applicable. As used in the Plan, the term “termination of employment” shall mean the Participant’s separation from service with the Company and its Affiliates within the meaning of section 409A and the regulations promulgated thereunder. For purposes of section 409A, the right to a series of payments under the Plan shall be treated as a right to a series of separate payments. All reimbursements and in-kind benefits provided under the Plan shall be made or provided in accordance with the requirements of section 409A of the Code. In no event may a Participant designate the year of payment for any amounts payable under the Plan. Notwithstanding any provision of the Plan to the contrary, if the payments and benefits provided for under the Plan are subject to section 409A, in no event shall the timing of a Participant’s execution of the Release, directly or indirectly, result in the Participant designating the calendar year of payment, and if a payment that is subject to execution of the Release could be made in more than one taxable year, payment shall be made in the later taxable year.

Section 5.03Payments After Death. If a Participant dies after separation from service and before the Participant has received any Benefit that the Participant is entitled to receive under Article IV, any unpaid Benefit that the Participant would otherwise have received shall be payable to the Participant’s estate.

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ARTICLE VI

ADMINISTRATION

Section 6.01Appointment. The Administrative Committee shall consist of one or more persons appointed by the Compensation Committee. Administrative Committee members may be, but need not be, employees of the Company.

Section 6.02Tenure. Administrative Committee members shall serve at the pleasure of the Compensation Committee. Administrative Committee members may resign at any time on ten days’ written notice, and Administrative Committee members may be discharged, with or without cause, at any time by the Compensation Committee.

Section 6.03Authority and Duties. It shall be the duty of the Administrative Committee, on the basis of information supplied to it by the Company, to determine the eligibility of each Participant for Benefits under the Plan, to determine the amount of Benefits to which each such Participant may be entitled, and to determine the manner, time of payment and other requirements of payment of Benefits consistent with the provisions hereof. The Company shall make such payments as are certified to it by the Administrative Committee to be due to Participants. The Administrative Committee shall have the full power and discretionary authority to construe, interpret and administer the Plan, to correct deficiencies therein, and to supply omissions. All decisions, actions, and interpretations of the Administrative Committee shall be final, binding, and conclusive upon the parties. The Administrative Committee may delegate ministerial and other responsibilities to one or more employees of the Company or its Affiliates.

Section 6.04Action by the Administrative Committee. A majority of the members of the Administrative Committee shall constitute a quorum for the transaction of business at a meeting of the Administrative Committee. Any action of the Administrative Committee may be taken upon the affirmative vote of a majority of the members of the Administrative Committee at a meeting, or at the direction of the Chairperson, without a meeting, by mail, telephone, or electronic communication; provided that all of the members of the Administrative Committee are informed of their right to vote on the matter before the Administrative Committee and of the outcome of the vote thereon.

Section 6.05Officers of the Administrative Committee. The Administrative Committee shall designate one of its members to serve as Chairperson thereof. The Administrative Committee shall also designate a person to serve as Secretary of the Administrative Committee, which person may be, but need not be, a member of the Administrative Committee.

Section 6.06Compensation of the Administrative Committee. Members of the Administrative Committee shall receive no compensation for their services as such. However, all reasonable expenses of the Administrative Committee shall be paid or reimbursed by the Company upon proper documentation. The Company shall indemnify members of the Administrative Committee against personal liability for actions taken in good faith in the discharge of their respective duties as members of the Administrative Committee.

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Section 6.07Records, Reporting, and Disclosure. The Administrative Committee shall keep all individual and group records relating to Participants and former Participants and all other records necessary for the proper operation of the Plan. Such records shall be made available to the Company and its Affiliates and to each Participant for examination during business hours except that a Participant shall examine only such records as pertain exclusively to the examining Participant and to the Plan. The Administrative Committee shall prepare and shall file as required by law or regulation all reports, forms, documents and other items required by ERISA, the Code, and every other relevant statute, each as amended, and all regulations thereunder (except that the Company or an Affiliate, as payor of the Benefits, shall prepare and distribute to the proper recipients all forms relating to withholding of income or wage taxes, Social Security taxes, and other amounts which may be similarly reportable).

Section 6.08Actions of the Administrative Committee. All determinations made by the Administrative Committee under the Plan shall be made solely at the discretion of the Administrative Committee. The exercise of discretion by the Administrative Committee need not be uniformly applied to similarly situated Participants and shall be final and binding on each Participant or beneficiary to whom the determination is directed.

Section 6.09Benefits of the Chief Executive Officer. Notwithstanding the foregoing, the Compensation Committee shall serve as the Administrative Committee under the Plan with respect to the Chief Executive Officer of the Company. The Compensation Committee shall make all determinations with respect to the Chief Executive Officer as to any matter that directly pertains to, or affects, the Chief Executive Officer.

Section 6.10Bonding. The Administrative Committee shall arrange any bonding that may be required by law, but no amount in excess of the amount required by law (if any) shall be required by the Plan.

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ARTICLE VII
AMENDMENT AND TERMINATION

Section 7.01Amendment, Suspension and Termination. The Company, by action of its Board of Directors or the Compensation Committee, retains the right, at any time and from time to time, to amend, suspend or terminate the Plan in whole or in part, for any reason, and without either the consent of or the prior notification to any Participant. No such amendment shall give the Company or an Affiliate the right to recover any amount paid to a Participant prior to the date of such amendment or to cause the cessation and discontinuance of payments of Benefits to any person or persons under the Plan already receiving Benefits.

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ARTICLE VIII
DUTIES OF THE COMPANY

Section 8.01Records. The Company shall supply to the Administrative Committee all records and information necessary to the performance of the Administrative Committee’s duties.

Section 8.02Payment. The Company shall make payments from its general assets to Participants in accordance with the terms of the Plan, as directed by the Administrative Committee.

Section 8.03Discretion, Delegation.

(a)Any decisions, actions or interpretations to be made under the Plan by the Company shall be made in its sole discretion, not in any fiduciary capacity and need not be uniformly applied to similarly situated individuals, and such decisions, actions or interpretations shall be final, binding and conclusive upon all parties.

(b)The Company may take actions under the Plan by action of its Board of Directors or the Compensation Committee, or by action of any officer or committee to whom any of the Company’s authority with respect to the Plan shall have been delegated. The Compensation Committee shall be authorized to take all Company actions under the Plan with respect to the Chief Executive Officer.

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ARTICLE IX

CLAIMS PROCEDURES

Section 9.01Application for Benefits. Participants who believe they are eligible for benefits under this Plan may apply for such benefits by completing and filing with the Administrative Committee an application for benefits on a form supplied by the Administrative Committee. Before the date on which benefit payments commence, each such application must be supported by such information as the Administrative Committee deems relevant and appropriate.

Section 9.02Claim. A terminated employee may contest his or her eligibility for the amount of benefit awarded by completing and filing with the Administrative Committee a written request for review in the manner specified by the Administrative Committee. Each such application must be supported by such information as the Administrative Committee deems relevant and appropriate. The Administrative Committee will review the claim and provide notice to the terminated employee, in writing, within 90 days after the claim is filed unless special circumstances require an extension of time for processing the claim. In no event shall the extension exceed a period of 90 days from the end of the initial period. In the event that any claim for benefits is denied in whole or in part, the terminated employee whose claim has been so denied shall be notified of such denial in writing by the Administrative Committee. The notice advising of the denial shall be written in a manner calculated to be understood by the terminated employee and shall set forth: (i) specific references to the pertinent Plan provisions on which the denial is based; (ii) a description of any additional material or information necessary for the claimant to perfect the claim and an explanation as to why such information is necessary; and (iii) an explanation of the Plan’s claim procedure and the time limits applicable to such procedures, including a statement of the claimant’s right to bring a civil action under section 502(a) of ERISA following an adverse benefit determination on appeal.

