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 March 31, 2014

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 April 30, 2014, 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 March 31, 2014, September 30, 2013 and March 31, 2013	1
Condensed Consolidated Statements of Income for the three and six months ended March 31, 2014 and 2013	2
Condensed Consolidated Statements of Comprehensive Income for the three and six months ended March 31, 2014 and 2013	3
Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 2014 and 2013	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	25
Item 4. Controls and Procedures	26
Part II Other Information
Item 1A. Risk Factors	27
Item 6. Exhibits	27
Signatures	29

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UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Thousands of dollars)

	March 31, 2014			September 30, 2013			March 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	14,238		$	4,707		$	58,329
Restricted cash	—			3,181			—
Accounts receivable (less allowances for doubtful accounts of $12,098, $5,519 and $8,052, respectively)	181,823			53,341			141,053
Accounts receivable — related parties	8,633			3,497			9,518
Accrued utility revenues	49,710			18,868			48,857
Inventories	20,629			89,661			16,215
Deferred income taxes	12,877			14,165			32,815
Regulatory assets	4,242			8,217			1,072
Derivative financial instruments	3,221			43			8,528
Prepaid expenses & other current assets	13,705			15,862			16,755
Total current assets	309,078			211,542			333,142
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $877,460, $853,675 and $837,110, respectively)	1,611,934			1,574,135			1,508,985
Goodwill	182,145			182,145			182,145
Regulatory assets	231,689			236,694			321,257
Other assets	5,771			5,806			2,808
Total assets	$	2,340,617		$	2,210,322		$	2,348,337
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	—		$	—		$	133,000
Bank loans	6,500			17,500			—
Accounts payable	69,468			51,970			48,099
Accounts payable — related parties	20,715			12,487			12,535
Deferred fuel refunds	3,204			8,283			31,209
Derivative financial instruments	372			6,677			29,077
Other current liabilities	149,983			110,596			149,801
Total current liabilities	250,242			207,513			403,721
Long-term debt	642,000			642,000			467,000
Deferred income taxes	448,678			436,810			413,168
Deferred investment tax credits	4,100			4,270			4,440
Pension and postretirement benefit obligations	65,972			72,505			174,905
Other noncurrent liabilities	52,669			55,610			53,965
Total liabilities	1,463,661			1,418,708			1,517,199
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	470,761			470,098			469,501
Retained earnings	353,680			269,977			324,450
Accumulated other comprehensive loss	(7,744		)	(8,720		)	(23,072		)
Total common stockholder’s equity	876,956			791,614			831,138
Total liabilities and stockholder’s equity	$	2,340,617		$	2,210,322		$	2,348,337

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					Six Months Ended
	March 31,					March 31,
	2014			2013		2014			2013
Revenues	$	513,956		$	395,901	$	812,855		$	669,698
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	300,424			212,785		452,289			351,062
Operating and administrative expenses	54,306			52,421		95,451			96,656
Operating and administrative expenses — related parties	3,769			3,012		5,612			4,817
Taxes other than income taxes	4,801			4,684		8,980			8,960
Depreciation	13,815			12,895		27,437			25,648
Amortization	828			817		1,656			1,635
Other (income) loss, net	(1,941		)	57		(2,367		)	(874		)
	376,002			286,671		589,058			487,904
Operating income	137,954			109,230		223,797			181,794
Interest expense	8,806			9,820		17,603			19,897
Income before income taxes	129,148			99,410		206,194			161,897
Income taxes	53,038			41,151		84,798			66,826
Net income	$	76,110		$	58,259	$	121,396		$	95,071

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 March 31,				Six Months Ended March 31,
	2014		2013		2014		2013
Net income	$	76,110	$	58,259	$	121,396	$	95,071
Other comprehensive income:
Net gains in fair value of derivative instruments (net of tax of $0, $(2,538), $0 and $(4,337), respectively)	—		3,578		—		6,115
Reclassifications of net losses on derivative instruments (net of tax of $(278), $(84), $(556) and $(168), respectively)	392		118		783		237
Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(67), $(139), $(137) and $(278), respectively)	95		198		193		393
Other comprehensive income	487		3,894		976		6,745
Comprehensive income	$	76,597	$	62,153	$	122,372	$	101,816

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)

	Six Months Ended
	March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	121,396		$	95,071
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	29,093			27,283
Deferred income taxes, net	12,109			4,241
Provision for uncollectible accounts	8,716			6,059
Other, net	414			7,537
Net change in:
Accounts receivable and accrued utility revenues	(173,176		)	(136,644		)
Inventories	69,032			51,119
Deferred fuel and power costs, net of changes in unsettled derivatives	(10,181		)	33,311
Accounts payable	25,726			3,688
Other current assets	1,746			12,632
Other current liabilities	38,355			18,120
Net cash provided by operating activities	123,230			122,417
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(65,902		)	(55,519		)
Net costs of property, plant and equipment disposals	(2,948		)	(1,437		)
Decrease in restricted cash	3,181			—
Net cash used by investing activities	(65,669		)	(56,956		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(37,693		)	—
Issuances of long-term debt	175,000			—
Repayments of long-term debt	(175,000		)	—
Decrease in bank loans	(11,000		)	(9,200		)
Other	663			809
Net cash used by financing activities	(48,030		)	(8,391		)
Cash and cash equivalents increase	$	9,531		$	57,070
CASH AND CASH EQUIVALENTS:
End of period	$	14,238		$	58,329
Beginning of period	4,707			1,259
Increase	$	9,531		$	57,070

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 its small Maryland service territory, 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, 2013, 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, 2013 (“Company’s 2013 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. Other comprehensive income 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.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Changes in accumulated other comprehensive loss during the three and six months ended March 31, 2014 are as follows:

	Postretirement			Derivative
Three Months Ended March 31, 2014:	Benefit Plans			Instruments			Total
Balance, December 31, 2013	$	(5,185	)	$	(3,046	)	$	(8,231	)
Reclassification of benefit plan actuarial losses and prior service cost	95			—			95
Reclassifications of net losses on interest rate protection agreements	—			392			392
Balance, March 31, 2014	$	(5,090	)	$	(2,654	)	$	(7,744	)
Six Months Ended March 31, 2014:
Balance, September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
Reclassification of benefit plan actuarial losses and prior service cost	193			—			193
Reclassifications of net losses on interest rate protection agreements	—			783			783
Balance, March 31, 2014	$	(5,090	)	$	(2,654	)	$	(7,744	)

Amounts in the table above are net of tax.

Reclassifications of net losses on interest rate protection agreements are reflected in interest expense on the Condensed Consolidated Statements of Income.

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

Correction of Error. We identified an error in the classification of deferred income tax assets on the March 31, 2013, Condensed Consolidated Balance Sheet. We evaluated the impact of the error and have determined that such error is not material. We have revised the March 31, 2013, Condensed Consolidated Balance Sheet to correct the error which decreased the following Condensed Consolidated Balance Sheet items by $20,709: current deferred income taxes; total current assets and total assets; long-term deferred income tax liabilities; total liabilities; and total liabilities and stockholder’s equity.

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

Adoption of New Accounting Standards

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. Effective October 1, 2013, the Company adopted new accounting guidance regarding disclosures for items reclassified out of accumulated other comprehensive income (“AOCI”). The disclosures required by the new accounting guidance are included in the Note 2 to the condensed consolidated financial statements. The new disclosures are applied prospectively. As this guidance only

- 6 -

affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities. In Fiscal 2014 the Company adopted new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet as a result of an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new disclosures are applied retroactively for all periods presented. The disclosures required are included in Note 10 to the condensed consolidated financial statements. As this guidance only affects disclosure requirements, the adoption of this guidance did 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 2013 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 March 31, 2014:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	513,956	$	480,163	$	33,552	$	241
Cost of sales	$	300,424	$	278,748	$	21,676	$	—
Depreciation and amortization	$	14,643	$	13,575	$	1,068	$	—
Operating income	$	137,954	$	134,560	$	3,492	$	(98	)
Interest expense	$	8,806	$	8,362	$	444	$	—
Income before income taxes	$	129,148	$	126,198	$	3,048	$	(98	)
Total assets (at period end)	$	2,340,617	$	2,195,437	$	145,180	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	31,648	$	30,039	$	1,609	$	—

Three Months Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	395,901	$	368,635	$	26,951	$	315
Cost of sales	$	212,785	$	196,742	$	16,043	$	—
Depreciation and amortization	$	13,712	$	12,731	$	981	$	—
Operating income	$	109,230	$	105,749	$	3,389	$	92
Interest expense	$	9,820	$	9,327	$	493	$	—
Income before income taxes	$	99,410	$	96,422	$	2,896	$	92
Total assets (at period end)	$	2,348,337	$	2,184,816	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	25,791	$	24,430	$	1,361	$	—

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Six Months Ended March 31, 2014:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	812,855	$	751,725	$	60,513	$	617
Cost of sales	$	452,289	$	414,235	$	38,054	$	—
Depreciation and amortization	$	29,093	$	26,959	$	2,134	$	—
Operating income	$	223,797	$	216,613	$	7,181	$	3
Interest expense	$	17,603	$	16,748	$	855	$	—
Income before income taxes	$	206,194	$	199,865	$	6,326	$	3
Total assets (at period end)	$	2,340,617	$	2,195,437	$	145,180	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	65,902	$	62,851	$	3,051	$	—

Six Months Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	669,698	$	616,889	$	52,069	$	740
Cost of sales	$	351,062	$	320,316	$	30,746	$	—
Depreciation and amortization	$	27,283	$	25,336	$	1,947	$	—
Operating income	$	181,794	$	175,538	$	6,013	$	243
Interest expense	$	19,897	$	18,899	$	998	$	—
Income before income taxes	$	161,897	$	156,639	$	5,015	$	243
Total assets (at period end)	$	2,348,337	$	2,184,816	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	55,519	$	52,949	$	2,570	$	—

5.    Inventories

Inventories comprise the following:

	March 31, 2014		September 30, 2013		March 31, 2013
Gas Utility natural gas	$	7,490	$	78,950	$	5,366
Materials, supplies and other	13,139		10,711		10,849
Total inventories	$	20,629	$	89,661	$	16,215

At March 31, 2014, UGI Utilities is a party to four storage contract administrative agreements (“SCAAs”) having terms of one to three years. Three of the SCAAs are with Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (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,

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 March 31, 2014, September 30, 2013 and March 31, 2013, comprising 1.3 billion cubic feet (“bcf”), 11.0 bcf and 1.0 bcf of natural gas, was $5,421, $44,366 and $3,315, respectively. In conjunction with these SCAAs, UGI Utilities held total security deposits received from its SCAA counterparties of $17,600 at March 31, 2014, and $16,500 at September 30, 2013 and March 31, 2013. 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 2013 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:

	March 31, 2014		September 30, 2013		March 31, 2013
Regulatory assets:
Income taxes recoverable	$	106,800	$	106,069	$	104,229
Underfunded pension and postretirement plans	90,996		94,515		181,305
Environmental costs	14,544		17,054		16,841
Deferred fuel and power costs	4,308		8,283		2,122
Removal costs, net	14,379		13,333		11,856
Other	4,904		5,657		5,976
Total regulatory assets	$	235,931	$	244,911	$	322,329
Regulatory liabilities:
Postretirement benefits	$	17,196	$	16,497	$	13,865
Environmental overcollections	1,855		2,552		2,980
Deferred fuel and power refunds	3,204		8,283		31,209
State tax benefits — distribution system repairs	8,998		8,453		7,900
Other	1,895		1,502		700
Total regulatory liabilities	$	33,148	$	37,287	$	56,654

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 March 31, 2014, September 30, 2013, and March 31, 2013, were $2,389, $(1,743) and $4,129, 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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At March 31, 2014, September 30, 2013, and March 31, 2013, the fair values of Electric Utility’s electricity supply contracts were net gains (losses) of $358, $(4,759) and $(5,458), respectively, which amounts are reflected in current derivative financial instrument assets and liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs or refunds 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 March 31, 2014, September 30, 2013, and March 31, 2013, were not material.

