10-K 1 ugi-9302015x10k.htm 10-K
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K
ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2015
Commission file number 1-11071
UGI CORPORATION
(Exact name of registrant as specified in its charter)

Pennsylvania |  | 23-2668356
(State or Other Jurisdiction of Incorporation or Organization) |  | (I.R.S. Employer Identification No.)

460 North Gulph Road, King of Prussia, PA 19406
(Address of Principal Executive Offices) (Zip Code)
(610) 337-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class |  | Name of each Exchange on Which Registered
Common Stock, without par value |  | New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
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.

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
The aggregate market value of UGI Corporation Common Stock held by non-affiliates of the registrant on March 31, 2015 was $5,620,244,117.
At November 17, 2015, there were 172,443,403 shares of UGI Corporation Common Stock issued and outstanding.
Portions of the Proxy Statement for the Annual Meeting of Shareholders to be held on January 28, 2016 are incorporated by reference into Part III of this Form 10-K.

Table of Contents
TABLE OF CONTENTS

| Page
Forward-Looking Information | 2
PART I: |
Items 1. and 2. Business and Properties | 2
Item 1A. Risk Factors | 21
Item 1B. Unresolved Staff Comments | 27
Item 3. Legal Proceedings | 27
Item 4. Mine Safety Disclosures | 27
PART II: |
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 28
Item 6. Selected Financial Data | 30
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 32
Item 7A. Quantitative and Qualitative Disclosures About Market Risk | 59
Item 8. Financial Statements and Supplementary Data | 59
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 59
Item 9A. Controls and Procedures | 59
Item 9B. Other Information | 59
PART III: |
Item 10. Directors, Executive Officers and Corporate Governance | 60
Item 11. Executive Compensation | 60
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 60
Item 13. Certain Relationships and Related Transactions and Director Independence | 60
Item 14. Principal Accounting Fees and Services | 60
PART IV: |
Item 15. Exhibits and Financial Statement Schedules | 63
Signatures | 77
Index to Financial Statements and Financial Statement Schedules | F-2

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FORWARD-LOOKING INFORMATION
Information contained in this Annual Report on Form 10-K 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 (the “Exchange Act”). 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 which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other liquefied petroleum gases, oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax, consumer protection 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) failure to acquire new customers and retain current customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) large customer, counterparty or supplier defaults; (12) liability in excess of insurance coverage 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 and liquefied petroleum gases (“LPG”); (13) political, regulatory and economic conditions in the United States and in foreign countries, including the current conflicts in the Middle East, and foreign currency exchange rate fluctuations, particularly the euro; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (15) changes in commodity market prices resulting in significantly higher cash collateral requirements; (16) reduced distributions from subsidiaries; (17) changes in Marcellus Shale gas production; (18) the timing and success of our acquisitions, commercial initiatives and investments to grow our businesses; and (19) our ability to successfully integrate acquired businesses and achieve anticipated synergies.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.
PART I:
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
CORPORATE OVERVIEW
UGI Corporation (the “Company”) is a holding company that, through subsidiaries, distributes, stores, transports and markets energy products and related services. We are a domestic and international retail distributor of propane and butane (which are both LPG); a provider of natural gas and electric service through regulated local distribution utilities; a generator of electricity; a regional marketer of energy commodities; an owner and manager of midstream assets; and a regional provider of heating, ventilation, air conditioning, refrigeration, plumbing, and electrical contracting services. Our subsidiaries and affiliates operate principally in the following six business segments:

• | AmeriGas Propane

• | UGI International - UGI France

• | UGI International - Flaga & Other

• | Energy Services

• | Electric Generation

• | Gas Utility

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The AmeriGas Propane segment consists of the propane distribution business of AmeriGas Partners, L.P. (“AmeriGas Partners” or the “Partnership”), which is the nation’s largest retail propane distributor. The Partnership’s sole general partner is our subsidiary, AmeriGas Propane, Inc. (“AmeriGas Propane” or the “General Partner”). The common units of AmeriGas Partners represent limited partner interests in a Delaware limited partnership and trade on the New York Stock Exchange under the symbol “APU.” We have an effective 26% ownership interest in the Partnership and the remaining interest is publicly held. See Note 1 to Consolidated Financial Statements.
The UGI International - UGI France segment consists of the French LPG distribution business of our wholly-owned subsidiaries, Antargaz, a French société anonyme, and Finagaz, a French société par actions simplifiée, and our LPG distribution businesses in the Benelux countries (consisting of Belgium, the Netherlands, and Luxembourg) (collectively, “UGI France”). Following the completion of the Totalgaz Acquisition (described herein), Totalgaz’s LPG distribution business is now referred to as Finagaz. UGI France is the largest LPG distributor in France and Luxembourg and one of the largest LPG distributors in the Netherlands and Belgium.
The UGI International - Flaga & Other segment consists of the LPG distribution businesses of (i) Flaga GmbH, an Austrian limited liability company, and its subsidiaries (collectively, “Flaga”), (ii) AvantiGas Limited, a United Kingdom private limited company (“AvantiGas”), and (iii) ChinaGas Partners, L.P., a majority-owned Delaware limited partnership. Flaga is the largest retail LPG distributor in Austria, Denmark, and Hungary and one of the largest in Poland, the Czech Republic, Slovakia, Norway, and Sweden. Flaga also distributes LPG in Finland, Romania, and Switzerland. AvantiGas is an LPG distributor in the United Kingdom. ChinaGas Partners is an LPG distributor in the Nantong region of China. UGI France and Flaga & Other segments are collectively referred to as “UGI International.”
The Energy Services segment consists of energy-related businesses conducted by our wholly-owned subsidiary, UGI Energy Services, LLC (“Energy Services”). These businesses include (i) energy marketing in the Mid-Atlantic region of the United States (the “U.S.”), (ii) operating and owning a natural gas liquefaction, storage and vaporization facility and propane-air mixing assets, (iii) managing natural gas pipeline and storage contracts, and (iv) developing, owning and operating pipelines, gathering infrastructure and gas storage facilities primarily in the Marcellus Shale region of Pennsylvania.
The Electric Generation segment consists of electric generation facilities conducted by Energy Services’ wholly-owned subsidiary, UGI Development Company (“UGID”). UGID has an approximate 5.97% (approximately 102 megawatt) ownership interest in a coal-fired generation station in Pennsylvania. UGID also owns and operates (i) a 130 megawatt natural gas-fueled generating station in Pennsylvania, (ii) an 11 megawatt landfill gas-fueled generation plant in Pennsylvania, and (iii) 13.5 megawatts of solar-powered generation capacity in Pennsylvania, Maryland, and New Jersey. The Energy Services and Electric Generation segments are collectively referred to as “Midstream & Marketing.”
The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of our subsidiary, UGI Utilities, Inc. (“UGI Utilities”), and UGI Utilities’ subsidiaries, UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). Gas Utility serves nearly 617,000 customers in eastern and central Pennsylvania and more than five hundred customers in portions of one Maryland county. UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” Gas Utility is regulated by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to its more than five hundred customers in Maryland, the Maryland Public Service Commission.
In addition to the segments set forth herein, UGI Corporation also owns and operates (i) a regulated electric distribution business in Pennsylvania through UGI Utilities (“Electric Utility”), and (ii) a heating, ventilation, air conditioning, refrigeration, mechanical and electrical contracting, and project management service business in portions of eastern and central Pennsylvania and portions of New Jersey and Northern Delaware.
Business Strategy
Our business strategy is to grow the Company by focusing on our core competencies of distributing, storing, transporting and marketing energy products and services. We are utilizing our core competencies from our existing businesses and our national scope, international experience, extensive asset base and access to customers to accelerate both internal growth and growth through acquisitions in our existing businesses, as well as in related and complementary businesses. During Fiscal 2015, we completed a number of transactions in pursuit of this strategy and made progress on larger internally generated capital projects, including infrastructure projects to further support the development of natural gas in the Marcellus Shale region of Pennsylvania. A few of these transactions and projects are described below.
On May 29, 2015, our indirect wholly-owned French subsidiary, UGI France SAS (a Société par actions simplifiée) (“France SAS”) (formerly UGI Bordeaux Holding), acquired all of the outstanding shares of Totalgaz, Total’s LPG distribution business