Section 9.03Appeals of Denied Claims for Benefits. All appeals shall be made by the following procedure:

(a)The terminated employee whose claim has been denied shall file with the Administrative Committee a notice of appeal of the denial. Such notice shall be filed within 60 days of notification by the Administrative Committee of the claim denial, shall be made in writing, and shall set forth all of the facts upon which the appeal is based. Appeals not timely filed shall be barred.

(b)The claimant or his duly authorized representative may:

(i)request a review upon written notice to the Administrative Committee;

(ii)examine the Plan and obtain, upon request and without charge, copies of all information relevant to the claimant’s appeal; and

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(iii)submit issues and comments in writing.

(c)The Named Appeals Fiduciary (as described in Section 9.04) shall issue a decision no later than 60 days after receipt of a request for review unless special circumstances, such as the need to hold a hearing, require a longer period of time, in which case a decision shall be rendered as soon as possible, but not later than 120 days after receipt of the terminated employee’s notice of appeal.

(d)The Named Appeals Fiduciary shall consider the merits of the claimant’s written presentations, the merits of any facts or evidence in support of the denial of benefits, and such other facts and circumstances as the Named Appeals Fiduciary shall deem relevant.

(e)The Named Appeals Fiduciary shall render a determination upon the appealed claim which determination shall be accompanied by a written statement setting forth:

(i)specific reasons for the decision, written in a manner calculated to be understood by the claimant;

(ii)specific references to the pertinent Plan provisions on which the decision is based;

(iii)the claimant’s right to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claim for benefits; and

(iv)the claimant’s right to bring a civil action under section 502(a) of ERISA.

Section 9.04Appointment of the Named Appeals Fiduciary. The Named Appeals Fiduciary shall be the person or persons named as such by the Compensation Committee, or, if no such person or persons be named, then the person or persons named by the Administrative Committee as the Named Appeals Fiduciary. Named Appeals Fiduciaries may at any time be removed by the Compensation Committee, and any Named Appeals Fiduciary named by the Administrative Committee may be removed by the Administrative Committee. All such removals may be with or without cause and shall be effective on the date stated in the notice of removal. The Named Appeals Fiduciary shall be a “Named Fiduciary” within the meaning of ERISA, and unless appointed to other fiduciary responsibilities, shall have no authority, responsibility or liability with respect to any matter other than the proper discharge of the functions of the Named Appeals Fiduciary as set forth herein.

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ARTICLE X

MISCELLANEOUS

Section 10.01Nonalienation of Benefits. None of the payments, benefits or rights of any Participant shall be subject to any claim of any creditor, and, in particular, to the fullest extent permitted by law, all such payments, benefits and rights shall be free from attachment, garnishment, trustee’s process, or any other legal or equitable process available to any creditor of such Participant. No Participant shall have the right to alienate, anticipate, commute, pledge, encumber or assign any of the benefits or payments which the Participant may expect to receive, contingently or otherwise, under this Plan.

Section 10.02No Contract of Employment. Neither the establishment of the Plan, nor any modification thereof, nor the creation of any fund, trust or account, nor the payment of any benefits shall be construed as giving any Participant, or any person whosoever, the right to be retained in the service of the Company or an Affiliate, and all Participants shall remain subject to discharge to the same extent as if the Plan had never been adopted.

Section 10.03Severability of Provisions. If any provision of this Plan shall be held invalid or unenforceable by a court of competent jurisdiction, such invalidity or unenforceability shall not affect any other provisions hereof, and this Plan shall be construed and enforced as if such provisions had not been included.

Section 10.04Successors, Heirs, Assigns, and Personal Representatives. This Plan shall be binding upon the heirs, executors, administrators, successors and assigns of the parties, including each Participant, present and future. If a Change in Control occurs, unless the Compensation Committee directs otherwise before the Change in Control, the Company shall require any successor or successors (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, or a division or Affiliate thereof, (i) to acknowledge expressly that this Plan is binding upon and enforceable against such successor in accordance with the terms hereof, (ii) to become jointly and severally obligated with the Company to perform the obligations under this Plan, and (iii) to agree not to amend or terminate the Plan for a period of one year after the Change in Control without the consent of the affected Participant.

Section 10.05Unfunded Plan. The Plan shall not be funded. The Company may, but shall not be required to, set aside or designate an amount necessary to provide the Benefits specified herein (including the establishment of trusts). In any event, no Participant shall have any right to, or interest in, any assets of the Company or an Affiliate which may be applied by the Company or an Affiliate to the payment of Benefits.

Section 10.06Payments to Incompetent Persons. Any Benefit payable to or for the benefit of an incompetent person or other person incapable of receipting therefor shall be deemed paid when paid to such person’s guardian or to the party providing or reasonably appearing to provide for the care of such person, and such payment shall fully discharge the Company, its

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Affiliates, the Administrative Committee, the Compensation Committee and all other parties with respect thereto.

Section 10.07Controlling Law. This Plan shall be construed and enforced according to the laws of the Commonwealth of Pennsylvania, to the extent not preempted by Federal law, without giving effect to any Pennsylvania choice of law provisions.

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EXHIBIT A

UGI UTILITIES, INC.

CHANGE IN CONTROL

For purposes of this Plan, the term “Change in Control,” and defined terms used in the definition of “Change in Control,” shall have the following meanings:

(i)Any Person (except the Employee, his Affiliates and Associates, UGI Corporation (“UGI”), any Subsidiary of UGI, any employee benefit plan of UGI or of any Subsidiary of UGI, or any Person or entity organized, appointed or established by UGI or any Subsidiary of UGI for or pursuant to the terms of any such employee benefit plan), together with all Affiliates and Associates of such Person, becomes the Beneficial Owner in the aggregate of 20% or more of either (i) the then outstanding shares of common stock of UGI (the “Outstanding UGI Common Stock”) or (ii) the combined voting power of the then outstanding voting securities of UGI entitled to vote generally in the election of directors (the “UGI Voting Securities”); or

(ii)Individuals who, as of the beginning of any 24-month period, constitute the UGI Board of Directors (the “Incumbent UGI Board”) cease for any reason to constitute at least a majority of the Incumbent UGI Board, provided that any individual becoming a director of UGI subsequent to the beginning of such period whose election or nomination for election by the UGI stockholders was approved by a vote of at least a majority of the directors then comprising the Incumbent UGI Board shall be considered as though such individual were a member of the Incumbent UGI Board, but excluding, for this purpose, any such individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the Directors of UGI; or

(iii)Consummation by UGI of a reorganization, merger or consolidation (a “Business Combination”), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of the Outstanding UGI Common Stock and UGI Voting Securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of the Outstanding UGI Common Stock and UGI Voting Securities, as the case may be; or

(iv)(A)    Consummation of a complete liquidation or dissolution of UGI or (B) sale or other disposition of all or substantially all of the assets of UGI other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of the Outstanding UGI Common Stock and UGI Voting Securities immediately prior to such sale or disposition in substantially the same proportion as

A-1

their ownership of the Outstanding UGI Common Stock and UGI Voting Securities, as the case may be, immediately prior to such sale or disposition; or

(v)UGI and its Subsidiaries fail to own more than 50% of the then outstanding shares of common stock of the Company or more than 50% of the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors; or

(vi)Consummation by the Company of a reorganization, merger or consolidation (a “Business Combination”), in each case, with respect to which all or substantially all of the individuals and entities who were the respective Beneficial Owners of the Company’s outstanding common stock and voting securities immediately prior to such Business Combination do not, following such Business Combination, Beneficially Own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of the Company’s outstanding common stock and voting securities, as the case may be; or

(vii)Consummation of a complete liquidation or dissolution of the Company or sale or other disposition of all or substantially all of the assets of the Company other than to a corporation with respect to which, following such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the Beneficial Owners, respectively, of the Company’s outstanding common stock and voting securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of the Company’s outstanding common stock and voting securities, as the case may be, immediately prior to such sale or disposition.