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
	March 31,						March 31,
	2014			2013			2014			2013
Service cost	$	1,623		$	2,053		$	41		$	51
Interest cost	5,721			5,196			127			143
Expected return on assets	(6,650		)	(6,198		)	(139		)	(132		)
Amortization of:
Prior service benefit	87			62			(160		)	(105		)
Actuarial loss	1,661			3,366			37			91
Net benefit cost (income)	2,442			4,479			(94		)	48
Change in associated regulatory liabilities	—			—			918			815
Net expense	$	2,442		$	4,479		$	824		$	863
	Pension Benefits						Other Postretirement Benefits
	Six Months Ended						Six Months Ended
	March 31,						March 31,
	2014			2013			2014			2013
Service cost	$	3,246		$	4,105		$	82		$	102
Interest cost	11,442			10,391			254			286
Expected return on assets	(13,299		)	(12,396		)	(278		)	(264		)
Amortization of:
Prior service cost (benefit)	174			124			(320		)	(210		)
Actuarial loss	3,321			6,732			74			182
Net benefit cost	4,884			8,956			(188		)	96
Change in associated regulatory liabilities	—			—			1,836			1,630
Net expense	$	4,884		$	8,956		$	1,648		$	1,726

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 $10,912 to the Pension Plan during the remainder of Fiscal 2014. During the six months endedMarch 31, 2014 and 2013, the Company made contributions to the Pension Plan of $6,972 and $6,393, 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.

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.

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

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 was recently renewed and is scheduled to terminate at the end of 2018. 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 March 31, 2014 and 2013, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11,097 and $14,338, 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 March 31, 2014, 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 UGI Utilities 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.

There are pending claims and legal actions arising in the normal course of our businesses. While the results of these pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, that the final outcome of such 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,

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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.

UGI Utilities is a party to several SCAAs with Energy Services which have terms of one to three years. 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 $248 and $6,695 during the three and six months ended March 31, 2014, respectively, and $702 and $5,026 during the three and six months ended March 31, 2013, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets, were $10,600 as of March 31, 2014, and $16,500 as of September 30, 2013 and March 31, 2013.

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 March 31, 2014, comprising approximately 1.1 bcf of natural gas, was $4,653. The carrying value of these gas storage inventories at September 30, 2013, comprising approximately 10.4 bcf of natural gas, was $41,988. The carrying value of these gas storage inventories at March 31, 2013, comprising approximately 1.0 bcf of natural gas, was $3,315.

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 three and six months ended March 31, 2014 , totaled $13,330 and $32,708, respectively. During the three and six months ended March 31, 2013, such transactions totaled $14,701 and $32,526, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and six months ended March 31, 2014, revenues associated with such sales to Energy Services totaled $75,133 and $92,249, respectively. During the three and six months ended March 31, 2013, revenues associated with such sales to Energy Services totaled $25,428 and $45,252, 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 six months ended March 31, 2014, the aggregate amount of such purchases totaled $70,619 and $92,697, respectively. During the three and six months ended March 31, 2013, the aggregate amount of such purchases totaled $18,213 and $37,233, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.

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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

10.    Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of March 31, 2014, September 30, 2013 and March 31, 2013:

	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
March 31, 2014:
Assets:
Derivative financial instruments:
Commodity contracts	$	2,491		$	730		$	—	$	3,221
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(9	)	$	(363	)	$	—	$	(372	)
September 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	43		$	—		$	—	$	43
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(2,162	)	$	(4,515	)	$	—	$	(6,677	)
March 31, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	4,299		$	—		$	—	$	4,299
Interest rate contracts	$	—		$	4,229		$	—	$	4,229
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(406	)	$	(5,061	)	$	—	$	(5,467	)
Interest rate contracts	$	—		$	(24,298	)	$	—	$	(24,298	)

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 March 31, 2014, were $642,000 and $704,811, respectively. The carrying amount and estimated fair value of our long-term debt at March 31, 2013, were $600,000 and $690,459, 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).

Disclosures About Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on our Condensed Consolidated Balance Sheets if the right of offset exists. Our derivative financial instruments include both over-the-counter transactions and those that are executed on an exchange and centrally cleared. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts may be subject to conditional rights of offset through counterparty nonperformance, insolvency, or other conditions.

In general, most of our over-the-counter transactions and most exchange contracts are subject to collateral requirements. Types of collateral generally includes cash or letters of credit. Any cash collateral paid by us to our derivative counterparties is reflected in the table below to offset derivative liabilities. Any cash collateral received by us from our derivative counterparties is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on our Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the tables below but could reduce our net exposure to such counterparties because they are subject to master netting or similar arrangements.

	Gross Amount Recognized			Gross Amount Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet
March 31, 2014:
Derivative assets	$	3,526		$	(305	)	$	3,221
Derivative (liabilities)	$	(677	)	$	305		$	(372	)
September 30, 2013:
Derivative assets	$	92		$	(49	)	$	43
Derivative (liabilities)	$	(6,726	)	$	49		$	(6,677	)
March 31, 2013:
Derivative assets	$	12,241		$	(3,713	)	$	8,528
Derivative (liabilities)	$	(33,478	)	$	3,713		$	(29,765	)

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

- 16 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 March 31, 2014 and 2013, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.0 million dekatherms and 10.0 million dekatherms, respectively. At March 31, 2014, the maximum period over which Gas Utility is hedging natural gas market price risk is 11 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 March 31, 2014 and 2013, the fair values of Electric Utility’s forward purchase power agreements comprising net gains of $358 and net losses of $5,458, respectively, are reflected in current derivative financial instrument assets and 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 and liabilities. At March 31, 2014 and 2013, the volumes of Electric Utility’s forward electricity purchase contracts were 207.0 million kilowatt hours and 403.2 million kilowatt hours, respectively. At March 31, 2014, the maximum period over which these contracts extend is 8 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 March 31, 2014 and 2013, the volumes associated with Electric Utility FTRs totaled 47.4 million kilowatt hours and 47.5 million kilowatt hours, respectively.

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 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 March 31, 2014 we had no unsettled IRPAs. As of March 31, 2013, the total notional amounts of unsettled IRPAs was $173,000.

- 17 -

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

At March 31, 2014, the amount of net losses associated with settled IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $2,680.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2014 and 2013, there was no restricted cash in brokerage accounts.

The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of March 31, 2014 and 2013:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2014		2013		Location	2014			2013
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	—	$	4,229	Derivative financial instruments	$	—		$	(24,298	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	3,153		4,130		Derivative financial instruments and Other noncurrent liabilities	(372		)	(5,467		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	68		169		Derivative financial instruments	—			—
Total Derivatives		$	3,221	$	8,528		$	(372	)	$	(29,765	)

- 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 the three and six months ended March 31, 2014 and 2013:

Three Months Ended March 31, :
	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2014			2013		2014			2013			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—		$	6,116	$	(670	)	$	(202	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income											Location of Gain (Loss) Recognized in Income
	2014			2013
Commodity contracts	$	(18	)	$	107							Operating expenses/other income, net
Six Months Ended March 31, :
	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2014			2013		2014			2013			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—		$	10,452	$	1,339		$	(405	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income											Location of Gain (Loss) Recognized in Income
	2014			2013
Commodity contracts	$	79		$	105							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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UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

12.     Debt

On March 26, 2014, UGI Utilities issued in a private placement $175,000 of 4.98% Senior Notes due March 26, 2044 (“4.98% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175,000 of borrowings under UGI Utilities’ 364-day term loan credit agreement scheduled to expire in September 2014. The 4.98% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The 4.98% Senior Notes also contain restrictive and financial covenants including a Consolidated Debt to Consolidated Total Capital, as defined therein, of 0.65 to 1.00.

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,” 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, 2013, 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.

- 20 -

UGI UTILITIES, INC. AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended March 31, 2014 (“2014 three-month period”) with the three months ended March 31, 2013 (“2013 three-month period”) and the six months ended March 31, 2014 (“2014 six-month period”) with the six months ended March 31, 2013 (“2013 six-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.

2014 three-month periodcompared with2013 three-month period

Three Months Ended March 31,	2014			2013			Increase
(Millions of dollars)
Gas Utility:
Revenues	$	480.2		$	368.6		$	111.6	30.3	%
Total margin (a)	$	201.4		$	171.9		$	29.5	17.2	%
Operating income	$	134.6		$	105.7		$	28.9	27.3	%
Income before income taxes	$	126.2		$	96.4		$	29.8	30.9	%
System throughput — billions of cubic feet (“bcf”)
Core market	41.8			34.9			6.9		19.8	%
Total	78.5			68.6			9.9		14.4	%
Heating degree days — % colder than normal (b)	19.3		%	1.9		%	—		—
Electric Utility:
Revenues	$	33.6		$	27.0		$	6.6	24.4	%
Total margin (a)	$	10.1		$	9.4		$	0.7	7.4	%
Operating income	$	3.5		$	3.4		$	0.1	2.9	%
Income before income taxes	$	3.0		$	2.9		$	0.1	3.4	%
Distribution sales — millions of kilowatt-hours (“gwh”)	301.7			282.8			18.9		6.7	%

(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 $1.8 million and $1.5 million during the three-month periods ended March 31, 2014 and 2013, 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. Gas Utility experienced significantly colder than normal weather during the three months ended March 31, 2014. Temperatures in the Gas Utility service territory during the 2014 three-month period based upon heating degree days were 19.3% colder than normal and 17.1% colder than the prior-year three-month period. Total distribution system throughput increased 9.9 bcf principally reflecting a 6.9 bcf (19.8%) increase in demand from Gas Utility’s core market customers and, to a lesser extent, greater large firm delivery service volumes. 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 higher than last year principally reflecting the effects of the significantly colder weather and, to a lesser extent, customer growth due principally to conversions from other fuels prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $111.6 million during the 2014 three-month period principally reflecting higher revenues from core market customers ($55.4 million), higher revenues from off-system sales ($47.3 million) and, to a much lesser extent, higher revenues from large firm delivery service customers on higher throughput ($5.8 million). The increase in core market revenues principally reflects the effects of the higher core market throughput and, to a much lesser extent, the effects of slightly higher average purchased gas cost (“PGC”) rates ($1.2 million). Under Gas Utility’s PGC recovery mechanisms, Gas Utility records the

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UGI UTILITIES, INC. AND SUBSIDIARIES

cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $278.7 million in the 2014 three-month period compared with $196.7 million in the prior-year period principally reflecting the effects of the greater retail core-market volumes sold ($31.6 million) and the effects of the higher off-system sales ($47.3 million).

Gas Utility total margin increased $29.5 million in the 2014 three-month period principally reflecting higher core market total margin ($22.9 million) and greater large firm delivery service total margin ($5.5 million). The higher core market and large firm delivery service total margin reflects the effects of the greater throughput to these customers resulting from the significantly colder weather and new customer growth.

Gas Utility operating income and income before income taxes during the 2014 three-month period were $28.9 million and $29.8 million higher than the prior year, respectively. The increase in Gas Utility operating income principally reflects the $29.5 million increase in total margin partially offset by slightly higher operating and administrative expenses which include, among other things, higher uncollectible accounts expense and higher distribution system maintenance expenses offset in part by lower pension and benefit expenses. The increase in Gas Utility income before income taxes reflects the greater operating income ($28.9 million) and lower interest expense principally reflecting lower average interest rates.

Electric Utility. Temperatures based upon heating degree days during the 2014 three-month period were 16.6% colder than normal and approximately 15.5% colder than the prior-year period. The increase in Electric Utility revenues reflects the effects of the colder weather on throughput to heating customers and slightly higher average default service (“DS”) rates. Electric Utility cost of sales increased to $21.7 million in the 2014 three-month period from $16.0 million in the 2013 three-month period principally reflecting the effects of the greater DS rates and the higher sales.

Electric Utility total margin increased $0.7 million reflecting the effects of the higher throughput partially offset by higher gross receipts tax on the higher revenues. Operating income and income before income taxes in the 2014 three-month period each increased $0.1 million, notwithstanding the $0.7 million increase in total margin, principally as a result of higher uncollectible accounts and distribution system expenses.

Interest Expense and Income Taxes. Our consolidated interest expense in the 2014three-month period was lower than the prior year principally reflecting lower average interest rates. Our effective income tax rate for the three months ended March 31, 2014, was approximately equal to the prior-year three-month period.