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in France (now known as Finagaz) (the “Totalgaz Acquisition”). The Totalgaz Acquisition nearly doubled our retail LPG distribution business in France and is consistent with our growth strategies, one of which is to grow our core business through acquisitions. In addition, the Company expanded its presence in Europe by acquiring Total’s LPG distribution business in Hungary in September 2015 and Tyczka Neue Gastechnik’s LPG distribution business in Austria in October 2015. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
During Fiscal 2015, UGI Utilities announced its Invenergy pipeline project to provide natural gas service to a power generation facility in Jessup, Pennsylvania. Energy Services also announced its Sunbury Pipeline project to construct an approximately 35-mile pipeline to transport natural gas to the proposed Hummel Station combined-cycle 1,000 megawatt power generation facility near the Shamokin Dam in Snyder County, Pennsylvania.
In Fiscal 2015, Energy Services (i) commenced service on the Union Dale Lateral pipeline to transport locally produced natural gas to PNG and (ii) completed its Temple LNG project that increased the liquefaction capacity of its natural gas liquefaction, storage, and vaporization facility in Temple, Pennsylvania. In addition, Energy Services made progress on its participation in the PennEast Pipeline project to develop an approximately 118-mile pipeline from Pennsylvania to New Jersey. As of September 30, 2015, Energy Services had a 20% membership interest in the PennEast Pipeline project. In addition, on October 28, 2015, Energy Services announced that it had completed its three-phase expansion of its Auburn gathering system with the construction of three additional compressor units at its Manning Compressor Station in Wyoming County, Pennsylvania. Energy Services also announced that service commenced on its 9-mile pipeline (Auburn Loop project) connecting Susquehanna County to the Manning Compressor Station on November 1, 2015.
Corporate Information
UGI Corporation was incorporated in Pennsylvania in 1991. UGI Corporation is not subject to regulation by the PUC. UGI Corporation is a “holding company” under the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). PUHCA 2005 and the implementing regulations of the Federal Energy Regulatory Commission (“FERC”) give FERC access to certain holding company books and records and impose certain accounting, record-keeping, and reporting requirements on holding companies. PUHCA 2005 also provides state utility regulatory commissions with access to holding company books and records in certain circumstances. Pursuant to a waiver granted in accordance with FERC’s regulations on the basis of UGI Corporation’s status as a single-state holding company system, UGI Corporation is not subject to certain of the accounting, record-keeping, and reporting requirements prescribed by FERC’s regulations. As further discussed herein, however, UGI Corporation, through Energy Services, will become subject to additional FERC accounting regulations and standards of conduct upon FERC approval and completion of the Sunbury Pipeline project.
Our executive offices are located at 460 North Gulph Road, King of Prussia, Pennsylvania 19406, and our telephone number is (610) 337-1000. In this report, the terms “Company” and “UGI,” as well as the terms “our,” “we,” “us,” and “its,” are sometimes used as abbreviated references to UGI Corporation or, collectively, UGI Corporation and its consolidated subsidiaries. Similarly, the terms “AmeriGas Partners” and the “Partnership” are sometimes used as abbreviated references to AmeriGas Partners, L.P. or, collectively, AmeriGas Partners, L.P. and its subsidiaries, and the term “UGI Utilities” is sometimes used as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries. The terms “Fiscal 2015” and “Fiscal 2014” refer to the fiscal years ended September 30, 2015 and September 30, 2014, respectively.
The Company’s corporate website can be found at www.ugicorp.com. Information on our website is not intended to be incorporated into this report. The Company makes available free of charge at this website (under the “Investor Relations - Financial Reports - SEC Filings and Proxy” caption) copies of its reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, including its Annual Reports on Form 10-K, its Quarterly Reports on Form 10-Q and its Current Reports on Form 8-K. The Company’s Principles of Corporate Governance, Code of Ethics for the Chief Executive Officer and Senior Financial Officers, Code of Business Conduct and Ethics for Directors, Officers and Employees, and charters of the Corporate Governance, Audit, Compensation and Management Development, and Safety, Environmental and Regulatory Compliance Committees of the Board of Directors are also available on the Company’s website, under the captions “Investor Relations - Corporate Governance - Committees.” All of these documents are also available free of charge by writing to Treasurer, UGI Corporation, P.O. Box 858, Valley Forge, PA 19482.
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AMERIGAS PROPANE
Products, Services and Marketing
Our domestic propane distribution business is conducted through AmeriGas Partners. AmeriGas Propane is responsible for managing the Partnership. The Partnership serves approximately 2 million customers in all 50 states from approximately 2,000 propane distribution locations. In addition to distributing propane, the Partnership also sells, installs and services propane appliances, including heating systems, and operates a residential heating, ventilation, air conditioning, plumbing, and related services business in certain counties of Pennsylvania, Delaware, and Maryland. Typically, the Partnership’s propane distribution locations are in suburban and rural areas where natural gas is not readily available. Our local offices generally consist of a business office and propane storage. As part of its overall transportation and distribution infrastructure, the Partnership operates as an interstate carrier in all states throughout the continental U.S.