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EX-10.3

EXHIBIT 10.3

Service Agreement No. SST No. 79133

Control Number _________

LETTER AGREEMENT

AMENDING SST SERVICE AGREEMENT

THIS LETTER AGREEMENT is entered into and made effective June 10, 2013, by and between COLUMBIA GAS TRANSMISSION, LLC (“Transporter”) and UGI UTILITIES, INC. (“Shipper”).

WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree that existing SST service agreement No. 79133 shall be amended as follows:

Section 3. Rates. Effective June 11, 2013, through December 2013, Shipper agrees to pay, in addition to all other charges then applicable to the agreement, a negotiated monthly fee of $____ on SST Contract 79133.

UGI UTILITIES, INC.                COLUMBIA GAS TRANSMISSION, LLC

BY: /s/ Robert F. Beard                BY: /s/ Joseph Shields        

ITS: President and CEO                ITS: Chief Operating Officer

DATE: 6/7/13                         DATE: 6/10/13        

EX-12.1

UGI UTILITIES, INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1

(Thousands of dollars)

	Nine Months Ended June 30,
			Year Ended September 30,
	2013		2012		2011		2010		2009		2008
Earnings:
Earnings before income taxes	$	171,085	$	142,971	$	168,693	$	147,183	$	125,554	$	123,977
Interest expense	29,587		42,412		42,728		42,336		43,918		39,065
Amortization of debt discount and
expense	549		814		1,060		627		625		467
Estimated interest component of
rental expense	1,561		2,121		1,740		1,912		1,965		1,619
	$	202,782	$	188,318	$	214,221	$	192,058	$	172,062	$	165,128
Fixed Charges:
Interest expense	$	29,587	$	42,412	$	42,728	$	42,336	$	43,918	$	39,065
Amortization of debt discount and
expense	549		814		1,060		627		625		467
Allowance for funds used during
construction (capitalized interest)	362		10		90		74		160		139
Estimated interest component of
rental expense	1,561		2,121		1,740		1,912		1,965		1,619
	$	32,059	$	45,357	$	45,618	$	44,949	$	46,668	$	41,290
Ratio of earnings to fixed charges	6.33		4.15		4.70		4.27		3.69		4.00

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Robert F. Beard, certify that:

1. I have reviewed this periodic report on Form 10-Q of UGI Utilities, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2013

/s/ Robert F. Beard

Robert F. Beard

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Donald E. Brown, certify that:

1. I have reviewed this periodic report on Form 10-Q of UGI Utilities, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2013

/s/ Donald E. Brown

Donald E. Brown

Vice President - Finance and Chief Financial Officer

EX-32

EXHIBIT 32

Certification by the Chief Executive Officer and Chief Financial Officer

Relating to a Periodic Report Containing Financial Statements

I, Robert F. Beard, Chief Executive Officer, and I, Donald E. Brown, Chief Financial Officer, of UGI Utilities, Inc., a Pennsylvania corporation (the “Company”), hereby certify that to our knowledge:

(1) The Company’s periodic report on Form 10-Q for the period ended June 30, 2013 (the “Form 10-Q”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

CHIEF EXECUTIVE OFFICER		CHIEF FINANCIAL OFFICER
/s/ Robert F. Beard		/s/ Donald E. Brown
Robert F. Beard		Donald E. Brown
Date:	August 2, 2013	Date:	August 2, 2013

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Fair Value Measurements

9 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

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, 2013, September 30, 2012 and June 30, 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	103		$	—		$	—	$	103
Interest rate contracts	$	—		$	8,125		$	—	$	8,125
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,885	)	$	(5,759	)	$	—	$	(7,644	)
Interest rate contracts	$	—		$	(15,306	)	$	—	$	(15,306	)
September 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5,468		$	—		$	—	$	5,468
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(671	)	$	(8,766	)	$	—	$	(9,437	)
Interest rate contracts	$	—		$	(30,522	)	$	—	$	(30,522	)
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	545		$	—		$	—	$	545
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,457	)	$	(12,099	)	$	—	$	(13,556	)
Interest rate contracts	$	—		$	(28,917	)	$	—	$	(28,917	)

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. There were no transfers between Level 1 and Level 2 during the periods presented.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for 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, 2013, were $600,000 and $663,178, respectively. The carrying amount and estimated fair value of our long-term debt at June 30, 2012, were $640,000 and $742,165, 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 (Level 2).

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Condensed Consolidated Statements of Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Revenues	$ 148,798	$ 143,644	$ 818,496	$ 770,087
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	64,332	62,701	415,394	412,377
Operating and administrative expenses	46,420	37,689	143,076	124,380
Operating and administrative expenses - related parties	1,940	2,107	6,757	7,013
Taxes other than income taxes	3,756	3,919	12,716	12,903
Depreciation	13,201	12,425	38,849	37,132
Amortization	832	826	2,467	2,292
Other income, net	(561)	(1,323)	(1,435)	(4,362)
Total costs and expenses	129,920	118,344	617,824	591,735
Operating income	18,878	25,300	200,672	178,352
Interest expense	9,690	10,575	29,587	31,859
Income before income taxes	9,188	14,725	171,085	146,493
Income taxes	3,815	6,265	70,641	57,494
Net income	$ 5,373	$ 8,460	$ 100,444	$ 88,999

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Accounting Changes

9 Months Ended

Jun. 30, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Changes

Accounting Changes

New Accounting Standards Not Yet Adopted

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In February 2013, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance regarding disclosures for items reclassified out of accumulated other comprehensive income (“AOCI”). The new disclosure guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2012. The new disclosures are to be applied prospectively, and early adoption is permitted. We expect to adopt the new guidance in Fiscal 2014. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities. In December 2011 (and amended in January 2013), the FASB issued new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 (Fiscal 2014) and interim periods within those annual periods, and is required to be applied retrospectively. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

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Fair Value Measurements (Tables)

9 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Financial assets and financial liabilities that are measured at fair value on a recurring basis

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, 2013, September 30, 2012 and June 30, 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	103		$	—		$	—	$	103
Interest rate contracts	$	—		$	8,125		$	—	$	8,125
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,885	)	$	(5,759	)	$	—	$	(7,644	)
Interest rate contracts	$	—		$	(15,306	)	$	—	$	(15,306	)
September 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5,468		$	—		$	—	$	5,468
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(671	)	$	(8,766	)	$	—	$	(9,437	)
Interest rate contracts	$	—		$	(30,522	)	$	—	$	(30,522	)
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	545		$	—		$	—	$	545
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(1,457	)	$	(12,099	)	$	—	$	(13,556	)
Interest rate contracts	$	—		$	(28,917	)	$	—	$	(28,917	)

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Disclosures About Derivative Instruments and Hedging Activities

9 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Disclosures About Derivative Instruments and Hedging Activities

. 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, including the cost of financial instruments used to hedge purchased gas costs. 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. At June 30, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.7 million dekatherms and 13.2 million dekatherms, respectively. At June 30, 2013, the maximum period over which Gas Utility is hedging natural gas market price risk is 16 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with accounting guidance related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 6).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At June 30, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising net losses of $6,060 and $13,095, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At June 30, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 327.4 million kilowatt hours and 654.7 million kilowatt hours, respectively. At June 30, 2013, the maximum period over which these contracts extend is 11 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly 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. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 6). At June 30, 2013 and 2012, the volumes associated with Electric Utility FTRs totaled 260.6 million kilowatt hours and 261.0 million kilowatt hours, respectively. At June 30, 2013, the maximum period over which we are hedging electricity congestion with FTRs is 11 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, 2013 and 2012, the total notional amounts of unsettled IRPAs 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 2013.