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UGI UTILITIES, INC. AND SUBSIDIARIES

2014 six-month periodcompared with2013 six-month period

Six Months Ended March 31,	2014			2013			Increase
(Millions of dollars)
Gas Utility:
Revenues	$	751.7		$	616.9		$	134.8	21.9	%
Total margin (a)	$	337.5		$	296.6		$	40.9	13.8	%
Operating income	$	216.6		$	175.5		$	41.1	23.4	%
Income before income taxes	$	199.9		$	156.6		$	43.3	27.7	%
System throughput — billions of cubic feet (“bcf”)
Core market	65.9			56.7			9.2		16.2	%
Total	135.3			122.7			12.6		10.3	%
Heating degree days — % colder (warmer) than normal (b)	12.5		%	(0.4		)%	—		—
Electric Utility:
Revenues	$	60.5		$	52.1		$	8.4	16.1	%
Total margin (a)	$	19.2		$	18.5		$	0.7	3.8	%
Operating income	$	7.2		$	6.0		$	1.2	20.0	%
Income before income taxes	$	6.3		$	5.0		$	1.3	26.0	%
Distribution sales — millions of kilowatt-hours (“gwh”)	558.1			531.0			$	27.1	5.1	%

(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 $3.3 million and $2.8 million during the six-month periods ended March 31, 2014 and 2013, 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 2014 six-month period based upon heating degree days were 12.5% colder than normal and 12.9% colder than the prior-year six-month period. Total distribution system throughput increased 12.6 bcf principally reflecting a 9.2 bcf (16.2%) increase in demand from Gas Utility’s core market customers. Gas Utility system throughput to core-market customers was higher than last year principally reflecting the effects of the significantly colder weather and, to a lesser extent, customer growth due principally to conversions from other fuels prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $134.8 million during the 2014 six-month period principally reflecting higher revenues from core market customers ($77.2 million), higher revenues from off-system sales ($45.5 million) and, to a much lesser extent, higher revenues from large firm delivery service customers on higher throughput ($8.7 million). The increase in core market revenues principally reflects the effects of the higher core market throughput. Gas Utility’s cost of gas was $414.2 million in the 2014 six-month period compared with $320.3 million in the prior-year period principally reflecting the effects of the greater retail core-market volumes sold ($43.2 million) and the effects of the higher off-system sales ($45.5 million).

Gas Utility total margin increased $40.9 million in the 2014 six-month period principally reflecting higher core market total margin ($30.7 million) and greater large firm delivery service total margin ($8.7 million). The higher core market and large firm delivery service total margin reflects the effects of the colder weather and new customer growth.

Gas Utility operating income and income before income taxes during the 2014 six-month period were $41.1 million and $43.3 million higher than the prior year, respectively. The increase in Gas Utility operating income principally reflects the $40.9 million increase in total margin. Operating expenses were about equal to the prior year six-month period as greater 2014 six-month period uncollectible accounts expense was offset principally by lower distribution system maintenance expenses and lower pension and

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UGI UTILITIES, INC. AND SUBSIDIARIES

benefit expenses. The increase in Gas Utility income before income taxes reflects the greater operating income ($41.1 million) and lower interest expense principally reflecting lower average interest rates.

Electric Utility. Temperatures based upon heating degree days during the 2014 six-month period were approximately 9.7% colder than normal and approximately 11.4% colder than the prior-year period. The increase in Electric Utility revenues reflects the effects of the colder weather on throughput to residential and commercial customers primarily for heating purposes and higher average default service (“DS”) rates. Electric Utility cost of sales increased to $38.1 million in the 2014 six-month period from $30.7 million in the 2013 six-month period principally reflecting the effects of the greater DS rates and the higher sales.

Electric Utility total margin increased $0.7 million reflecting the effects of the higher throughput partially offset by higher gross receipts taxes on the higher revenues. Operating income and income before income taxes in the 2014 six-month period increased $1.2 million and $1.3 million, respectively, principally as a result of the higher total margin ($0.7 million) and lower operating costs. Operating costs in the prior-year period reflect higher distribution system costs associated with Hurricane Sandy.

Interest Expense and Income Taxes. Our consolidated interest expense in the 2014 six-month period was lower than the prior year principally reflecting lower average interest rates. Our effective income tax rate for the six months ended March 31, 2014, was approximately equal to the prior-year six-month period.

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

The Company’s total debt outstanding at March 31, 2014, was $648.5 million, including $6.5 million of bank loans, compared to debt outstanding of $659.5 million at September 30, 2013, which includes $17.5 million of bank loans. UGI Utilities’ long-term debt outstanding at March 31, 2014, comprises $450 million of Senior Notes and $192 million of Medium-Term Notes.

In March 2014, UGI Utilities issued in a private placement $175 million of 4.98% Senior Notes due March 26, 2044 (“4.98% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175 million of borrowings under UGI Utilities’ 364-day term loan credit agreement scheduled to expire in September 2014. The 4.98% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The 4.98% Senior Notes also contain restrictive and financial covenants including a Consolidated Debt to Consolidated Total Capital, as defined therein, of 0.65 to 1.00.

UGI Utilities may borrow up to a total of $300 million (including a $100 million sublimit for letters of credit) under its credit agreement (“Credit Agreement”). The Credit Agreement expires in October 2015. During the 2014 and 2013six-month periods, average daily bank loan borrowings were $45.6 million and $53.5 million, respectively, and peak bank loan borrowings totaled $84.0 million and $78.6 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 Credit Agreement to meet our anticipated contractual and projected cash commitments.

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 Credit Agreement to manage seasonal cash flow needs.

Cash provided by operating activities was $123.2 million in the 2014 six-month period compared to $122.4 million in the prior-year six-month period. Cash flow from operating activities before changes in operating working capital was $171.7 million in the 2014 six-month period compared to $140.2 million recorded in the prior-year six-month period principally reflecting the higher 2014 six-month period operating results. Changes in operating working capital used $48.5 million of operating cash flow during the 2014 six-month period compared to $17.8 million of cash used during the prior-year six-month period. The higher cash used

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UGI UTILITIES, INC. AND SUBSIDIARIES

to fund changes in operating working capital in the 2014 six-month period reflects, among other things, higher cash used to fund changes in accounts receivable and lower net cash from the PGC recovery mechanism.

Investing activities. Cash used by investing activities was $65.7 million in the 2014 six-month period compared to $57.0 million in the 2013 six-month period. Total capital expenditures were $65.9 million in the 2014 six-month period compared with $55.5 million recorded in the prior-year period. The 2014 six-month period principally reflects higher Gas Utility capital expenditures. Changes in restricted cash in futures brokerage accounts provided provided $3.2 million of cash in the 2014 six-month period period.

Financing activities. Cash used by financing activities was $48.0 million in the 2014 six-month period compared with $8.4 million in the 2013 six-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 2014 six-month period there were net bank loan repayments of $11.0 million compared with net repayments of $9.2 million during the prior-year six-month period. Cash dividends in the 2014 six-month period totaled $37.7 million. There were no cash dividends paid during the six months ended March 31, 2013. In March 2014, UGI Utilities issued $175 million of 4.98% Senior Notes due March 26, 2044. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175 million of borrowings under UGI Utilities’ term loan credit agreement.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 March 31, 2014 and 2013, UGI Utilities had no restricted cash associated with futures accounts. At March 31, 2014 and 2013, the fair values of our natural gas futures and option contracts were net gains of $2.4 million and $4.1 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 March 31, 2014 and 2013, the fair values of Electric Utility’s electricity supply contracts were net gains (losses) of $0.4 million and $(5.5) million, respectively. At March 31, 2014 and 2013, the fair values of FTRs were not material.

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 March 31, 2014 and 2013 are 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”). There were no outstanding IRPAs at March 31, 2014. The fair values of unsettled IRPAs held at March 31, 2013, were net losses of $20.1 million.

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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, 2013, 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 last date of the period for which it was filed, and the exhibit number in such filing):

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UGI UTILITIES, INC. AND SUBSIDIARIES

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.1	FSS Service Agreement No. 79028 effective as of April 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.
10.2	SST Service Agreement No. 79133 effective as of April 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.
10.3	UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective November 22, 2013.	UGI	Form 10-Q (3/31/14)	10.3
10.4	UGI Corporation 2009 Supplemental Executive Retirement Plan for New Employees, as Amended and Restated effective November 22, 2013.	UGI	Form 10-Q (3/31/14)	10.4
10.5	UGI Corporation 2009 Deferral Plan, as Amended and Restated Effective January 24, 2014.	UGI	Form 10-Q (3/31/14)	10.5
10.6	UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Employees, dated January 1, 2014.	UGI	Form 10-Q (3/31/14)	10.7
10.7	UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2014.	UGI	Form 10-Q (3/31/14)	10.9
10.8	UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2014.	UGI	Form 10-Q (3/31/14)	10.11
10.9	UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2014.	UGI	Form 10-Q (3/31/14)	10.12
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 March 31, 2014, 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 March 31, 2014, 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 March 31, 2014, 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:	May 9, 2014	By:	/s/ Donald E. Brown
			Donald E. Brown Vice President - Finance and Chief Financial Officer
Date:	May 9, 2014	By:	/s/ Matthew J. Nolan
			Matthew J. Nolan  Controller

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UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX

10.1	FSS Service Agreement No. 79028 effective as of April 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc.
10.2	SST Service Agreement No. 79133 effective as of April 1, 2014 by and 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 March 31, 2014, 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 March 31, 2014, 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 March 31, 2014, 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

Service Agreement No. 79028

Revision No. 3

FSS SERVICE AGREEMENT

THIS AGREEMENT is made and entered into this 21st day of March, 2014, 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 as follows:

Section 1.    Service to be Rendered. Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FSS Rate Schedule and applicable General Terms and Conditions of Transporter’s FERC Gas Tariff, Fourth Revised Volume No. 1 (“Tariff”), on file with the Federal Energy Regulatory Commission (“Commission”), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. Transporter shall store quantities of gas for Shipper up to but not exceeding Shipper’s Storage Contract Quantity as specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission.

Section 2.    Term. Service under this Agreement shall commence as of April 1, 2014, and shall continue in full force and effect until March 31, 2017. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commission’s regulations and Transporter’s Tariff.

Section 3.    Rates. Shipper shall pay Transporter the charges and furnish the Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporter’s maximum rate, but not less than Transporter’s minimum rate. Such discounted rate may apply to: (a) specified quantities (contract demand or commodity quantities); (b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; (c) quantities during specified time periods; (d) quantities at specified points, locations, or other defined geographical area; (e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specific relationship to quantities actually transported); (f) production and/or reserves committed by the Shipper; and (g) based on a formula including, but not limited to, published index prices for specific receipt and/or delivery points or other agreed-upon pricing points, provided that the resulting rate shall be no lower than the minimum nor higher than the maximum applicable rate set forth in the Tariff. In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporter’s maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sections. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates, which had been charged under a discount agreement, exceeded rates which ultimately are found to be just and reasonable.

Section 4.    Notices. Notices to Transporter under this Agreement shall be addressed to it at 5151 San Felipe, Suite 2500, Houston, Texas 77056, Attention: Customer Services and notices to Shipper shall be addressed to it at UGI Utilities, Inc., 2525 N. 12^th Street, Reading, PA 19605, Attention: Claire Neri, until changed by either party by written notice.

Section 5.    Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreement(s): FSS No. 79028, Revision No. 2.

UGI UTILITIES, INC.                    COLUMBIA GAS TRANSMISSION, LLC

By        By    

Title        Title    

Date        Date    

Revision 3

Appendix A to Service Agreement No. 79028

Under Rate Schedule FSS

between Columbia Gas Transmission, LLC (“Transporter”)

and UGI Utilities, Inc. (“Shipper”)

Storage Contract Quantity

Begin                End                Storage Contract            Maximum Daily Storage

DateDateQuantity (Dth)Quantity (Dth/day)

April 1, 2014            March 31, 2017            5,090,400                93,867

X Yes No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporter’s FERC Gas Tariff.

Yes X     No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporter’s FERC Gas Tariff.