The Partnership sells propane primarily to residential, commercial/industrial, motor fuel, agricultural and wholesale customers. The Partnership distributed over 1.2 billion gallons of propane in Fiscal 2015. Approximately 96% of the Partnership’s Fiscal 2015 sales (based on gallons sold) were to retail accounts and approximately 4% were to wholesale and supply customers. Sales to residential customers in Fiscal 2015 represented approximately 39% of retail gallons sold; commercial/industrial customers 36%; motor fuel customers 15%; and agricultural customers 6%. Transport gallons, which are large-scale deliveries to retail customers other than residential, accounted for 4% of Fiscal 2015 retail gallons. No single customer represents, or is anticipated to represent, more than 5% of the Partnership’s consolidated revenues.
The Partnership continues to expand its AmeriGas Cylinder Exchange (“ACE”) program. At September 30, 2015, ACE cylinders were available at nearly 48,500 retail locations throughout the U.S. Sales of our ACE cylinders to retailers are included in commercial/industrial sales. The ACE program enables consumers to purchase or exchange propane cylinders at various retail locations such as home centers, gas stations, mass merchandisers and grocery and convenience stores. We also supply retailers with large propane tanks to enable retailers to replenish customers’ propane cylinders directly at the retailer’s location.
Residential and commercial customers use propane primarily for home heating, water heating and cooking purposes. Commercial users include hotels, restaurants, churches, warehouses, and retail stores. Industrial customers use propane to fire furnaces, as a cutting gas and in other process applications. Other industrial customers are large-scale heating accounts and local gas utility customers who use propane as a supplemental fuel to meet peak load deliverability requirements. As a motor fuel, propane is burned in internal combustion engines that power over-the-road vehicles, forklifts, commercial lawn mowers, and stationary engines. Agricultural uses include tobacco curing, chicken brooding, crop drying, and orchard heating. In its wholesale operations, the Partnership principally sells propane to large industrial end-users and other propane distributors.
Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from the bobtail truck, which generally holds 2,400 to 3,000 gallons of propane, into a stationary storage tank on the customer’s premises. The Partnership owns most of these storage tanks and leases them to its customers. The capacity of these tanks ranges from approximately 120 gallons to approximately 1,200 gallons. The Partnership also delivers propane in portable cylinders, including ACE cylinders. Some of these deliveries are made to the customer’s location, where cylinders are either picked up or replenished in place.
Propane Supply and Storage
The United States propane market has over 250 domestic and international sources of supply, including the spot market. Supplies of propane from the Partnership’s sources historically have been readily available. The propane industry experienced record inventory levels and the lowest propane prices in the U.S. in nearly 15 years during the Fiscal 2015 winter heating season. The availability and pricing of propane supply is dependent upon, among other things, the severity of winter weather, the price and availability of competing fuels such as natural gas and crude oil, and the amount and availability of imported and exported supply. In recent years, there has been an increase in demand for propane overseas from the U.S. propane export market with total U.S. propane exports nearly doubling over the last two years. During Fiscal 2015, over 85% of the Partnership’s propane supply was purchased under supply agreements with terms of 1 to 3 years. Although no assurance can be given that supplies of propane will be readily available in the future, management currently expects to be able to secure adequate supplies during the fiscal year ending September 30, 2016. If supply from major sources were interrupted, however, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be adversely affected. Enterprise Products Partners, L.P., Plains Marketing, L.P., and Targa Liquids Marketing & Trade LLC supplied approximately 40% of the Partnership’s Fiscal 2015 propane supply. No other single supplier provided more than 10% of the Partnership’s total propane supply in Fiscal 2015. In certain geographical areas, however, a single supplier provides more
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than 50% of the Partnership’s requirements. Disruptions in supply in these areas could also have an adverse impact on the Partnership’s margins.
The Partnership’s supply contracts typically provide for pricing based upon (i) index formulas using the current prices established at a major storage point such as Mont Belvieu, Texas, or Conway, Kansas, or (ii) posted prices at the time of delivery. In addition, some agreements provide maximum and minimum seasonal purchase volume guidelines. The percentage of contract purchases, and the amount of supply contracted for at fixed prices, will vary from year to year as determined by the General Partner. The Partnership uses a number of interstate pipelines, as well as railroad tank cars, delivery trucks, and barges, to transport propane from suppliers to storage and distribution facilities. The Partnership stores propane at various storage facilities and terminals located in strategic areas across the U.S.