UGI Utilities reclassified pre-tax losses of $682 from AOCI into income during the nine months ended June 30, 2012 as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in “Other income, net” on the Condensed Consolidated Statements of Income.

At June 30, 2013, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $2,203.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2013, there was $2,636 restricted cash in brokerage accounts. At June 30, 2012, restricted cash in brokerage accounts totaled $1,604.

The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of June 30, 2013 and 2012:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	8,125	$	—	Derivative financial instruments and Other noncurrent liabilities	$	(15,306	)	$	(28,917	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	67		545		Derivative financial instruments and Other noncurrent liabilities	(7,644		)	(13,539		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	36		—		Derivative financial instruments	—			(17		)
Total Derivatives		$	8,228	$	545		$	(22,950	)	$	(42,473	)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for three and nine months ended June 30, 2013 and 2012:

Three Months Ended June 30, :
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013			2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	12,776		$	(11,573	)	$	(203	)	$	(484	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
	2013			2012
Commodity contracts	$	(93	)	$	(127	)							Operating expenses/other income, net
Nine Months Ended June 30, :
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013			2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	23,228		$	(10,147	)	$	(608	)	$	(1,748	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
	2013			2012
Commodity contracts	$	12		$	78								Operating expenses/other income, net

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 and contracts that provide for the purchase and delivery, or sale, 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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Disclosures About Derivative Instruments and Hedging Activities (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Jun. 30, 2012
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	$ 8,228	$ 545
Total Derivatives Liability	(22,950)	(42,473)
Interest rate contracts [Member] | Derivatives Designated as Hedging Instruments [Member] | Derivative financial instruments [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	8,125	0
Interest rate contracts [Member] | Derivatives Designated as Hedging Instruments [Member] | Derivative financial instruments and other noncurrent liabilities [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(15,306)	(28,917)
Commodity contracts [Member] | Derivatives Subject to Utility Rate Regulation [Member] | Derivative financial instruments [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	67	545
Commodity contracts [Member] | Derivatives Subject to Utility Rate Regulation [Member] | Derivative financial instruments and other noncurrent liabilities [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(7,644)	(13,539)
Commodity contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Derivative financial instruments [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	0	(17)
Commodity contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Derivative financial instruments [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	$ 36	$ 0

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Inventories (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Inventory, Net [Abstract]
Total inventories	$ 53,998	$ 67,334	$ 38,413
Gas Utility Natural Gas [Member]
Inventory, Net [Abstract]
Total inventories	43,052	57,663	27,761
Materials, Supplies and Other [Member]
Inventory, Net [Abstract]
Total inventories	$ 10,946	$ 9,671	$ 10,652

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 Segment	Jun. 30, 2012	Sep. 30, 2012
Segment Reporting [Abstract]
Number of reportable segments (in segments)			2
Segment Reporting Information [Line Items]
Revenues	$ 148,798	$ 143,644	$ 818,496	$ 770,087
Cost of sales	64,332	62,701	415,394	412,377
Depreciation and amortization	14,033	13,251	41,316	39,424
Operating income	18,878	25,300	200,672	178,352
Interest expense	9,690	10,575	29,587	31,859
Income before income taxes	9,188	14,725	171,085	146,493
Total assets (at period end)	2,328,056	2,185,845	2,328,056	2,185,845	2,223,179
Goodwill (at period end)	182,145	182,145	182,145	182,145	182,145
Capital expenditures	38,961	29,914	94,480	79,698
Gas Utility [Member]
Segment Reporting Information [Line Items]
Revenues	126,725	122,273	743,614	696,814
Cost of sales	52,365	51,401	372,681	370,572
Depreciation and amortization	13,012	12,332	38,348	36,635
Operating income	16,054	22,535	191,592	168,735
Interest expense	9,172	9,965	28,071	30,148
Income before income taxes	6,882	12,570	163,521	138,587
Total assets (at period end)	2,164,435	2,027,023	2,164,435	2,027,023
Goodwill (at period end)	182,145	182,145	182,145	182,145
Capital expenditures	37,224	29,004	90,173	76,470
Electric Utility [Member]
Segment Reporting Information [Line Items]
Revenues	21,535	20,779	73,604	71,888
Cost of sales	11,967	11,300	42,713	41,805
Depreciation and amortization	1,021	919	2,968	2,789
Operating income	2,584	2,554	8,597	9,147
Interest expense	518	610	1,516	1,711
Income before income taxes	2,066	1,944	7,081	7,436
Total assets (at period end)	163,621	158,822	163,621	158,822
Goodwill (at period end)	0	0	0	0
Capital expenditures	1,737	910	4,307	3,228
Other [Member]
Segment Reporting Information [Line Items]
Revenues	538	592	1,278	1,385
Cost of sales	0	0	0	0
Depreciation and amortization	0	0	0	0
Operating income	240	211	483	470
Interest expense	0	0	0	0
Income before income taxes	240	211	483	470
Total assets (at period end)	0	0	0	0
Goodwill (at period end)	0	0	0	0
Capital expenditures	$ 0	$ 0	$ 0	$ 0

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Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended					3 Months Ended		9 Months Ended					3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 Energy Services [Member]	Jun. 30, 2012 Energy Services [Member]	Jun. 30, 2013 Energy Services [Member]	Jun. 30, 2012 Energy Services [Member]	Jun. 30, 2013 Inventories [Member] Energy Services [Member] ft3	Sep. 30, 2012 Inventories [Member] Energy Services [Member] ft3	Jun. 30, 2012 Inventories [Member] Energy Services [Member] ft3	Jun. 30, 2013 SCAAs [Member] Energy Services [Member]	Jun. 30, 2012 SCAAs [Member] Energy Services [Member]	Jun. 30, 2013 SCAAs [Member] Energy Services [Member]	Jun. 30, 2012 SCAAs [Member] Energy Services [Member]	Jun. 30, 2013 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Sep. 30, 2012 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Jun. 30, 2012 SCAAs [Member] Other current liabilities [Member] Energy Services [Member]	Jun. 30, 2013 Exclusive of transactions pursuant SCAAs [Member] Energy Services [Member]	Jun. 30, 2012 Exclusive of transactions pursuant SCAAs [Member] Energy Services [Member]	Jun. 30, 2013 Exclusive of transactions pursuant SCAAs [Member] Energy Services [Member]	Jun. 30, 2012 Exclusive of transactions pursuant SCAAs [Member] Energy Services [Member]	Jun. 30, 2013 SCAAs [Member] Storage_Agreement	Jun. 30, 2013 SCAAs [Member] Energy Services [Member] Storage_Agreement	Jun. 30, 2013 Expires in October 2013 [Member] SCAAs [Member] Storage_Agreement	Jun. 30, 2013 Expires in October 2013 [Member] SCAAs [Member] Energy Services [Member] Storage_Agreement	Jun. 30, 2013 Expires in October 2015 [Member] SCAAs [Member] Storage_Agreement	Jun. 30, 2013 Expires in October 2015 [Member] SCAAs [Member] Energy Services [Member] Storage_Agreement
Related Party Transaction [Line Items]
Number of storage agreements (in storage agreements)																							3	3	1	1	2	2
Related party costs incurred	$ 1,940	$ 2,107	$ 6,757	$ 7,013								$ 21,570	$ 8,396	$ 26,596	$ 13,726				$ 0	$ 0	$ 32,526	$ 30,752
Related party security deposits																16,500	15,000	15,000
Volume of gas storage inventory (in bcf of natural gas)									5,600,000,000	7,600,000,000	4,100,000,000
Natural gas storage inventory, related parties, current									24,389	21,217	10,512
Revenue from related parties					14,956	12,067	60,208	52,744
Purchases from related party					$ 24,426	$ 13,158	$ 61,659	$ 36,477