Yes X     No (Check applicable blank) This Service Agreement covers interim capacity sold pursuant to the provisions of General Terms and Conditions Section 4. Right of first refusal rights, if any, applicable to this interim capacity are limited as provided for in General Terms and Conditions Section 4.

Yes X     No (Check applicable blank) This Service Agreement covers offsystem capacity sold pursuant to section 47 of the General Terms and Conditions. Right of first refusal rights, if any, applicable to this offsystem capacity are limited as provided for in General Terms and Conditions Section 47.

UGI UTILITIES, INC.                            COLUMBIA GAS TRANSMISSION, LLC

By            By    

Title            Title    

Date            Date    

EX-10.2

EXHIBIT 10.2

Service Agreement No. 79133

Revision No. 4

SST SERVICE AGREEMENT

THIS AGREEMENT is made and entered into this 21st day of March, 2014, 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 as follows:

Section 1.    Service to be Rendered. Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective SST Rate Schedule and applicable General Terms and Conditions of Transporter’s FERC Gas Tariff, Fourth Revised Volume No. 1 (“Tariff”), on file with the Federal Energy Regulatory Commission (“Commission”), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission.

Section 2.    Term. Service under this Agreement shall commence as of April 1, 2014, and shall continue in full force and effect until March 31, 2017. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commission’s regulations and Transporter’s Tariff.

Section 3.    Rates. Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporter’s maximum rate, but not less than Transporter’s minimum rate. Such discounted rate may apply to: (a) specified quantities (contract demand or commodity quantities); (b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; (c) quantities during specified time periods; (d) quantities at specified points, locations, or other defined geographical areas; (e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported); (f) production and/or reserves committed by the Shipper; and (g) based on a formula including, but not limited to, published index prices for specific receipt and/or delivery points or other agreed-upon pricing points, provided that the resulting rate shall be no lower than the minimum nor higher than the maximum applicable rate set forth in the Tariff. In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporter’s maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sections. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates, which had been charged under a discount agreement, exceeded rates which ultimately are found to be just and reasonable.

Section 4.    Notices. Notices to Transporter under this Agreement shall be addressed to it at 5151 San Felipe, Suite 2500, Houston, Texas 77056, Attention: Customer Services and notices to Shipper shall be addressed to it at UGI Utilities, Inc., 2525 N. 12^th Street, Reading, PA 19605, Attention: Claire Neri, until changed by either party by written notice.

Section 5.    Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreement(s): SST No. 79133, Revision No. 3.

UGI UTILITIES, INC.                    COLUMBIA GAS TRANSMISSION, LLC

By        By    

Title        Title    

Date        Date    

Revision No. 4

Appendix A to Service Agreement No. 79133

Under Rate Schedule SST

between Columbia Gas Transmission, LLC (“Transporter”)

and UGI Utilities, Inc. (“Shipper”)

Transportation Demand

Begin Date	End Date	Transportation Demand (Dth/day)	Recurrence Interval
April 1, 2014	March 31, 2017	93,867	10/1 – 3/31
April 1, 2014	March 31, 2017	46,933	4/1 – 9/30

Primary Receipt Points

Begin Date	End Date	Scheduling Point No.	Scheduling Point Name	Maximum Daily Quantity (Dth/day)	Recurrence Interval
April 1, 2014	March 31, 2017	STOR	RP Storage Point TCO	93,867	10/1 – 3/31
April 1, 2014	March 31, 2017	STOR	RP Storage Point TCO	46,933	4/1 – 9/30

Primary Delivery Points

Begin Date	End Date	Scheduling Point No.	Scheduling Point Name	Measuring Point No.	Measuring Point Name	Maximum Daily Delivery Obligation (Dth/day) 1/	Design Daily Quantity (Dth/day) 1/	Minimum Delivery Pressure Obligation (psig) 1/	Recurrence Interval
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600012	ROSEDALE	6,170		100	10/1 – 3/31
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600013	TATAMY	7,800		400	10/1 – 3/31
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600018	BOYERTOWN	4,050		400	10/1 – 3/31

Primary Delivery Points

Begin Date	End Date	Scheduling Point No.	Scheduling Point Name	Measuring Point No.	Measuring Point Name	Maximum Daily Delivery Obligation (Dth/day) 1/	Design Daily Quantity (Dth/day) 1/	Minimum Delivery Pressure Obligation (psig) 1/	Recurrence Interval
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600020	BIRDSBORO	22,340		400	10/1 – 3/31
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600021		20,811			10/1 – 3/31
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600023	Bally	11,000			10/1 – 3/31
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600032		20,811			10/1 – 3/31
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	637254	UGI/CONECTIV	85,000		430	10/1 – 3/31
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600012	ROSEDALE	4,381		100	4/1 – 9/30
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600013	TATAMY	5,538		400	4/1 – 9/30
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600018	BOYERTOWN	2,876		400	4/1 – 9/30
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600020	BIRDSBORO	15,861		400	4/1/ - 9/30
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600021		14,776			4/1 – 9/30
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600023	Bally	7,810			4/1 – 9/30
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	600032		14,776			4/1 – 9/30
April 1, 2014	March 31, 2017	72-23	UGI CORP-23	637254	UGI/CONECTIV	60,350		430	4/1 – 9/30
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600019	MILLWAY	15,376		400	10/1 – 3/31
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600030	HARRISBURG	30,005		400	10/1 – 3/31
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600033	MT. JOY	1,686		100	10/1 – 3/31
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600036	LITITZ	2,976		300	10/1 – 3/31
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600037	MANHEIM	1,488		150	10/1 – 3/31
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600038	NEW HOLLAND	22,356		200	10/1 – 3/31
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	603470	MARIETTA	13,800		400	10/1 – 3/31
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	604626	LOCUST POINT	27,700		500	10/1 – 3/31

April 1, 2014	March 31, 2017	72-25	UGI CORP-25	630112	UGI Morgantown	2,500	60	10/1 – 3/31
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600019	MILLWAY	10,917	400	4/1 – 9/30
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600030	HARRISBURG	21,304	400	4/1 – 9/30
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600033	MT. JOY	1,197	100	4/1 – 9/30

Primary Delivery Points

Begin Date	End Date	Scheduling Point No.	Scheduling Point Name	Measuring Point No.	Measuring Point Name	Maximum Daily Delivery Obligation (Dth/day) 1/	Design Daily Quantity (Dth/day) 1/	Minimum Delivery Pressure Obligation (psig) 1/	Recurrence Interval
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600036	LITITZ	2,113		300	4/1 – 9/30
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600037	MANHEIM	1,056		150	4/1 – 9/30
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	600038	NEW HOLLAND	15,873		200	4/1 – 9/30
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	603470	MARIETTA	9,798		400	4/1 – 9/30
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	604626	LOCUST POINT	19,667		500	4/1 – 9/30
April 1, 2014	March 31, 2017	72-25	UGI CORP-25	630112	UGI Morgantown	1,775		60	4/1 – 9/30
April 1, 2014	March 31, 2017	C22	EAGLE-25	632170	EAGLE C.S. (74-0000	0			10/1 – 3/31
April 1, 2014	March 31, 2017	C22	EAGLE-25	632170	EAGLE C.S. (74-0000	0			4/1 – 9/30
April 1, 2014	March 31, 2017	C23	PENNSBURG-23	631929	PENNSBURG (74-0000	0			10/1 – 3/31
April 1, 2014	March 31, 2017	C23	PENNSBURG-23	631929	PENNSBURG (74-0000	0			4/1 – 9/30

1/    Application of MDDOs, DDQs and ADQs, minimum pressure and/or hourly flowrate shall be as follows:

FN01     Transporter’s historic practice of providing Shipper flexibility in meeting the hourly variations in its requirements at city-gate delivery points under its service agreements, within the daily firm obligations set forth in Shipper’s contracts, will continue unless it becomes inconsistent with the terms of Transporter’s FERC Gas Tariff, as that Tariff may be changed from time to time, or unless Transporter issues an operational flow chart (“OFO”) limiting hourly deliveries in the manner described herein. If such an OFO is issued, Shipper will be entitled to receive hourly deliveries of 110% of 1/24th of the quantity of gas scheduled on a Gas Day, or such higher quantity as may be specified in the OFO, at its primary delivery points during any five hours falling between 5 a.m. and 9 a.m. eastern clock time or between 5 p.m. and 9 p.m. eastern clock time, respectively, as determined by Shipper (the “Hourly Flow Rate”). Notwithstanding the foregoing, Transporter may issue an OFO directed at Shipper’s delivery points and requiring a lower Hourly Flow Rate based upon the occurrence of an event specified in Section 17 of the General Terms and Conditions of Transporter’s FERC Gas Tariff that materially affects Transporter’s ability to serve Market Areas 23 and/or 25 and requiring the issuance of an OFO specifically limiting the Hourly Flow Rate to Shipper. Transporter reserves the right, if operationally necessary, to require that Shipper take its Hourly Flow Rate at its citygate delivery points on a pro rata basis based on the MDDOs at those delivery points.

FN02    [POINTS: 600013, 600023, 600021, 600020, 600018, 600012, 637254, 632710, 631929, 600032] Measuring Point No. 600021, 600023, 600032, 631929, and 632170 (Group No. 1) are in the Texas Eastern Directs Aggregate Area and the Line 1278 North Aggregate Area.

Measuring Point Nos. 600012, 600013, 600018, 600020, and 637254 (Group No. 2) are in the Line 1278 North Aggregate Area.

Unless station specific MDDOs are specified in a separate firm service agreement between Transporter and Shipper, Transporter’s Aggregate Maximum Daily Delivery Obligation, under this and any other service agreement between Transporter and Shipper, at the stations listed above shall not exceed the MDDO quantities set forth above for each station. In addition, Transporter shall not be obligated on any day to deliver more than the Aggregate Daily Quantities (ADQ) listed below in the Aggregate Areas listed below. The stations in Group Nos. 1 or 2 are in the Aggregate Areas set forth in greater detail below. Any station specific MDDOs in a separate firm service agreement between Transporter and Shipper shall be additive both to the individual station MDDOs set forth herein and to any applicable Aggregate Daily Quantity set forth below.

Group No.	Aggregate Area Name	Aggregate Daily Quantity
1	Texas Eastern Directs Aggregate Area (From November 1 – March 31)	20,811 DTH/D
1	Texas Eastern Directs Aggregate Area (From April 1 – October 31)	22,524 DTD/D
1 + 2	ADQ for Aggregate Area Group Nos. 1 and 2	100,000 DTD/D

The Master List of Interconnects (“MLI”) as defined in Section 1 of the General Terms and Conditions of Transporter’s FERC Gas Tariff is incorporated herein by reference for purposes of listing valid secondary interruptible receipt and delivery points.

X Yes No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporter’s FERC Gas Tariff.

Yes X     No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporter’s FERC Gas Tariff.

Yes X     No (Check applicable blank) The MDDOs, ADQs, and/or DDQs set forth in Appendix A to Shipper’s _______ Service Agreement No. _______ are incorporated herein by reference.

Yes X     No (Check applicable blank) This Service Agreement covers interim capacity sold pursuant to the provisions of General Terms and Conditions Section 4. Right of first refusal rights, if any, applicable to this interim capacity are limited as provided for in General Terms and Conditions Section 4.

Yes X     No (Check applicable blank) This Service Agreement covers offsystem capacity sold pursuant to Section 47 of the General Terms and Conditions. Right of first refusal rights, if any, applicable to this offsystem capacity are limited as provided for in General Terms and Conditions Section 47.