Because the Partnership’s profitability is sensitive to changes in wholesale propane costs, the Partnership generally seeks to pass on increases in the cost of propane to customers. There is no assurance, however, that the Partnership will always be able to pass on product cost increases fully, or keep pace with such increases, particularly when product costs rise rapidly. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil and natural gas, or other unforeseen events. The General Partner has adopted supply acquisition and product cost risk management practices to reduce the effect of volatility on selling prices. These practices currently include the use of summer storage, forward purchases and derivative commodity instruments, such as options and propane price swaps. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures.”
The following graph shows the average prices of propane on the propane spot market during the last five fiscal years at Mont Belvieu, Texas and Conway, Kansas, both major storage areas.
Average Propane Spot Market Prices
General Industry Information
Propane is separated from crude oil during the refining process and also extracted from natural gas or oil wellhead gas at processing plants. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for economy and ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is colorless and odorless; an odorant is added to allow for its detection. Propane is considered a clean alternative fuel under the Clean Air Act Amendments of 1990, producing negligible amounts of pollutants when properly consumed.
Competition
Propane competes with other sources of energy, some of which are less costly for equivalent energy value. Propane distributors compete for customers with suppliers of electricity, fuel oil and natural gas, principally on the basis of price, service, availability
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and portability. Electricity is generally more expensive than propane on a British thermal unit (“Btu”) equivalent basis, but the convenience and efficiency of electricity makes it an attractive energy source for consumers and developers of new homes. Fuel oil is also a major competitor of propane and, although a less environmentally attractive energy source, is currently less expensive than propane. Furnaces and appliances that burn propane will not operate on fuel oil, and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new equipment. Propane serves as an alternative to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Natural gas is generally a significantly less expensive source of energy than propane, although in areas where natural gas is available, propane is used for certain industrial and commercial applications and as a standby fuel during interruptions in natural gas service. The gradual expansion of the nation’s natural gas distribution systems has resulted in the availability of natural gas in some areas that previously depended upon propane. However, natural gas pipelines are not present in many areas of the country where propane is sold for heating and cooking purposes.
For motor fuel customers, propane competes with gasoline, diesel fuel, electric batteries, fuel cells and, in certain applications, liquefied natural gas and compressed natural gas. Wholesale propane distribution is a highly competitive, low margin business. Propane sales to other retail distributors and large-volume, direct-shipment industrial end-users are price sensitive and frequently involve a competitive bidding process.
Retail propane industry volumes have been declining for several years and no or modest growth in total demand is foreseen in the next several years. Therefore, the Partnership’s ability to grow within the industry is dependent on its ability to acquire other retail distributors and to achieve internal growth, which includes expansion of the ACE program and the National Accounts program (through which the Partnership encourages multi-location propane users to enter into a single AmeriGas supply agreement rather than multiple agreements with other suppliers), as well as the success of its sales and marketing programs designed to attract and retain customers. The failure of the Partnership to retain and grow its customer base would have an adverse effect on its long-term results.
The domestic propane retail distribution business is highly competitive. The Partnership competes in this business with other large propane marketers, including other full-service marketers, and thousands of small independent operators. Some farm cooperatives, rural electric cooperatives, and fuel oil distributors include propane distribution in their businesses and the Partnership competes with them as well. The ability to compete effectively depends on providing high quality customer service, maintaining competitive retail prices and controlling operating expenses. The Partnership also offers customers various payment and service options, including guaranteed price programs, fixed price arrangements and pricing arrangements based on published propane prices at specified terminals.
In Fiscal 2015, the Partnership’s retail propane sales totaled nearly 1.2 billion gallons. Based on the most recent annual survey by the American Petroleum Institute, 2013 domestic retail propane sales (annual sales for other than chemical uses) in the U.S. totaled approximately 8.8 billion gallons. Based on LP-GAS magazine rankings, 2013 sales volume of the ten largest propane companies (including AmeriGas Partners) represented approximately 38% of domestic retail sales.
Properties
As of September 30, 2015, the Partnership owned approximately 81% of its over 700 local offices throughout the country. The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 30, 2015, the Partnership operated a transportation fleet with the following assets:

Approximate Quantity & Equipment Type | % Owned | % Leased
1,000 | Trailers | 76% | 24%
375 | Tractors | 9% | 91%
500 | Railroad tank cars | 2% | 98%
3,700 | Bobtail trucks | 39% | 61%
425 | Rack trucks | 38% | 62%
4,000 | Service and delivery trucks | 52% | 48%

Other assets owned at September 30, 2015 included approximately 1.8 million stationary storage tanks with typical capacities of more than 120 gallons and approximately 4.7 million portable propane cylinders with typical capacities of 1 to 120 gallons.
Trade Names, Trade and Service Marks
The Partnership markets propane principally under the “AmeriGas®”, “America’s Propane Company®”, “Heritage Propane®”,
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“Relationships Matter®”, and “ServiceMark®” trade names and related service marks. The Partnership also markets propane under various other trade names throughout the U.S. UGI owns, directly or indirectly, all the right, title and interest in the “AmeriGas” name and related trade and service marks. The General Partner owns all right, title and interest in the “America’s Propane Company” trade name and related service marks. The Partnership has an exclusive (except for use by UGI, AmeriGas, Inc., AmeriGas Polska Sp. z.o.o. and the General Partner), royalty-free license to use these trade names and related service marks. UGI and the General Partner each have the option to terminate its respective license agreement (on 12 months prior notice in the case of UGI), without penalty, if the General Partner is removed as general partner of the Partnership other than for cause. If the General Partner ceases to serve as the general partner of the Partnership for cause, the General Partner has the option to terminate its license agreement upon payment of a fee to UGI equal to the fair market value of the licensed trade names. UGI has a similar termination option; however, UGI must provide 12 months prior notice in addition to paying the fee to the General Partner.
Seasonality
Because many customers use propane for heating purposes, the Partnership’s retail sales volume is seasonal. During Fiscal 2015, approximately 67% of the Partnership’s retail sales volume occurred, and substantially all of the Partnership’s operating income was earned, during the peak heating season from October through March. As a result of this seasonality, sales are typically higher in the Partnership’s first and second fiscal quarters (October 1 through March 31). Cash receipts are generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the winter heating season.
Sales volume for the Partnership traditionally fluctuates from year-to-year in response to variations in weather, prices, competition, customer mix and other factors, such as conservation efforts and general economic conditions. For information on national weather statistics, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Government Regulation
The Partnership is subject to various federal, state and local environmental, health, safety and transportation laws and regulations governing the storage, distribution and transportation of propane and the operation of bulk storage propane terminals. Generally, these laws impose limitations on the discharge of pollutants, establish standards for the handling of solid and hazardous substances, and require the investigation and cleanup of environmental contamination. These laws include, among others, the federal Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act (“OSHA”), the Homeland Security Act of 2002, the Emergency Planning and Community Right-to-Know Act, the Clean Water Act, and comparable state statutes. We incur expenses associated with compliance with our obligations under federal and state environmental laws and regulations, and we believe that we are in material compliance with all of our obligations. We maintain various permits that are necessary to operate our facilities, some of which may be material to our operations. We continually monitor our operations with respect to potential environmental issues, including changes in legal requirements.
Hazardous Substances and Wastes
The Partnership is investigating and remediating contamination at a number of present and former operating sites in the United States, including former sites where it or its former subsidiaries operated manufactured gas plants. CERCLA and similar state laws impose joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a “hazardous substance” into the environment without regard to fault or the legality of the original conduct. Propane is not a hazardous substance within the meaning of CERCLA.
Health and Safety
The Partnership is subject to the requirements of OSHA and comparable state laws that regulate the protection of the health and safety of our workers. These laws require the Partnership, among other things, to maintain information about materials, some of which may be hazardous or toxic, that are used, released, or produced in the course of our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and responders, commercial and industrial customers, and local citizens in accordance with applicable federal and state Emergency Planning and Community Right-to-Know Act requirements. The Partnership’s operations are also subject to the safety hazard communication requirements and reporting obligations set forth in federal workplace standards.
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All states in which the Partnership operates have adopted fire safety codes that regulate the storage, distribution, and use of propane. In some states, these laws are administered by state agencies, and in others they are administered on a municipal level. The Partnership conducts training programs to help ensure that its operations are in compliance with applicable governmental regulations. With respect to general operations, National Fire Protection Association (“NFPA”) Pamphlets No. 54 and No. 58 and/or one or more of various international codes (including international fire, building and fuel gas codes) establish rules and procedures governing the safe handling of propane, or comparable regulations, which have been adopted by all states in which the Partnership operates. Management believes that the policies and procedures currently in effect at all of its facilities for the handling, storage, distribution, and use of propane are consistent with industry standards and are in compliance, in all material respects, with applicable environmental, health and safety laws.