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Defined Benefit Pension and Other Postretirement Plans (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Pension Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	$ 2,052	$ 1,756	$ 6,158	$ 5,269
Interest cost	5,196	5,594	15,587	16,782
Expected return on assets	(6,197)	(5,940)	(18,594)	(17,822)
Amortization of:
Prior service cost (benefit)	62	62	187	187
Actuarial loss	3,366	1,963	10,098	5,890
Net benefit cost	4,479	3,435	13,436	10,306
Change in associated regulatory liabilities	0	0	0	0
Net expense	4,479	3,435	13,436	10,306
Other Postretirement Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	51	43	154	129
Interest cost	143	165	428	497
Expected return on assets	(133)	(127)	(396)	(380)
Amortization of:
Prior service cost (benefit)	(105)	(105)	(317)	(317)
Actuarial loss	91	99	273	296
Net benefit cost	47	75	142	225
Change in associated regulatory liabilities	815	784	2,446	2,353
Net expense	$ 862	$ 859	$ 2,588	$ 2,578

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Disclosures About Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Balance sheet location and fair value of derivative assets and liabilities

The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of June 30, 2013 and 2012:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	8,125	$	—	Derivative financial instruments and Other noncurrent liabilities	$	(15,306	)	$	(28,917	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	67		545		Derivative financial instruments and Other noncurrent liabilities	(7,644		)	(13,539		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	36		—		Derivative financial instruments	—			(17		)
Total Derivatives		$	8,228	$	545		$	(22,950	)	$	(42,473	)

Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for three and nine months ended June 30, 2013 and 2012:

Three Months Ended June 30, :
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013			2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	12,776		$	(11,573	)	$	(203	)	$	(484	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
	2013			2012
Commodity contracts	$	(93	)	$	(127	)							Operating expenses/other income, net
Nine Months Ended June 30, :
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2013			2012			2013			2012			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	23,228		$	(10,147	)	$	(608	)	$	(1,748	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
	2013			2012
Commodity contracts	$	12		$	78								Operating expenses/other income, net

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Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Dec. 31, 2011	Jun. 30, 2013	Jun. 30, 2012
Tax on (loss) gain on derivative instruments	$ (5,301)	$ 4,801	$ (9,638)	$ 4,209
Tax on reclassifications of net losses (gains) on derivative instruments	(84)	(201)	(252)	(725)
Tax on benefit plans	$ (140)	$ (80)	$ (418)	$ (242)

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Nature of Operations

9 Months Ended

Jun. 30, 2013

Nature of Operations [Abstract]

Nature of Operations

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.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, 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 service territory (“HVAC Business”).

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.

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Segment Information

9 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Segment Information

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. The HVAC Business 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 2012 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.

Financial information by business segment follows:

Three Months Ended June 30, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	148,798	$	126,725	$	21,535	$	538
Cost of sales	$	64,332	$	52,365	$	11,967	$	—
Depreciation and amortization	$	14,033	$	13,012	$	1,021	$	—
Operating income	$	18,878	$	16,054	$	2,584	$	240
Interest expense	$	9,690	$	9,172	$	518	$	—
Income before income taxes	$	9,188	$	6,882	$	2,066	$	240
Total assets (at period end)	$	2,328,056	$	2,164,435	$	163,621	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	38,961	$	37,224	$	1,737	$	—

Three Months Ended June 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	143,644	$	122,273	$	20,779	$	592
Cost of sales	$	62,701	$	51,401	$	11,300	$	—
Depreciation and amortization	$	13,251	$	12,332	$	919	$	—
Operating income	$	25,300	$	22,535	$	2,554	$	211
Interest expense	$	10,575	$	9,965	$	610	$	—
Income before income taxes	$	14,725	$	12,570	$	1,944	$	211
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	29,914	$	29,004	$	910	$	—

Nine Months Ended June 30, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	818,496	$	743,614	$	73,604	$	1,278
Cost of sales	$	415,394	$	372,681	$	42,713	$	—
Depreciation and amortization	$	41,316	$	38,348	$	2,968	$	—
Operating income	$	200,672	$	191,592	$	8,597	$	483
Interest expense	$	29,587	$	28,071	$	1,516	$	—
Income before income taxes	$	171,085	$	163,521	$	7,081	$	483
Total assets (at period end)	$	2,328,056	$	2,164,435	$	163,621	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	94,480	$	90,173	$	4,307	$	—

Nine Months Ended June 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	770,087	$	696,814	$	71,888	$	1,385
Cost of sales	$	412,377	$	370,572	$	41,805	$	—
Depreciation and amortization	$	39,424	$	36,635	$	2,789	$	—
Operating income	$	178,352	$	168,735	$	9,147	$	470
Interest expense	$	31,859	$	30,148	$	1,711	$	—
Income before income taxes	$	146,493	$	138,587	$	7,436	$	470
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	79,698	$	76,470	$	3,228	$	—

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Significant Accounting Policies

9 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Significant Accounting Policies

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 that 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, 2012, condensed consolidated balance sheet data was 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, 2012 (“Company’s 2012 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.

Comprehensive Income. Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally reflects net gains (losses) on interest rate protection agreements qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.

Restricted Cash. Restricted cash represents those cash balances in our commodity futures brokerage accounts that 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.

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Inventories Textual (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013 ft3	Sep. 30, 2012 ft3	Jun. 30, 2012 ft3
Inventory, Net [Abstract]
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)	5,600,000,000	11,400,000,000	6,000,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates	$ 24,389	$ 32,627	$ 15,787
SCAAs [Member]
Public Utilities, Inventory [Line Items]
Number of storage agreements (in storage agreements)	3
SCAAs [Member] | Other current liabilities [Member]
Inventory, Net [Abstract]
Security Deposit Liability	$ 16,500	$ 22,500	$ 22,500
Expires in October 2015 [Member] | SCAAs [Member]
Public Utilities, Inventory [Line Items]
Number of storage agreements (in storage agreements)	2
Expires in October 2013 [Member] | SCAAs [Member]
Public Utilities, Inventory [Line Items]
Number of storage agreements (in storage agreements)	1

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Defined Benefit Pension and Other Postretirement Plans Textual (Details) (Pension Benefits [Member], USD $) In Thousands, unless otherwise specified	9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contribution to pensions plans in the remainder of current fiscal year	$ 2,500
Contribution made to Pension Plan	$ 13,365	$ 25,442