UGI UTILITIES, INC.                            COLUMBIA GAS TRANSMISSION, LLC

By            By    

Title            Title    

Date            Date    

EX-12.1

UGI UTILITIES, INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1

(Thousands of dollars)

	Six Months Ended March 31,
			Year Ended September 30,
	2014		2013		2012		2011		2010
Earnings:
Earnings before income taxes	$	206,194	$	171,010	$	142,971	$	168,693	$	147,183
Interest expense	17,603		39,309		42,412		42,728		42,336
Amortization of debt discount and
expense	283		731		814		1,060		627
Estimated interest component of
rental expense	1,010		2,090		2,121		1,740		1,912
	$	225,090	$	213,140	$	188,318	$	214,221	$	192,058
Fixed Charges:
Interest expense	$	17,603	$	39,309	$	42,412	$	42,728	$	42,336
Amortization of debt discount and
expense	283		731		814		1,060		627
Allowance for funds used during
construction (capitalized interest)	201		286		10		90		74
Estimated interest component of
rental expense	1,010		2,090		2,121		1,740		1,912
	$	19,097	$	42,416	$	45,357	$	45,618	$	44,949
Ratio of earnings to fixed charges	11.79		5.02		4.15		4.70		4.27

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: May 9, 2014

/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: May 9, 2014

/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 March 31, 2014 (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:	May 9, 2014	Date:	May 9, 2014

XML

Fair Value Measurements - Narrative (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Fair Value Disclosures [Abstract]
Carrying amount of long-term debt	$ 642,000	$ 600,000
Long-term Debt, Fair Value	$ 704,811	$ 690,459

XML

Debt (Details) (USD $)	0 Months Ended
	Mar. 26, 2014
4.98% Senior Notes
Debt Instrument
Proceeds from 4.98% Senior Note	$ 175,000
Interest Rate	4.98%
Debt to Capital Ratio	0.65
Term Loan, 364-day Credit Agreement
Debt Instrument
Debt Repayment	$ 175,000
Debt Instrument, Term	364 days

XML

Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013
Gas Utility Derivative Financial Instruments
Regulatory Assets
Gas utility unrealized gain (losses) on derivative financial instrument contracts	$ 2,389	$ (1,743)	$ 4,129
Electric Utility Forward Supply Contracts
Regulatory Assets
Net gains (losses) on electricity supply contracts	$ 358	$ (4,759)	$ (5,458)

XML

Defined Benefit Pension and Other Postretirement Plans (Tables)

6 Months Ended

Mar. 31, 2014

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

Schedule of components 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
	March 31,						March 31,
	2014			2013			2014			2013
Service cost	$	1,623		$	2,053		$	41		$	51
Interest cost	5,721			5,196			127			143
Expected return on assets	(6,650		)	(6,198		)	(139		)	(132		)
Amortization of:
Prior service benefit	87			62			(160		)	(105		)
Actuarial loss	1,661			3,366			37			91
Net benefit cost (income)	2,442			4,479			(94		)	48
Change in associated regulatory liabilities	—			—			918			815
Net expense	$	2,442		$	4,479		$	824		$	863
	Pension Benefits						Other Postretirement Benefits
	Six Months Ended						Six Months Ended
	March 31,						March 31,
	2014			2013			2014			2013
Service cost	$	3,246		$	4,105		$	82		$	102
Interest cost	11,442			10,391			254			286
Expected return on assets	(13,299		)	(12,396		)	(278		)	(264		)
Amortization of:
Prior service cost (benefit)	174			124			(320		)	(210		)
Actuarial loss	3,321			6,732			74			182
Net benefit cost	4,884			8,956			(188		)	96
Change in associated regulatory liabilities	—			—			1,836			1,630
Net expense	$	4,884		$	8,956		$	1,648		$	1,726

XML

Disclosures About Derivative Instruments and Hedging Activities - Narrative (Details) (USD $) In Thousands, unless otherwise specified										3 Months Ended
	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013	Mar. 31, 2014 Gas Utility DTH	Mar. 31, 2013 Gas Utility DTH	Mar. 31, 2014 Electric Utility kWh	Mar. 31, 2013 Electric Utility kWh	Mar. 31, 2014 Electric Utility Electric Utility electric transmission congestion kWh	Mar. 31, 2013 Electric Utility Electric Utility electric transmission congestion kWh	Dec. 31, 2012 Interest Rate Swap [Member]	Mar. 31, 2014 Interest Rate Protection Agreements	Mar. 31, 2013 Interest Rate Protection Agreements
Derivative
Other Income										$ 0
Notional amount (in units)				9,000,000	10,000,000	207,000,000	403,200,000	47,400,000	47,500,000
Maximum length of time hedged in price risk cash flow hedges (in months)				11 months		8 months
Total Derivatives Liability	677	6,726	33,478			358	(5,458)
Underlying variable rate debt											0	173,000
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months											2,680
Restricted Cash in brokerage accounts	$ 0	$ 3,181	$ 0

XML

Commitments and Contingencies - Narrative (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
CPG MGP
Commitments and Contingencies
Environmental Remediation Expense	$ 1,800
PNG MGP
Commitments and Contingencies
Environmental Remediation Expense	1,100
CPG and PNG COAs
Commitments and Contingencies
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	$ 11,097	$ 14,338
Environmental Issue
Commitments and Contingencies
Base year for determination of investigation and remediation cost (in years)	5 years

XML

Significant Accounting Policies

6 Months Ended

Mar. 31, 2014

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, 2013, 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, 2013 (“Company’s 2013 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. Other comprehensive income 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.

Changes in accumulated other comprehensive loss during the three and six months ended March 31, 2014 are as follows:

	Postretirement			Derivative
Three Months Ended March 31, 2014:	Benefit Plans			Instruments			Total
Balance, December 31, 2013	$	(5,185	)	$	(3,046	)	$	(8,231	)
Reclassification of benefit plan actuarial losses and prior service cost	95			—			95
Reclassifications of net losses on interest rate protection agreements	—			392			392
Balance, March 31, 2014	$	(5,090	)	$	(2,654	)	$	(7,744	)
Six Months Ended March 31, 2014:
Balance, September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
Reclassification of benefit plan actuarial losses and prior service cost	193			—			193
Reclassifications of net losses on interest rate protection agreements	—			783			783
Balance, March 31, 2014	$	(5,090	)	$	(2,654	)	$	(7,744	)

Amounts in the table above are net of tax.

Reclassifications of net losses on interest rate protection agreements are reflected in interest expense on the Condensed Consolidated Statements of Income.

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

Correction of Error. We identified an error in the classification of deferred income tax assets on the March 31, 2013, Condensed Consolidated Balance Sheet. We evaluated the impact of the error and have determined that such error is not material. We have revised the March 31, 2013, Condensed Consolidated Balance Sheet to correct the error which decreased the following Condensed Consolidated Balance Sheet items by $20,709: current deferred income taxes; total current assets and total assets; long-term deferred income tax liabilities; total liabilities; and total liabilities and stockholder’s equity.

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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Disclosures About Derivative Instruments and Hedging Activities - Balance Sheet Location and Fair Value of Derivative Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013
Derivatives, Fair Value
Derivative Assets, Fair Value, Net Amount	$ 3,221	$ 43	$ 8,528
Derivative Liabilities, Net Amount	(372)	(6,677)	(29,765)
Interest rate contracts | Derivatives Designated as Hedging Instruments | Derivative financial instruments, assets
Derivatives, Fair Value
Derivative Assets, Fair Value, Net Amount	0		4,229
Interest rate contracts | Derivatives Designated as Hedging Instruments | Derivative financial instruments, liabilities
Derivatives, Fair Value
Derivative Liabilities, Net Amount	0		(24,298)
Commodity contracts | Derivatives Subject to Utility Rate Regulation | Derivative financial instruments, assets
Derivatives, Fair Value
Derivative Assets, Fair Value, Net Amount	3,153		4,130
Commodity contracts | Derivatives Subject to Utility Rate Regulation | Derivative financial instruments and other noncurrent liabilities
Derivatives, Fair Value
Derivative Liabilities, Net Amount	(372)		(5,467)
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Derivative financial instruments, assets
Derivatives, Fair Value
Derivative Assets, Fair Value, Net Amount	68		169
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Derivative financial instruments, liabilities
Derivatives, Fair Value
Derivative Liabilities, Net Amount	$ 0		$ 0

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Significant Accounting Policies Significant Accounting Policies - Phantom (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2012
Condensed Balance Sheet Statements, Captions
Quantifying Misstatement in Current Year Financial Statements, Amount	$ 20,709
Current Deferred Income Tax
Condensed Balance Sheet Statements, Captions
Quantifying Misstatement in Current Year Financial Statements, Amount	20,700
Total Current Assets
Condensed Balance Sheet Statements, Captions
Quantifying Misstatement in Current Year Financial Statements, Amount	20,700
Total Assets
Condensed Balance Sheet Statements, Captions
Quantifying Misstatement in Current Year Financial Statements, Amount	20,700
Long-term Deferred Income Tax Liability
Condensed Balance Sheet Statements, Captions
Quantifying Misstatement in Current Year Financial Statements, Amount	20,700
Total Liabilities
Condensed Balance Sheet Statements, Captions
Quantifying Misstatement in Current Year Financial Statements, Amount	20,700
Total Liabilities and Stockholders' Equity
Condensed Balance Sheet Statements, Captions
Quantifying Misstatement in Current Year Financial Statements, Amount	$ 20,700

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Significant Accounting Policies - Schedule of Changes in AOCI (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Sep. 30, 2013
Schedule of Accumulated Other Comprehensive Income
Accumulated other comprehensive loss	$ (7,744)	$ (23,072)		$ (7,744)	$ (23,072)	$ (8,231)	$ (8,720)
Reclassification of benefit plan actuarial losses and prior service cost	95			193
Reclassifications of net losses on interest rate protection agreements	392	118		783	237
Quantifying Misstatement in Current Year Financial Statements, Amount			20,709
Derivative
Schedule of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(2,654)			(2,654)		(3,046)	(3,437)
Reclassification of benefit plan actuarial losses and prior service cost	0			0
Reclassifications of net losses on interest rate protection agreements	392			783
Other Pension Plan, Postretirement or Supplemental Plans, Defined Benefit [Member]
Schedule of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(5,090)			(5,090)		(5,185)	(5,283)
Reclassification of benefit plan actuarial losses and prior service cost	(95)			(193)
Reclassifications of net losses on interest rate protection agreements	$ 0			$ 0

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Disclosures About Derivative Instruments and Hedging Activities - Effects of Derivatives on Statements of Income and AOCI (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Derivatives Not Designated as Hedging Instruments | Commodity contracts | Operating expenses/other income, net
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	$ (18)	$ 107	$ 79	$ 105
Cash Flow Hedges | Interest rate contracts | Interest expense, net
Derivative Instruments, Gain (Loss)
Gain or (loss) recognized in AOCI	0	6,116	0	10,452
Gain (loss) reclassified from AOCI into income	$ (670)	$ (202)	$ 1,339	$ (405)

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Segment Information - Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014 Segment	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Sep. 30, 2013
Segment Reporting Information
Revenues	$ 513,956	$ 395,901	$ 812,855	$ 669,698
Cost of sales	300,424	212,785	452,289	351,062
Depreciation and amortization	14,643	13,712	29,093	27,283
Operating income	137,954	109,230	223,797	181,794
Interest expense	8,806	9,820	17,603	19,897
Income before income taxes	129,148	99,410	206,194	161,897
Total assets (at period end)	2,340,617	2,348,337	2,340,617	2,348,337	2,210,322
Goodwill (at period end)	182,145	182,145	182,145	182,145	182,145
Capital expenditures	31,648	25,791	65,902	55,519
Number of reportable segments (in segments)	2
Concentration risk, percentage	10.00%
Gas Utility
Segment Reporting Information
Revenues	480,163	368,635	751,725	616,889
Cost of sales	278,748	196,742	414,235	320,316
Depreciation and amortization	13,575	12,731	26,959	25,336
Operating income	134,560	105,749	216,613	175,538
Interest expense	8,362	9,327	16,748	18,899
Income before income taxes	126,198	96,422	199,865	156,639
Total assets (at period end)	2,195,437	2,184,816	2,195,437	2,184,816
Goodwill (at period end)	182,145	182,145	182,145	182,145
Capital expenditures	30,039	24,430	62,851	52,949
Electric Utility
Segment Reporting Information
Revenues	33,552	26,951	60,513	52,069
Cost of sales	21,676	16,043	38,054	30,746
Depreciation and amortization	1,068	981	2,134	1,947
Operating income	3,492	3,389	7,181	6,013
Interest expense	444	493	855	998
Income before income taxes	3,048	2,896	6,326	5,015
Total assets (at period end)	145,180	163,521	145,180	163,521
Goodwill (at period end)	0	0	0	0
Capital expenditures	1,609	1,361	3,051	2,570
Counties of operation, number	2
Other
Segment Reporting Information
Revenues	241	315	617	740
Cost of sales	0	0	0	0
Depreciation and amortization	0	0	0	0
Operating income	(98)	92	3	243
Interest expense	0	0	0	0
Income before income taxes	(98)	92	3	243
Total assets (at period end)	0	0	0	0
Goodwill (at period end)	0	0	0	0
Capital expenditures	$ 0	$ 0	$ 0	$ 0
Customer Concentration Risk | Revenue
Segment Reporting Information
Number of customers exceeding threshold	0