With respect to the transportation of propane by truck, the Partnership is subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act, the Hazardous Materials & Transportation Act, and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials, including propane for purposes of these regulations, and are administered by the U.S. Department of Transportation (“DOT”), Pipeline and Hazardous Materials Safety Administration. The Natural Gas Safety Act of 1968 required the DOT to develop and enforce minimum safety regulations for the transportation of gases by pipeline. The DOT's pipeline safety regulations apply, among other things, to a propane gas system that supplies 10 or more residential customers or two or more commercial customers from a single source and to a propane gas system any portion of which is located in a public place. The DOT’s pipeline safety regulations require operators of all gas systems to provide operator qualification standards and training and written instructions for employees and third party contractors working on covered pipelines and facilities, establish written procedures to minimize the hazards resulting from gas pipeline emergencies, and conduct and keep records of inspections and testing. Operators are subject to the Pipeline Safety Improvement Act of 2002. Management believes that the procedures currently in effect at all of the Partnership’s facilities for the handling, storage, transportation and distribution of propane are consistent with industry standards and are in compliance, in all material respects, with applicable laws and regulations.
Climate Change
There continues to be concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global warming. Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, we anticipate that this will provide us with a competitive advantage over other sources of energy, such as fuel oil and coal, to the extent new climate change regulations become effective. At the same time, increased regulation of GHG emissions, especially in the transportation sector, could impose significant additional costs on the Partnership, suppliers and customers. In recent years, there has been an increase in state initiatives aimed at regulating GHG emissions. For example, the California Environmental Protection Agency established a Cap & Trade program that requires certain covered entities, including propane distribution companies, to purchase allowances to compensate for the GHG emissions created by their business operations. The impact of new legislation and regulations will depend on a number of factors, including (i) which industry sectors would be impacted, (ii) the timing of required compliance, (iii) the overall GHG emissions cap level, (iv) the allocation of emission allowances to specific sources, and (v) the costs and opportunities associated with compliance.
Employees
The Partnership does not directly employ any persons responsible for managing or operating the Partnership. The General Partner provides these services and is reimbursed for its direct and indirect costs and expenses, including all compensation and benefit costs. At September 30, 2015, the General Partner had nearly 8,500 employees, including over 500 part-time, seasonal and temporary employees, working on behalf of the Partnership. UGI also performs certain financial and administrative services for the General Partner on behalf of the Partnership and is reimbursed by the Partnership.
UGI INTERNATIONAL
UGI FRANCE
Our UGI France LPG distribution business is conducted in France and the Benelux countries (consisting of Belgium, the Netherlands, and Luxembourg). As a result of the Totalgaz Acquisition, our retail LPG distribution business in France has nearly doubled and our focus, in the short-term, will be to successfully integrate Finagaz and to capitalize on the benefits of the acquisition. UGI France also operates a natural gas marketing business in France and Belgium and sold approximately 13.3 million dekatherms of natural gas during Fiscal 2015.
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Products, Services and Marketing
During Fiscal 2015, UGI France sold approximately 283 million gallons of LPG in France (including approximately 52 million gallons attributed to Finagaz’ operations in France subsequent to the Totalgaz Acquisition) and approximately 47 million gallons of LPG in the Benelux countries. UGI France is the largest LPG distributor in France and Luxembourg and one of the largest LPG distributors in the Netherlands and Belgium. UGI France’s customer base consists of residential, commercial, agricultural and motor fuel customer accounts that use LPG for space heating, cooking, water heating, process heat, forklift operations, and transportation. UGI France sells LPG in cylinders, and in small, medium and large tanks. Sales of LPG are also made to service stations to accommodate vehicles that run on LPG. UGI France sells LPG in cylinders to approximately 20,000 retail outlets, such as supermarkets, individually owned stores and gas stations. Supermarket sales represented approximately 76% of UGI France’s butane cylinder sales volume and approximately 14% of UGI France’s propane cylinder sales volume in Fiscal 2015. At September 30, 2015, UGI France had approximately 406,000 bulk customers, more than 18,500 natural gas customers and nearly 15 million cylinders in circulation. Approximately 61% of UGI France’s Fiscal 2015 sales (based on volumes) were cylinder and small bulk, 15% medium bulk, 21% large bulk and 3% to service stations for automobiles. UGI France also engages in wholesale sales of LPG and provides logistic, storage and other services to third-party LPG distributors. In addition, UGI France operates a natural gas marketing business in France and Belgium that services both commercial and residential customers. No single customer represents, or is anticipated to represent, more than 10% of total revenues for UGI France.
Sales to small bulk customers represent the largest segment of UGI France’s business in terms of volume, revenue and total margin. Small bulk customers are primarily residential and small business users, such as restaurants, that use LPG mainly for heating and cooking. Small bulk customers also include municipalities, which use LPG for heating certain sports facilities and swimming pools, and the poultry industry for use in chicken brooding.
Medium bulk customers use propane only, and consist mainly of large residential developments such as housing developments, hospitals, municipalities and medium-sized industrial enterprises, and poultry brooders. Large bulk customers include agricultural companies and companies that use LPG in their industrial processes.