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Disclosures About Derivative Instruments and Hedging Activities Textual (Details) (USD $) In Thousands, unless otherwise specified												3 Months Ended	9 Months Ended
	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012	Jun. 30, 2013 Electric Utility electric transmission congestion [Member] kWh	Jun. 30, 2012 Electric Utility electric transmission congestion [Member] kWh	Jun. 30, 2013 Gas Utility [Member] DTH	Jun. 30, 2012 Gas Utility [Member] DTH	Jun. 30, 2013 Electric Utility [Member] kWh	Jun. 30, 2012 Electric Utility [Member] kWh	Jun. 30, 2013 Interest Rate Protection Agreements [Member]	Jun. 30, 2012 Interest Rate Protection Agreements [Member]	Jun. 30, 2012 Interest Rate Swap [Member]	Jun. 30, 2012 Interest Rate Swap [Member]
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Notional amount (in units)				260,600,000	261,000,000	11,700,000	13,200,000	327,400,000	654,700,000
Total Derivatives Liability	$ 22,950		$ 42,473					$ (6,060)	$ (13,095)
Total Derivatives Assets	8,228		545
Underlying variable rate debt										173,000	173,000
Recorded loss amount included in Other Income, Net												0	(682)
Maximum length of time hedged in price risk cash flow hedges (in months)				11 months		16 months		11 months
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	2,203
Restricted Cash in brokerage accounts	$ 2,636	$ 0	$ 1,604

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Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Allowance for doubtful accounts on accounts receivable	$ 9,166	$ 3,588	$ 7,457
Accumulated depreciation and amortization on property, plant and equipment	$ 846,941	$ 815,720	$ 809,458
Common stock, par value	$ 2.25	$ 2.25	$ 2.25
Common stock, shares authorized	40,000,000	40,000,000	40,000,000
Common stock, shares issued	26,781,785	26,781,785	26,781,785
Common stock, shares outstanding	26,781,785	26,781,785	26,781,785

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Defined Benefit Pension and Other Postretirement Plans

9 Months Ended

Jun. 30, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Pension and Other Postretirement Plans

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 postretirement life insurance benefits to nearly all active and retired employees.

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,
	2013			2012			2013			2012
Service cost	$	2,052		$	1,756		$	51		43
Interest cost	5,196			5,594			143			165
Expected return on assets	(6,197		)	(5,940		)	(133		)	(127		)
Amortization of:
Prior service cost (benefit)	62			62			(105		)	(105		)
Actuarial loss	3,366			1,963			91			99
Net benefit cost	4,479			3,435			47			75
Change in associated regulatory liabilities	—			—			815			784
Net expense	$	4,479		$	3,435		$	862		$	859
	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Service cost	$	6,158		$	5,269		$	154		$	129
Interest cost	15,587			16,782			428			497
Expected return on assets	(18,594		)	(17,822		)	(396		)	(380		)
Amortization of:
Prior service cost (benefit)	187			187			(317		)	(317		)
Actuarial loss	10,098			5,890			273			296
Net benefit cost	13,436			10,306			142			225
Change in associated regulatory liabilities	—			—			2,446			2,353
Net expense	$	13,436		$	10,306		$	2,588		$	2,578

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 Plan 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 $2,500 to the Pension Plan during the remainder of Fiscal 2013. During the nine months endedJune 30, 2013 and 2012, the Company made contributions to the Pension Plan of $13,365 and $25,442, respectively. 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 endedJune 30, 2013 and 2012, nor are they expected to be material for all of Fiscal 2013.

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.

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Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Net income	$ 5,373	$ 8,460	$ 100,444	$ 88,999
Net gains (losses) in fair value of derivative instruments (net of tax $(5,301), $4,801, $(9,638) and $4,209, respectively)	7,475	(6,772)	13,590	(5,938)
Reclassifications of net losses on derivative instruments (net of tax of $(84), $(201), $(252) and $(725), respectively)	119	283	356	1,023
Benefit plans (net of tax of $(140), $(80), $(418) and $(242),respectively)	195	101	588	317
Other comprehensive income (loss)	7,789	(6,388)	14,534	(4,598)
Comprehensive income	$ 13,162	$ 2,072	$ 114,978	$ 84,401

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Condensed Consolidated Balance Sheets (unaudited) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Current assets:
Cash and cash equivalents	$ 82,027	$ 1,259	$ 75,969
Restricted cash	2,636	0	1,604
Accounts receivable (less allowances for doubtful accounts of $9,166, $3,588 and $7,457, respectively)	78,677	47,362	61,072
Accounts receivable — related parties	4,086	4,571	4,311
Accrued utility revenues	11,836	16,911	14,970
Inventories	53,998	67,334	38,413
Deferred income taxes	38,619	46,436	33,595
Regulatory assets	3,747	6,473	2,681
Derivative financial instruments	8,228	5,468	545
Prepaid expenses & other current assets	9,766	29,313	17,890
Total current assets	293,620	225,127	251,050
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $846,941, $815,720 and $809,458, respectively)	1,531,440	1,479,949	1,458,654
Goodwill	182,145	182,145	182,145
Regulatory assets	317,216	331,932	288,366
Other assets	3,635	4,026	5,630
Total assets	2,328,056	2,223,179	2,185,845
Current liabilities:
Current maturities of long-term debt	133,000	133,000	40,000
Bank loans	0	9,200	0
Accounts payable	35,587	46,754	30,457
Accounts payable — related parties	17,176	10,192	10,175
Deferred fuel refunds	14,156	4,435	10,325
Derivative financial instruments	22,911	36,011	7,150
Other current liabilities	123,438	131,092	144,492
Total current liabilities	346,268	370,684	242,599
Long-term debt	467,000	467,000	600,000
Deferred income taxes	443,703	417,052	371,388
Deferred investment tax credits	4,355	4,612	4,698
Pension and postretirement benefit obligations	172,721	179,056	126,007
Other noncurrent liabilities	51,999	56,262	92,409
Total liabilities	1,486,046	1,494,666	1,437,101
Commitments and contingencies (note 8)
Common stockholder’s equity:
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares)	60,259	60,259	60,259
Additional paid-in capital	469,736	468,692	468,630
Retained earnings	327,298	229,379	246,286
Accumulated other comprehensive loss	(15,283)	(29,817)	(26,431)
Total common stockholder’s equity	842,010	728,513	748,744
Total liabilities and stockholder’s equity	$ 2,328,056	$ 2,223,179	$ 2,185,845

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Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 320,963	$ 338,405	$ 291,047
Regulatory Liabilities	40,002	28,344	33,978
Postretirement benefits [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	14,244	13,147	12,342
Environmental overcollections [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	2,906	2,883	3,726
Deferred fuel and power refunds [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	14,156	4,435	10,325
State tax benefits -- distribution system repairs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	8,024	7,385	6,961
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	672	494	624
Income taxes recoverable [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	104,731	103,172	99,891
Underfunded pension and postretirement plans [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	177,846	188,222	144,613
Environmental costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	16,642	16,812	16,562
Deferred fuel and power costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	4,109	11,602	9,829
Removal costs, net [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	12,074	12,718	11,840
Other [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 5,561	$ 5,879	$ 8,312

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Defined Benefit Pension and Other Postretirement Plans (Tables)

9 Months Ended

Jun. 30, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Component of net periodic pension expense and other postretirement benefit costs

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,
	2013			2012			2013			2012
Service cost	$	2,052		$	1,756		$	51		43
Interest cost	5,196			5,594			143			165
Expected return on assets	(6,197		)	(5,940		)	(133		)	(127		)
Amortization of:
Prior service cost (benefit)	62			62			(105		)	(105		)
Actuarial loss	3,366			1,963			91			99
Net benefit cost	4,479			3,435			47			75
Change in associated regulatory liabilities	—			—			815			784
Net expense	$	4,479		$	3,435		$	862		$	859
	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Service cost	$	6,158		$	5,269		$	154		$	129
Interest cost	15,587			16,782			428			497
Expected return on assets	(18,594		)	(17,822		)	(396		)	(380		)
Amortization of:
Prior service cost (benefit)	187			187			(317		)	(317		)
Actuarial loss	10,098			5,890			273			296
Net benefit cost	13,436			10,306			142			225
Change in associated regulatory liabilities	—			—			2,446			2,353
Net expense	$	13,436		$	10,306		$	2,588		$	2,578