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Inventories - Narrative (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014 ft3	Sep. 30, 2013 ft3	Mar. 31, 2013 ft3
Public Utilities, Inventory
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)	1,300,000,000	11,000,000,000	1,000,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates	$ 5,421	$ 44,366	$ 3,315
Security Deposit Liability	17,600
SCAAs
Public Utilities, Inventory
Number of storage agreements (in storage agreements)	4
Number of Storage Agreements with Energy Services	3
SCAAs | Other current liabilities
Public Utilities, Inventory
Security Deposit Liability		$ 16,500	$ 16,500

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Nature of Operations

6 Months Ended

Mar. 31, 2014

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 its small Maryland service territory, 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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Inventories - Schedule of Inventories (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Mar. 31, 2013	Dec. 31, 2012
Public Utilities, Inventory
Total inventories	$ 20,629	$ 20,629	$ 89,661	$ 16,215	$ 16,215
Gas Utility Natural Gas
Public Utilities, Inventory
Total inventories		7,490	78,950		5,366
Materials, Supplies and Other
Public Utilities, Inventory
Total inventories		$ 13,139	$ 10,711		$ 10,849

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Fair Value Measurements - Financial Assets and Financial Liabilities That are Measured at Fair Value on a Recurring Basis (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013	Dec. 31, 2013 Commodity contracts Fair Value, Measurements, Recurring	Sep. 30, 2013 Commodity contracts Fair Value, Measurements, Recurring	Dec. 31, 2012 Commodity contracts Fair Value, Measurements, Recurring	Dec. 31, 2013 Commodity contracts Fair Value, Measurements, Recurring Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)	Sep. 30, 2013 Commodity contracts Fair Value, Measurements, Recurring Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)	Dec. 31, 2012 Commodity contracts Fair Value, Measurements, Recurring Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)	Dec. 31, 2013 Commodity contracts Fair Value, Measurements, Recurring Significant Other Observable Inputs (Level 2)	Sep. 30, 2013 Commodity contracts Fair Value, Measurements, Recurring Significant Other Observable Inputs (Level 2)	Dec. 31, 2012 Commodity contracts Fair Value, Measurements, Recurring Significant Other Observable Inputs (Level 2)	Dec. 31, 2013 Commodity contracts Fair Value, Measurements, Recurring Fair Value Inputs (Level 3)	Sep. 30, 2013 Commodity contracts Fair Value, Measurements, Recurring Fair Value Inputs (Level 3)	Dec. 31, 2012 Commodity contracts Fair Value, Measurements, Recurring Fair Value Inputs (Level 3)	Dec. 31, 2012 Interest rate contracts Fair Value, Measurements, Recurring	Dec. 31, 2012 Interest rate contracts Fair Value, Measurements, Recurring Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)	Dec. 31, 2012 Interest rate contracts Fair Value, Measurements, Recurring Significant Other Observable Inputs (Level 2)	Dec. 31, 2012 Interest rate contracts Fair Value, Measurements, Recurring Fair Value Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	$ 3,221	$ 43	$ 8,528	$ 3,221	$ 43	$ 4,299	$ 2,491	$ 43	$ 4,299	$ 730	$ 0	$ 0	$ 0	$ 0	$ 0	$ 4,229	$ 0	$ 4,229	$ 0
Derivative financial instruments, liabilities	$ (372)	$ (6,677)	$ (29,765)	$ (372)	$ (6,677)	$ (5,467)	$ (9)	$ (2,162)	$ (406)	$ (363)	$ (4,515)	$ (5,061)	$ 0	$ 0	$ 0	$ (24,298)	$ 0	$ (24,298)	$ 0

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Condensed Consolidated Balance Sheets (unaudited) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013
Current assets:
Cash and cash equivalents	$ 14,238	$ 4,707	$ 58,329
Restricted cash	0	3,181	0
Accounts receivable (less allowances for doubtful accounts of $12,098, $5,519 and $8,052, respectively)	181,823	53,341	141,053
Accounts receivable — related parties	8,633	3,497	9,518
Accrued utility revenues	49,710	18,868	48,857
Inventories	20,629	89,661	16,215
Deferred income taxes	12,877	14,165	32,815
Regulatory assets	4,242	8,217	1,072
Derivative financial instruments	3,221	43	8,528
Prepaid expenses & other current assets	13,705	15,862	16,755
Total current assets	309,078	211,542	333,142
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $877,460, $853,675 and $837,110, respectively)	1,611,934	1,574,135	1,508,985
Goodwill	182,145	182,145	182,145
Regulatory assets	231,689	236,694	321,257
Other assets	5,771	5,806	2,808
Total assets	2,340,617	2,210,322	2,348,337
Current liabilities:
Current maturities of long-term debt	0	0	133,000
Bank loans	6,500	17,500	0
Accounts payable	69,468	51,970	48,099
Accounts payable — related parties	20,715	12,487	12,535
Deferred fuel refunds	3,204	8,283	31,209
Derivative financial instruments	372	6,677	29,077
Other current liabilities	149,983	110,596	149,801
Total current liabilities	250,242	207,513	403,721
Long-term debt	642,000	642,000	467,000
Deferred income taxes	448,678	436,810	413,168
Deferred investment tax credits	4,100	4,270	4,440
Pension and postretirement benefit obligations	65,972	72,505	174,905
Other noncurrent liabilities	52,669	55,610	53,965
Total liabilities	1,463,661	1,418,708	1,517,199
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	470,761	470,098	469,501
Retained earnings	353,680	269,977	324,450
Accumulated other comprehensive loss	(7,744)	(8,720)	(23,072)
Total common stockholder’s equity	876,956	791,614	831,138
Total liabilities and stockholder’s equity	$ 2,340,617	$ 2,210,322	$ 2,348,337

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Disclosures About Derivative Instruments and Hedging Activities - Phantom (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Restricted Cash and Cash Equivalents, Noncurrent	$ 0

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Condensed Consolidated Statements of Comprehensive Income (unaudited) Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Statement of Comprehensive Income [Abstract]
Tax on (loss) gain on derivative instruments	$ 0	$ (2,538)	$ 0	$ (4,337)
Tax on reclassifications of net losses (gains) on derivative instruments	(278)	(84)	(556)	(168)
Tax on benefit plans	$ (67)	$ (139)	$ (137)	$ (278)

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Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Defined Benefit Plan Disclosure
Number of Defined Benefit Plans	1
Pension Benefits
Defined Benefit Plan Disclosure
Expected contribution to pensions plans in the remainder of current fiscal year	$ 10,912
Contribution made to Pension Plan	$ 6,972	$ 6,393

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Segment Information (Tables)

6 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Segment Information

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 March 31, 2014:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	513,956	$	480,163	$	33,552	$	241
Cost of sales	$	300,424	$	278,748	$	21,676	$	—
Depreciation and amortization	$	14,643	$	13,575	$	1,068	$	—
Operating income	$	137,954	$	134,560	$	3,492	$	(98	)
Interest expense	$	8,806	$	8,362	$	444	$	—
Income before income taxes	$	129,148	$	126,198	$	3,048	$	(98	)
Total assets (at period end)	$	2,340,617	$	2,195,437	$	145,180	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	31,648	$	30,039	$	1,609	$	—

Three Months Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	395,901	$	368,635	$	26,951	$	315
Cost of sales	$	212,785	$	196,742	$	16,043	$	—
Depreciation and amortization	$	13,712	$	12,731	$	981	$	—
Operating income	$	109,230	$	105,749	$	3,389	$	92
Interest expense	$	9,820	$	9,327	$	493	$	—
Income before income taxes	$	99,410	$	96,422	$	2,896	$	92
Total assets (at period end)	$	2,348,337	$	2,184,816	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	25,791	$	24,430	$	1,361	$	—

Six Months Ended March 31, 2014:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	812,855	$	751,725	$	60,513	$	617
Cost of sales	$	452,289	$	414,235	$	38,054	$	—
Depreciation and amortization	$	29,093	$	26,959	$	2,134	$	—
Operating income	$	223,797	$	216,613	$	7,181	$	3
Interest expense	$	17,603	$	16,748	$	855	$	—
Income before income taxes	$	206,194	$	199,865	$	6,326	$	3
Total assets (at period end)	$	2,340,617	$	2,195,437	$	145,180	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	65,902	$	62,851	$	3,051	$	—

Six Months Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	669,698	$	616,889	$	52,069	$	740
Cost of sales	$	351,062	$	320,316	$	30,746	$	—
Depreciation and amortization	$	27,283	$	25,336	$	1,947	$	—
Operating income	$	181,794	$	175,538	$	6,013	$	243
Interest expense	$	19,897	$	18,899	$	998	$	—
Income before income taxes	$	161,897	$	156,639	$	5,015	$	243
Total assets (at period end)	$	2,348,337	$	2,184,816	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	55,519	$	52,949	$	2,570	$	—

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Defined Benefit Pension and Other Postretirement Plans - Schedule of Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 1,623	$ 2,053	$ 3,246	$ 4,105
Interest cost	5,721	5,196	11,442	10,391
Expected return on assets	(6,650)	(6,198)	(13,299)	(12,396)
Amortization of:
Prior service cost (benefit)	87	62	174	124
Actuarial loss	1,661	3,366	3,321	6,732
Net benefit cost (income)	2,442	4,479	4,884	8,956
Change in associated regulatory liabilities	0	0	0	0
Net expense	2,442	4,479	4,884	8,956
Other Postretirement Benefit Plan, Defined Benefit
Defined Benefit Plan Disclosure
Service cost	41	51	82	102
Interest cost	127	143	254	286
Expected return on assets	(139)	(132)	(278)	(264)
Amortization of:
Prior service cost (benefit)	(160)	(105)	(320)	(210)
Actuarial loss	37	91	74	182
Net benefit cost (income)	(94)	48	(188)	96
Change in associated regulatory liabilities	918	815	1,836	1,630
Net expense	$ 824	$ 863	$ 1,648	$ 1,726

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Regulatory Assets and Liabilities and Regulatory Matters (Tables)

6 Months Ended

Mar. 31, 2014

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of 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:

	March 31, 2014		September 30, 2013		March 31, 2013
Regulatory assets:
Income taxes recoverable	$	106,800	$	106,069	$	104,229
Underfunded pension and postretirement plans	90,996		94,515		181,305
Environmental costs	14,544		17,054		16,841
Deferred fuel and power costs	4,308		8,283		2,122
Removal costs, net	14,379		13,333		11,856
Other	4,904		5,657		5,976
Total regulatory assets	$	235,931	$	244,911	$	322,329
Regulatory liabilities:
Postretirement benefits	$	17,196	$	16,497	$	13,865
Environmental overcollections	1,855		2,552		2,980
Deferred fuel and power refunds	3,204		8,283		31,209
State tax benefits — distribution system repairs	8,998		8,453		7,900
Other	1,895		1,502		700
Total regulatory liabilities	$	33,148	$	37,287	$	56,654

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Condensed Consolidated Statements of Cash Flows (unaudited) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 121,396	$ 95,071
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	29,093	27,283
Deferred income taxes, net	12,109	4,241
Provision for uncollectible accounts	8,716	6,059
Other, net	414	7,537
Net change in:
Accounts receivable and accrued utility revenues	(173,176)	(136,644)
Inventories	69,032	51,119
Deferred fuel and power costs, net of changes in unsettled derivatives	(10,181)	33,311
Accounts payable	25,726	3,688
Other current assets	1,746	12,632
Other current liabilities	38,355	18,120
Net cash provided by operating activities	123,230	122,417
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment	(65,902)	(55,519)
Net costs of property, plant and equipment disposals	(2,948)	(1,437)
Decrease in restricted cash	3,181	0
Net cash used by investing activities	(65,669)	(56,956)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends	(37,693)	0
Issuances of long-term debt	175,000	0
Repayments of long-term debt	(175,000)	0
Decrease in bank loans	(11,000)	(9,200)
Other	663	809
Net cash used by financing activities	(48,030)	(8,391)
Cash and cash equivalents increase	9,531	57,070
CASH AND CASH EQUIVALENTS:
End of period	14,238	58,329
Beginning of period	4,707	1,259
Increase	$ 9,531	$ 57,070

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Condensed Consolidated Balance Sheets (unaudited) Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013
Statement of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 12,098	$ 5,519	$ 8,052
Accumulated depreciation and amortization on property, plant and equipment	$ 877,460	$ 853,675	$ 837,110
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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Fair Value Measurements

6 Months Ended

Mar. 31, 2014

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 March 31, 2014, September 30, 2013 and March 31, 2013:

	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
March 31, 2014:
Assets:
Derivative financial instruments:
Commodity contracts	$	2,491		$	730		$	—	$	3,221
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(9	)	$	(363	)	$	—	$	(372	)
September 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	43		$	—		$	—	$	43
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(2,162	)	$	(4,515	)	$	—	$	(6,677	)
March 31, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	4,299		$	—		$	—	$	4,299
Interest rate contracts	$	—		$	4,229		$	—	$	4,229
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(406	)	$	(5,061	)	$	—	$	(5,467	)
Interest rate contracts	$	—		$	(24,298	)	$	—	$	(24,298	)

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 March 31, 2014, were $642,000 and $704,811, respectively. The carrying amount and estimated fair value of our long-term debt at March 31, 2013, were $600,000 and $690,459, 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).

Disclosures About Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on our Condensed Consolidated Balance Sheets if the right of offset exists. Our derivative financial instruments include both over-the-counter transactions and those that are executed on an exchange and centrally cleared. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts may be subject to conditional rights of offset through counterparty nonperformance, insolvency, or other conditions.

In general, most of our over-the-counter transactions and most exchange contracts are subject to collateral requirements. Types of collateral generally includes cash or letters of credit. Any cash collateral paid by us to our derivative counterparties is reflected in the table below to offset derivative liabilities. Any cash collateral received by us from our derivative counterparties is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on our Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the tables below but could reduce our net exposure to such counterparties because they are subject to master netting or similar arrangements.

	Gross Amount Recognized			Gross Amount Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet
March 31, 2014:
Derivative assets	$	3,526		$	(305	)	$	3,221
Derivative (liabilities)	$	(677	)	$	305		$	(372	)
September 30, 2013:
Derivative assets	$	92		$	(49	)	$	43
Derivative (liabilities)	$	(6,726	)	$	49		$	(6,677	)
March 31, 2013:
Derivative assets	$	12,241		$	(3,713	)	$	8,528
Derivative (liabilities)	$	(33,478	)	$	3,713		$	(29,765	)

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Document and Entity Information	6 Months Ended
	Mar. 31, 2014	Apr. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	UGI UTILITIES INC
Entity Central Index Key	0000100548
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Amendment Flag	false
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q2
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

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Disclosures About Derivative Instruments and Hedging Activities

6 Months Ended

Mar. 31, 2014

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 March 31, 2014 and 2013, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.0 million dekatherms and 10.0 million dekatherms, respectively. At March 31, 2014, the maximum period over which Gas Utility is hedging natural gas market price risk is 11 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 March 31, 2014 and 2013, the fair values of Electric Utility’s forward purchase power agreements comprising net gains of $358 and net losses of $5,458, respectively, are reflected in current derivative financial instrument assets and 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 and liabilities. At March 31, 2014 and 2013, the volumes of Electric Utility’s forward electricity purchase contracts were 207.0 million kilowatt hours and 403.2 million kilowatt hours, respectively. At March 31, 2014, the maximum period over which these contracts extend is 8 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 March 31, 2014 and 2013, the volumes associated with Electric Utility FTRs totaled 47.4 million kilowatt hours and 47.5 million kilowatt hours, respectively.

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 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 March 31, 2014 we had no unsettled IRPAs. As of March 31, 2013, the total notional amounts of unsettled IRPAs was $173,000.

At March 31, 2014, the amount of net losses associated with settled IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $2,680.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2014 and 2013, there was no restricted cash in brokerage accounts.

The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of March 31, 2014 and 2013:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2014		2013		Location	2014			2013
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	—	$	4,229	Derivative financial instruments	$	—		$	(24,298	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	3,153		4,130		Derivative financial instruments and Other noncurrent liabilities	(372		)	(5,467		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	68		169		Derivative financial instruments	—			—
Total Derivatives		$	3,221	$	8,528		$	(372	)	$	(29,765	)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for the three and six months ended March 31, 2014 and 2013:

Three Months Ended March 31, :
	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2014			2013		2014			2013			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—		$	6,116	$	(670	)	$	(202	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income											Location of Gain (Loss) Recognized in Income
	2014			2013
Commodity contracts	$	(18	)	$	107							Operating expenses/other income, net
Six Months Ended March 31, :
	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2014			2013		2014			2013			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—		$	10,452	$	1,339		$	(405	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income											Location of Gain (Loss) Recognized in Income
	2014			2013
Commodity contracts	$	79		$	105							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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Condensed Consolidated Statements of Income (unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Income Statement [Abstract]
Revenues	$ 513,956	$ 395,901	$ 812,855	$ 669,698
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	300,424	212,785	452,289	351,062
Operating and administrative expenses	54,306	52,421	95,451	96,656
Operating and administrative expenses — related parties	3,769	3,012	5,612	4,817
Taxes other than income taxes	4,801	4,684	8,980	8,960
Depreciation	13,815	12,895	27,437	25,648
Amortization	828	817	1,656	1,635
Other (income) loss, net	(1,941)	57	(2,367)	(874)
Total costs and expenses	376,002	286,671	589,058	487,904
Operating income	137,954	109,230	223,797	181,794
Interest expense	8,806	9,820	17,603	19,897
Income before income taxes	129,148	99,410	206,194	161,897
Income taxes	53,038	41,151	84,798	66,826
Net income	$ 76,110	$ 58,259	$ 121,396	$ 95,071

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Inventories

6 Months Ended

Mar. 31, 2014

Inventory Disclosure [Abstract]

Inventories

Inventories

Inventories comprise the following:

	March 31, 2014		September 30, 2013		March 31, 2013
Gas Utility natural gas	$	7,490	$	78,950	$	5,366
Materials, supplies and other	13,139		10,711		10,849
Total inventories	$	20,629	$	89,661	$	16,215

At March 31, 2014, UGI Utilities is a party to four storage contract administrative agreements (“SCAAs”) having terms of one to three years. Three of the SCAAs are with Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (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 March 31, 2014, September 30, 2013 and March 31, 2013, comprising 1.3 billion cubic feet (“bcf”), 11.0 bcf and 1.0 bcf of natural gas, was $5,421, $44,366 and $3,315, respectively. In conjunction with these SCAAs, UGI Utilities held total security deposits received from its SCAA counterparties of $17,600 at March 31, 2014, and $16,500 at September 30, 2013 and March 31, 2013. These amounts are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets.

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Segment Information

6 Months Ended

Mar. 31, 2014

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 2013 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 March 31, 2014:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	513,956	$	480,163	$	33,552	$	241
Cost of sales	$	300,424	$	278,748	$	21,676	$	—
Depreciation and amortization	$	14,643	$	13,575	$	1,068	$	—
Operating income	$	137,954	$	134,560	$	3,492	$	(98	)
Interest expense	$	8,806	$	8,362	$	444	$	—
Income before income taxes	$	129,148	$	126,198	$	3,048	$	(98	)
Total assets (at period end)	$	2,340,617	$	2,195,437	$	145,180	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	31,648	$	30,039	$	1,609	$	—

Three Months Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	395,901	$	368,635	$	26,951	$	315
Cost of sales	$	212,785	$	196,742	$	16,043	$	—
Depreciation and amortization	$	13,712	$	12,731	$	981	$	—
Operating income	$	109,230	$	105,749	$	3,389	$	92
Interest expense	$	9,820	$	9,327	$	493	$	—
Income before income taxes	$	99,410	$	96,422	$	2,896	$	92
Total assets (at period end)	$	2,348,337	$	2,184,816	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	25,791	$	24,430	$	1,361	$	—

Six Months Ended March 31, 2014:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	812,855	$	751,725	$	60,513	$	617
Cost of sales	$	452,289	$	414,235	$	38,054	$	—
Depreciation and amortization	$	29,093	$	26,959	$	2,134	$	—
Operating income	$	223,797	$	216,613	$	7,181	$	3
Interest expense	$	17,603	$	16,748	$	855	$	—
Income before income taxes	$	206,194	$	199,865	$	6,326	$	3
Total assets (at period end)	$	2,340,617	$	2,195,437	$	145,180	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	65,902	$	62,851	$	3,051	$	—

Six Months Ended March 31, 2013:

			Reportable Segments
	Total		Gas Utility		Electric Utility		Other
Revenues	$	669,698	$	616,889	$	52,069	$	740
Cost of sales	$	351,062	$	320,316	$	30,746	$	—
Depreciation and amortization	$	27,283	$	25,336	$	1,947	$	—
Operating income	$	181,794	$	175,538	$	6,013	$	243
Interest expense	$	19,897	$	18,899	$	998	$	—
Income before income taxes	$	161,897	$	156,639	$	5,015	$	243
Total assets (at period end)	$	2,348,337	$	2,184,816	$	163,521	$	—
Goodwill (at period end)	$	182,145	$	182,145	$	—	$	—
Capital expenditures	$	55,519	$	52,949	$	2,570	$	—

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Inventories (Tables)

6 Months Ended

Mar. 31, 2014

Inventory Disclosure [Abstract]

Schedule of Inventories

Inventories comprise the following:

	March 31, 2014		September 30, 2013		March 31, 2013
Gas Utility natural gas	$	7,490	$	78,950	$	5,366
Materials, supplies and other	13,139		10,711		10,849
Total inventories	$	20,629	$	89,661	$	16,215

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Debt

6 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Debt Disclosure

Debt

On March 26, 2014, UGI Utilities issued in a private placement $175,000 of 4.98% Senior Notes due March 26, 2044 (“4.98% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175,000 of borrowings under UGI Utilities’ 364-day term loan credit agreement scheduled to expire in September 2014. The 4.98% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The 4.98% Senior Notes also contain restrictive and financial covenants including a Consolidated Debt to Consolidated Total Capital, as defined therein, of 0.65 to 1.00.

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Commitments and Contingencies

6 Months Ended

Mar. 31, 2014

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 was recently renewed and is scheduled to terminate at the end of 2018. 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 March 31, 2014 and 2013, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11,097 and $14,338, 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 March 31, 2014, 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 UGI Utilities 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.

There are pending claims and legal actions arising in the normal course of our businesses. While the results of these pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, that the final outcome of such 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

6 Months Ended

Mar. 31, 2014

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 2013 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:

	March 31, 2014		September 30, 2013		March 31, 2013
Regulatory assets:
Income taxes recoverable	$	106,800	$	106,069	$	104,229
Underfunded pension and postretirement plans	90,996		94,515		181,305
Environmental costs	14,544		17,054		16,841
Deferred fuel and power costs	4,308		8,283		2,122
Removal costs, net	14,379		13,333		11,856
Other	4,904		5,657		5,976
Total regulatory assets	$	235,931	$	244,911	$	322,329
Regulatory liabilities:
Postretirement benefits	$	17,196	$	16,497	$	13,865
Environmental overcollections	1,855		2,552		2,980
Deferred fuel and power refunds	3,204		8,283		31,209
State tax benefits — distribution system repairs	8,998		8,453		7,900
Other	1,895		1,502		700
Total regulatory liabilities	$	33,148	$	37,287	$	56,654

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 March 31, 2014, September 30, 2013, and March 31, 2013, were $2,389, $(1,743) and $4,129, 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 March 31, 2014, September 30, 2013, and March 31, 2013, the fair values of Electric Utility’s electricity supply contracts were net gains (losses) of $358, $(4,759) and $(5,458), respectively, which amounts are reflected in current derivative financial instrument assets and liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs or refunds 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 March 31, 2014, September 30, 2013, and March 31, 2013, were not material.