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Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Interest rate contracts [Member] | Interest expense, net [Member] | Cash Flow Hedges [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain or (loss) recognized in AOCI	$ 12,776	$ (11,573)	$ 23,228	$ (10,147)
Gain (loss) reclassified from AOCI into income	(203)	(484)	(608)	(1,748)
Derivatives Not Designated as Hedging Instruments [Member] | Commodity contracts [Member] | Operating expenses/other income, net [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain (Loss) recognized in income	$ (93)	$ (127)	$ 12	$ 78

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Fair Value Measurements (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 103	$ 5,468	$ 545
Derivative financial instruments, liabilities	(7,644)	(9,437)	(13,556)
Commodity contracts [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	103	5,468	545
Derivative financial instruments, liabilities	(1,885)	(671)	(1,457)
Commodity contracts [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	(5,759)	(8,766)	(12,099)
Commodity contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	0	0	0
Interest rate contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	8,125
Derivative financial instruments, liabilities	(15,306)	(30,522)	(28,917)
Interest rate contracts [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0
Derivative financial instruments, liabilities	0	0	0
Interest rate contracts [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	8,125
Derivative financial instruments, liabilities	(15,306)	(30,522)	(28,917)
Interest rate contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0
Derivative financial instruments, liabilities	$ 0	$ 0	$ 0

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Fair Value Measurements Textual (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Jun. 30, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying amount of long-term debt	$ 600,000	$ 640,000
Fair value of long-term debt	$ 663,178	$ 742,165

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Regulatory Assets and Liabilities and Regulatory Matters

9 Months Ended

Jun. 30, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities and Regulatory Matters

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 4 to the Company’s 2012 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, 2013		September 30, 2012		June 30, 2012
Regulatory assets:
Income taxes recoverable	$	104,731	$	103,172	$	99,891
Underfunded pension and postretirement plans	177,846		188,222		144,613
Environmental costs	16,642		16,812		16,562
Deferred fuel and power costs	4,109		11,602		9,829
Removal costs, net	12,074		12,718		11,840
Other	5,561		5,879		8,312
Total regulatory assets	$	320,963	$	338,405	$	291,047
Regulatory liabilities:
Postretirement benefits	$	14,244	$	13,147	$	12,342
Environmental overcollections	2,906		2,883		3,726
Deferred fuel and power refunds	14,156		4,435		10,325
State tax benefits — distribution system repairs	8,024		7,385		6,961
Other	672		494		624
Total regulatory liabilities	$	40,002	$	28,344	$	33,978

Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and Electric Utility’s 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 natural 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. Net unrealized gains (losses) on such contracts at June 30, 2013, September 30, 2012, and June 30, 2012, were $(1,352), $5,303 and $280, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are recognized on the Condensed Consolidated Balance Sheet with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At June 30, 2013, September 30, 2012, and June 30, 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $6,060, $9,207 and $13,095, 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, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at June 30, 2013, September 30, 2012, and June 30, 2012, were not material.

Allentown, Pennsylvania Natural Gas Incident. On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff’s formal complaint, issued on June 11, 2012, pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $386 to $500; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

Transfers of Assets. On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11-mile natural gas pipeline, related facilities and right of way located in Delmar Township, Pennsylvania (“TL-96 line”) to Energy Services.   The PUC approved the transfer and in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services.  The net book value of the TL-96 line was approximately $2,650 which amount, net of related deferred income taxes, was recorded as a dividend of net assets.

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Regulatory Assets and Liabilities and Regulatory Matters Textual (Details) (USD $) In Thousands, unless otherwise specified										0 Months Ended
	Jul. 31, 2013	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 Deferral Fuel and Power [Member]	Sep. 30, 2012 Deferral Fuel and Power [Member]	Jun. 30, 2012 Deferral Fuel and Power [Member]	Jun. 30, 2013 Electric Utility Electric Supply Contracts [Member]	Sep. 30, 2012 Electric Utility Electric Supply Contracts [Member]	Jun. 30, 2012 Electric Utility Electric Supply Contracts [Member]	Oct. 03, 2012 Damage from Natural Gas Explosion [Member] Allentown, Pennsylvania Natural Gas Explosion [Member]	Feb. 09, 2011 Damage from Natural Gas Explosion [Member] Allentown, Pennsylvania Natural Gas Explosion [Member] Persons	Jun. 30, 2013 Allentown Incident [Member]	Jun. 30, 2013 Revised Penalty [Member] Allentown Incident [Member]
Regulatory Assets [Line Items]
GasUtilityUnrealizedGainOrLossOnDerivativeFinancialInstrumentsContracts				$ (1,352)	$ 5,303	$ 280
Site Contingency, Accelerated Time Frame Replacing Remainder of Cast-Iron Mains										14 years
Fair value of electric utility electricity supply contracts		(22,950)	(42,473)				(6,060)	(9,207)	(13,095)
Deaths from natural gas explosion (in persons)											5
Penalty Assessed												386	500
Loss Contingency, Agreement Permitted To Retain Current Timeframe for Replacing The Remainder of Their Bare Steel Mains										30 years
Net Book Value of The Pipeline	$ 2,650

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Related Party Transactions

9 Months Ended

Jun. 30, 2013

Related Party Transactions [Abstract]

Related Party Transactions

. 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.

At June 30, 2013, UGI Utilities was a party to three three-year SCAAs with Energy Services one of which expires October 31, 2013, and two of which expire October 31, 2015 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 $21,570 and $26,596 during the three and nine months ended June 30, 2013, respectively, and $8,396 and $13,726 during the three and nine months ended June 30, 2012. 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 $16,500 as of June 30, 2013, and $15,000 as of September 30, 2012 and June 30, 2012.

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, 2013, comprising approximately 5.6 bcf of natural gas, was $24,389. The carrying value of these gas storage inventories at September 30, 2012, comprising approximately 7.6 bcf of natural gas, was $21,217. The carrying value of these gas storage inventories at June 30, 2012, comprising approximately 4.1 bcf of natural gas, was $10,512.

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 aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the nine months ended June 30, 2013 and 2012, totaled $32,526 and $30,752, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2013, revenues associated with such sales to Energy Services totaled $14,956 and $60,208, respectively. During the three and nine months ended June 30, 2012, revenues associated with such sales to Energy Services totaled $12,067 and $52,744, respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three and nine months ended June 30, 2013, the aggregate amount of such purchases totaled $24,426 and $61,659, respectively. During the three and nine months ended June 30, 2012, such purchases totaled $13,158 and $36,477, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

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Inventories

9 Months Ended

Jun. 30, 2013

Inventory Disclosure [Abstract]

Inventories

Inventories

Inventories comprise the following:

	June 30, 2013		September 30, 2012		June 30, 2012
Gas Utility natural gas	$	43,052	$	57,663	$	27,761
Materials, supplies and other	10,946		9,671		10,652
Total inventories	$	53,998	$	67,334	$	38,413

At June 30, 2013, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”) with Energy Services, Inc. (“Energy Services”), a second-tier, wholly owned subsidiary of UGI, one of which expires in October 2013 and two of which expire in October 2015 (see Note 9). Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.