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Defined Benefit Pension and Other Postretirement Plans

6 Months Ended

Mar. 31, 2014

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
	March 31,						March 31,
	2014			2013			2014			2013
Service cost	$	1,623		$	2,053		$	41		$	51
Interest cost	5,721			5,196			127			143
Expected return on assets	(6,650		)	(6,198		)	(139		)	(132		)
Amortization of:
Prior service benefit	87			62			(160		)	(105		)
Actuarial loss	1,661			3,366			37			91
Net benefit cost (income)	2,442			4,479			(94		)	48
Change in associated regulatory liabilities	—			—			918			815
Net expense	$	2,442		$	4,479		$	824		$	863
	Pension Benefits						Other Postretirement Benefits
	Six Months Ended						Six Months Ended
	March 31,						March 31,
	2014			2013			2014			2013
Service cost	$	3,246		$	4,105		$	82		$	102
Interest cost	11,442			10,391			254			286
Expected return on assets	(13,299		)	(12,396		)	(278		)	(264		)
Amortization of:
Prior service cost (benefit)	174			124			(320		)	(210		)
Actuarial loss	3,321			6,732			74			182
Net benefit cost	4,884			8,956			(188		)	96
Change in associated regulatory liabilities	—			—			1,836			1,630
Net expense	$	4,884		$	8,956		$	1,648		$	1,726

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 $10,912 to the Pension Plan during the remainder of Fiscal 2014. During the six months endedMarch 31, 2014 and 2013, the Company made contributions to the Pension Plan of $6,972 and $6,393, 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.

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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Related Party Transactions

6 Months Ended

Mar. 31, 2014

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.

UGI Utilities is a party to several SCAAs with Energy Services which have terms of one to three years. 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 $248 and $6,695 during the three and six months ended March 31, 2014, respectively, and $702 and $5,026 during the three and six months ended March 31, 2013, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets, were $10,600 as of March 31, 2014, and $16,500 as of September 30, 2013 and March 31, 2013.

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 March 31, 2014, comprising approximately 1.1 bcf of natural gas, was $4,653. The carrying value of these gas storage inventories at September 30, 2013, comprising approximately 10.4 bcf of natural gas, was $41,988. The carrying value of these gas storage inventories at March 31, 2013, comprising approximately 1.0 bcf of natural gas, was $3,315.

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 three and six months ended March 31, 2014 , totaled $13,330 and $32,708, respectively. During the three and six months ended March 31, 2013, such transactions totaled $14,701 and $32,526, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and six months ended March 31, 2014, revenues associated with such sales to Energy Services totaled $75,133 and $92,249, respectively. During the three and six months ended March 31, 2013, revenues associated with such sales to Energy Services totaled $25,428 and $45,252, 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 six months ended March 31, 2014, the aggregate amount of such purchases totaled $70,619 and $92,697, respectively. During the three and six months ended March 31, 2013, the aggregate amount of such purchases totaled $18,213 and $37,233, 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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Regulatory Assets and Liabilities and Regulatory Matters - Schedule of Regulatory Assets and Liabilities Associated With Gas Utility and Electric Utility (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013
Regulatory Assets and Liabilities
Regulatory Assets	$ 235,931	$ 244,911	$ 322,329
Regulatory Liabilities	33,148	37,287	56,654
Postretirement benefits
Regulatory Assets and Liabilities
Regulatory Liabilities	17,196	16,497	13,865
Environmental overcollections
Regulatory Assets and Liabilities
Regulatory Liabilities	1,855	2,552	2,980
Deferred fuel and power refunds
Regulatory Assets and Liabilities
Regulatory Liabilities	3,204	8,283	31,209
State tax benefits -- distribution system repairs
Regulatory Assets and Liabilities
Regulatory Liabilities	8,998	8,453	7,900
Other
Regulatory Assets and Liabilities
Regulatory Liabilities	1,895	1,502	700
Income taxes recoverable
Regulatory Assets and Liabilities
Regulatory Assets	106,800	106,069	104,229
Underfunded pension and postretirement plans
Regulatory Assets and Liabilities
Regulatory Assets	90,996	94,515	181,305
Environmental costs
Regulatory Assets and Liabilities
Regulatory Assets	14,544	17,054	16,841
Deferred fuel and power costs
Regulatory Assets and Liabilities
Regulatory Assets	4,308	8,283	2,122
Removal costs, net
Regulatory Assets and Liabilities
Regulatory Assets	14,379	13,333	11,856
Other
Regulatory Assets and Liabilities
Regulatory Assets	$ 4,904	$ 5,657	$ 5,976

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Significant Accounting Policies (Tables)

6 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Schedule of Changes in AOCI

Changes in accumulated other comprehensive loss during the three and six months ended March 31, 2014 are as follows:

	Postretirement			Derivative
Three Months Ended March 31, 2014:	Benefit Plans			Instruments			Total
Balance, December 31, 2013	$	(5,185	)	$	(3,046	)	$	(8,231	)
Reclassification of benefit plan actuarial losses and prior service cost	95			—			95
Reclassifications of net losses on interest rate protection agreements	—			392			392
Balance, March 31, 2014	$	(5,090	)	$	(2,654	)	$	(7,744	)
Six Months Ended March 31, 2014:
Balance, September 30, 2013	$	(5,283	)	$	(3,437	)	$	(8,720	)
Reclassification of benefit plan actuarial losses and prior service cost	193			—			193
Reclassifications of net losses on interest rate protection agreements	—			783			783
Balance, March 31, 2014	$	(5,090	)	$	(2,654	)	$	(7,744	)

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Fair Value Measurements (Tables)

6 Months Ended

Mar. 31, 2014

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 March 31, 2014, September 30, 2013 and March 31, 2013:

	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
March 31, 2014:
Assets:
Derivative financial instruments:
Commodity contracts	$	2,491		$	730		$	—	$	3,221
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(9	)	$	(363	)	$	—	$	(372	)
September 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	43		$	—		$	—	$	43
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(2,162	)	$	(4,515	)	$	—	$	(6,677	)
March 31, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	4,299		$	—		$	—	$	4,299
Interest rate contracts	$	—		$	4,229		$	—	$	4,229
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(406	)	$	(5,061	)	$	—	$	(5,467	)
Interest rate contracts	$	—		$	(24,298	)	$	—	$	(24,298	)

Schedule of fair value, by balance sheet grouping

Any cash collateral paid by us to our derivative counterparties is reflected in the table below to offset derivative liabilities. Any cash collateral received by us from our derivative counterparties is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on our Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the tables below but could reduce our net exposure to such counterparties because they are subject to master netting or similar arrangements.

	Gross Amount Recognized			Gross Amount Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet
March 31, 2014:
Derivative assets	$	3,526		$	(305	)	$	3,221
Derivative (liabilities)	$	(677	)	$	305		$	(372	)
September 30, 2013:
Derivative assets	$	92		$	(49	)	$	43
Derivative (liabilities)	$	(6,726	)	$	49		$	(6,677	)
March 31, 2013:
Derivative assets	$	12,241		$	(3,713	)	$	8,528
Derivative (liabilities)	$	(33,478	)	$	3,713		$	(29,765	)

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Fair Value Measurements - Schedule of Fair Value by Balance Sheet Grouping (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013
Offsetting Derivatives Table
Derivative Asset, Fair Value, Gross Asset	$ 3,526	$ 92	$ 12,241
Derivative Asset Offset Amount	(305)	(49)	(3,713)
Derivative Assets, Fair Value, Net Amount	3,221	43	8,528
Derivative Liabilities, Fair Value, Gross	(677)	(6,726)	(33,478)
Derivative Liability Offset Amount	305	49	3,713
Derivative Liabilities, Net Amount	$ (372)	$ (6,677)	$ (29,765)

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Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income	$ 76,110	$ 58,259	$ 121,396	$ 95,071
Other comprehensive income:
Net gains in fair value of derivative instruments (net of tax of $0, $(2,538), $0 and $(4,337), respectively)	0	3,578	0	6,115
Reclassifications of net losses on derivative instruments (net of tax of $(278), $(84), $(556) and $(168), respectively)	392	118	783	237
Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(67), $(139), $(137) and $(278), respectively)	95	198	193	393
Other comprehensive income	487	3,894	976	6,745
Comprehensive income	$ 76,597	$ 62,153	$ 122,372	$ 101,816

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Accounting Changes

6 Months Ended

Mar. 31, 2014

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Changes

Accounting Changes

Adoption of New Accounting Standards

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. Effective October 1, 2013, the Company adopted new accounting guidance regarding disclosures for items reclassified out of accumulated other comprehensive income (“AOCI”). The disclosures required by the new accounting guidance are included in the Note 2 to the condensed consolidated financial statements. The new disclosures are applied prospectively. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities. In Fiscal 2014 the Company adopted new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet as a result of an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new disclosures are applied retroactively for all periods presented. The disclosures required are included in Note 10 to the condensed consolidated financial statements. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.

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Disclosures About Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Mar. 31, 2014

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 March 31, 2014 and 2013:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2014		2013		Location	2014			2013
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	—	$	4,229	Derivative financial instruments	$	—		$	(24,298	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	3,153		4,130		Derivative financial instruments and Other noncurrent liabilities	(372		)	(5,467		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	68		169		Derivative financial instruments	—			—
Total Derivatives		$	3,221	$	8,528		$	(372	)	$	(29,765	)

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 the three and six months ended March 31, 2014 and 2013:

Three Months Ended March 31, :
	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2014			2013		2014			2013			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—		$	6,116	$	(670	)	$	(202	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income											Location of Gain (Loss) Recognized in Income
	2014			2013
Commodity contracts	$	(18	)	$	107							Operating expenses/other income, net
Six Months Ended March 31, :
	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2014			2013		2014			2013			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—		$	10,452	$	1,339		$	(405	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income											Location of Gain (Loss) Recognized in Income
	2014			2013
Commodity contracts	$	79		$	105							Operating expenses/other income, net

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Related Party Transactions - Narrative (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended					3 Months Ended		6 Months Ended					3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Energy Services	Mar. 31, 2013 Energy Services	Mar. 31, 2014 Energy Services	Mar. 31, 2013 Energy Services	Mar. 31, 2014 Inventories Energy Services ft3	Sep. 30, 2013 Inventories Energy Services ft3	Mar. 31, 2013 Inventories Energy Services ft3	Mar. 31, 2014 SCAAs Energy Services	Mar. 31, 2013 SCAAs Energy Services	Mar. 31, 2014 SCAAs Energy Services	Mar. 31, 2013 SCAAs Energy Services	Mar. 31, 2014 SCAAs Other current liabilities Energy Services	Sep. 30, 2013 SCAAs Other current liabilities Energy Services	Mar. 31, 2013 SCAAs Other current liabilities Energy Services	Mar. 31, 2014 Exclusive of transactions pursuant SCAAs Energy Services	Mar. 31, 2013 Exclusive of transactions pursuant SCAAs Energy Services	Mar. 31, 2014 Exclusive of transactions pursuant SCAAs Energy Services	Mar. 31, 2013 Exclusive of transactions pursuant SCAAs Energy Services
Related Party Transaction
Related party costs incurred	$ 3,769	$ 3,012	$ 5,612	$ 4,817								$ 248	$ 702	$ 6,695	$ 5,026				$ 13,330	$ 14,701	$ 32,708	$ 32,526
Related party security deposits																10,600	16,500	16,500
Volume of gas storage inventory (in bcf of natural gas)									1,100,000,000	10,400,000,000	1,000,000,000
Natural gas storage inventory, related parties, current									4,653	41,988	3,315
Revenue from related parties					75,133	25,428	92,249	45,252
Purchases from related party					$ 70,619	$ 18,213	$ 92,697	$ 37,233

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Significant Accounting Policies (Policies)

6 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Comprehensive Income

Comprehensive Income. Comprehensive income comprises net income and other comprehensive income. Other comprehensive income 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.