The carrying value of gas storage inventories released under UGI Utilities’ principal SCAAs at June 30, 2013, September 30, 2012 and June 30, 2012, comprising 5.6 billion cubic feet (“bcf”), 11.4 bcf and 6.0 bcf of natural gas, was $24,389, $32,627 and $15,787, respectively. In conjunction with these SCAAs, UGI Utilities held a total of security deposits received from its SCAA counterparties of $16,500 at June 30, 2013, and $22,500 at September 30, 2012 and June 30, 2012. These amounts are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets.

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 100,444	$ 88,999
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	41,316	39,424
Deferred income taxes, net	23,369	21,269
Provision for uncollectible accounts	8,297	5,592
Other, net	4,647	(12,809)
Net change in:
Accounts receivable and accrued utility revenues	(34,052)	(5,354)
Inventories	13,336	65,850
Deferred fuel and power costs	20,549	8,133
Accounts payable	(4,183)	(23,032)
Other current assets	19,675	7,059
Other current liabilities	(4,753)	7,467
Net cash provided by operating activities	188,645	202,598
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(94,480)	(79,698)
Net costs of property, plant and equipment disposals	(2,604)	(2,400)
(Increase) decrease in restricted cash	(2,636)	2,704
Net cash used by investing activities	(99,720)	(79,394)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	0	(54,809)
Decrease in bank loans	(9,200)	0
Other	1,043	307
Net cash used by financing activities	(8,157)	(54,502)
Cash and cash equivalents increase	80,768	68,702
CASH AND CASH EQUIVALENTS:
End of period	82,027	75,969
Beginning of period	1,259	7,267
Increase	$ 80,768	$ 68,702

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Commitments and Contingencies (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended		3 Months Ended	9 Months Ended
	Jun. 30, 2013	Jun. 30, 2013 Environmental Issue [Member]	Jun. 30, 2013 Environmental Issue [Member] PNG MGP [Member]	Jun. 30, 2013 Environmental Remediation Expense [Member] CPG MGP [Member]	Jun. 30, 2013 Environmental Remediation Expense [Member] PNG MGP [Member]	Jun. 30, 2013 CPG and PNG COAs [Member]	Jun. 30, 2012 CPG and PNG COAs [Member]	Feb. 09, 2011 Allentown, Pennsylvania Natural Gas Explosion [Member] Damage from Natural Gas Explosion [Member] Persons
Commitments and Contingencies [Line Items]
Environmental expenditures cap during calendar year				$ 1,800	$ 1,100
Option to termination agreement by either party effective at end of any two-year period beginning with the original effective date in March 2004 (in years)			2 years
Accrual for environmental loss contingencies						14,399	15,820
Base year for determination of investigation and remediation cost (in years)		5 years
Deaths from natural gas explosion (in persons)								5
Liability insurance deductible	$ 500

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Significant Accounting Policies (Policies)

9 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Comprehensive Income

Comprehensive Income. Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally reflects net gains (losses) on interest rate protection agreements qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.

Restricted Cash

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

Use of Estimates

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.

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Commitments and Contingencies

9 Months Ended

Jun. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At June 30, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14,399 and $15,820, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of 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.

The Company 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 (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At June 30, 2013, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.

From time to time, UGI Utilities is notified of 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 generally investigate the extent of environmental contamination or perform environmental remediation. 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.

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012. There have been no recent developments in this matter.

Other Matters

Allentown, Pennsylvania Natural Gas Incident. 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 “Incident”). UGI Utilities has received and settled all wrongful death claims and substantially all property and personal injury claims in connection with the Incident. UGI Utilities maintains liability insurance for personal injury, wrongful death and property and casualty damages subject to a $500 deductible. We expect that the remaining claims will be covered by UGI Utilities’ insurance. As a result, the Incident did not and we continue to believe it will not have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.

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

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Regulatory Assets and Liabilities and Regulatory Matters (Tables)

9 Months Ended

Jun. 30, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory assets and liabilities associated with Gas Utility and Electric Utility

The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:

	June 30, 2013		September 30, 2012		June 30, 2012
Regulatory assets:
Income taxes recoverable	$	104,731	$	103,172	$	99,891
Underfunded pension and postretirement plans	177,846		188,222		144,613
Environmental costs	16,642		16,812		16,562
Deferred fuel and power costs	4,109		11,602		9,829
Removal costs, net	12,074		12,718		11,840
Other	5,561		5,879		8,312
Total regulatory assets	$	320,963	$	338,405	$	291,047
Regulatory liabilities:
Postretirement benefits	$	14,244	$	13,147	$	12,342
Environmental overcollections	2,906		2,883		3,726
Deferred fuel and power refunds	14,156		4,435		10,325
State tax benefits — distribution system repairs	8,024		7,385		6,961
Other	672		494		624
Total regulatory liabilities	$	40,002	$	28,344	$	33,978

XML

Segment Information (Tables)

9 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Segment Information

Financial information by business segment follows:

Three Months Ended June 30, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	148,798	$	126,725	$	21,535	$	538
Cost of sales	$	64,332	$	52,365	$	11,967	$	—
Depreciation and amortization	$	14,033	$	13,012	$	1,021	$	—
Operating income	$	18,878	$	16,054	$	2,584	$	240
Interest expense	$	9,690	$	9,172	$	518	$	—
Income before income taxes	$	9,188	$	6,882	$	2,066	$	240
Total assets (at period end)	$	2,328,056	$	2,164,435	$	163,621	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	38,961	$	37,224	$	1,737	$	—

Three Months Ended June 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	143,644	$	122,273	$	20,779	$	592
Cost of sales	$	62,701	$	51,401	$	11,300	$	—
Depreciation and amortization	$	13,251	$	12,332	$	919	$	—
Operating income	$	25,300	$	22,535	$	2,554	$	211
Interest expense	$	10,575	$	9,965	$	610	$	—
Income before income taxes	$	14,725	$	12,570	$	1,944	$	211
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	29,914	$	29,004	$	910	$	—

Nine Months Ended June 30, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	818,496	$	743,614	$	73,604	$	1,278
Cost of sales	$	415,394	$	372,681	$	42,713	$	—
Depreciation and amortization	$	41,316	$	38,348	$	2,968	$	—
Operating income	$	200,672	$	191,592	$	8,597	$	483
Interest expense	$	29,587	$	28,071	$	1,516	$	—
Income before income taxes	$	171,085	$	163,521	$	7,081	$	483
Total assets (at period end)	$	2,328,056	$	2,164,435	$	163,621	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	94,480	$	90,173	$	4,307	$	—

Nine Months Ended June 30, 2012:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	770,087	$	696,814	$	71,888	$	1,385
Cost of sales	$	412,377	$	370,572	$	41,805	$	—
Depreciation and amortization	$	39,424	$	36,635	$	2,789	$	—
Operating income	$	178,352	$	168,735	$	9,147	$	470
Interest expense	$	31,859	$	30,148	$	1,711	$	—
Income before income taxes	$	146,493	$	138,587	$	7,436	$	470
Total assets (at period end)	$	2,185,845	$	2,027,023	$	158,822	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	79,698	$	76,470	$	3,228	$	—

XML

Document and Entity Information	9 Months Ended
	Jun. 30, 2013	Jul. 31, 2013
Entity Information [Line Items]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	0000100548
Document Type	10-Q
Document Period End Date	Jun. 30, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		26,781,785

XML

Inventories (Tables)

9 Months Ended

Jun. 30, 2013

Inventory Disclosure [Abstract]

Inventories

Inventories comprise the following:

	June 30, 2013		September 30, 2012		June 30, 2012
Gas Utility natural gas	$	43,052	$	57,663	$	27,761
Materials, supplies and other	10,946		9,671		10,652
Total inventories	$	53,998	$	67,334	$	38,413