The principal end-users of cylinders are residential customers who use LPG supplied in this form for domestic applications such as cooking and heating. Butane cylinders accounted for approximately 52% of all LPG cylinders distributed by UGI France in Fiscal 2015, with propane cylinders accounting for 48% of all LPG cylinders distributed by UGI France in Fiscal 2015. Propane cylinders are also used to supply fuel for forklift trucks. The market demand for cylinders continues to decline, due primarily to customers gradually changing to other household energy sources for cooking and heating, such as natural gas and electricity.
LPG Supply and Storage
Prior to the Totalgaz Acquisition, UGI France had an agreement with Totalgaz (which was owned by Total France until the acquisition) for the supply of butane in France, with pricing based on internationally quoted market prices. Under this agreement, approximately 50% of UGI France’s butane requirements in France were guaranteed until September 2015. The balance of UGI France’s butane requirements in France were purchased on a spot basis. In Fiscal 2015, UGI France purchased substantially all of its propane supply for its operations in France from SHV and TOTSA and substantially all of its butane and propane requirements for its operations in the Benelux countries from SHV and GUNVOR.
Since the closing of the Totalgaz Acquisition and pursuant to its terms, UGI France has a supply agreement with the Total group of companies. Under this agreement, approximately 50% of UGI France’s propane and butane requirements in France are guaranteed until September 2016. The balance of its propane and butane requirements in France will be purchased from TOTSA and SHV as term suppliers or from spot market purchases. From time to time, as needed, UGI France also purchases propane on the international market and on the domestic spot market.
UGI France has an interest in three primary storage facilities that are located at deep sea harbor facilities, and 54 secondary storage facilities. It also manages an extensive logistics and transportation network. Access to seaborne facilities allows UGI France to diversify its LPG supplies through imports. LPG stored in primary storage facilities is transported to smaller storage facilities by rail, sea and road. At secondary storage facilities, LPG is loaded into cylinders or trucks equipped with tanks and then delivered to customers.
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Competition and Seasonality
The LPG markets in France and the Benelux countries are mature, with modest declines in total demand due to competition with other fuels and other energy sources, conservation and the economic climate. Sales volumes are affected principally by the severity of the weather and customer migration to alternative energy forms, including natural gas and electricity. Because UGI France’s profitability is sensitive to changes in wholesale LPG costs, UGI France generally seeks to pass on increases in the cost of LPG to customers. There is no assurance, however, that UGI France will always be able to pass on product cost increases fully when product costs rise rapidly. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil and natural gas, or other unforeseen events. High LPG prices may result in slower than expected growth due to customer conservation and customers seeking less expensive alternative energy sources. France derives a significant portion of its electricity from nuclear power plants. Due to the nuclear power plants, as well as the regulation of electricity prices by the French government, electricity prices in France are generally less expensive than LPG. As a result, electricity has increasingly become a more significant competitor to LPG in France than in other countries where we operate. In addition, government policies and incentives that favor alternative energy sources can result in customers migrating to energy sources other than LPG in both France and the Benelux countries.
In Fiscal 2015, UGI France competed in all of its product markets in France on a national level, principally with three LPG distribution companies, Totalgaz (owned by Total France until the closing of the Totalgaz Acquisition), Butagaz (owned by Societe des Petroles Shell), and Compagnie des Gaz de Petrole Primagaz (owned by SHV Holding NV), as well as with a regional competitor, Vitogaz. UGI France also competes with supermarket chains that affiliate with LPG distributors to offer their own brands of cylinders. UGI France has partnered with two supermarket chains in France in this market. If UGI France is unsuccessful in expanding its services to other supermarket chains, its market share through supermarket sales may decline in France. In the Benelux countries, UGI France competes in all of its product markets on a national level, principally with Compagnie des Gaz de Petrole Primagaz, as well as with several regional competitors. In recent years, competition has increased in the Benelux countries as small competitors have reduced their price offerings. In the Netherlands, several LPG distributors offer their own brands of cylinders. UGI France seeks to increase demand for its butane and propane cylinders through marketing and product innovations. Some of UGI France’s competitors are affiliates of its LPG suppliers. As a result, its competitors may obtain product at more competitive prices.
Because many of UGI France’s customers use LPG for heating, sales volume is affected principally by the severity of the temperatures during the heating season months and traditionally fluctuates from year-to-year in response to variations in weather, prices and other factors, such as conservation efforts and the challenging economic climate. Demand for LPG is higher during the colder months of the year. During Fiscal 2015, approximately 63% of UGI France’s retail sales volume occurred, and substantially all of UGI France’s operating income was earned, during the six months from October through March. For historical information on weather statistics for UGI France, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Government Regulation
UGI France’s business is subject to various laws and regulations at the national and European levels with respect to matters such as protection of the environment, the storage and handling of hazardous materials and flammable substances, the discharge of contaminants into the environment and the safety of persons and property. In Belgium and Luxembourg, UGI France is also subject to price regulations that permit UGI France to increase the price of LPG sold to small bulk, medium bulk, large bulk and cylinder customers (up to a defined maximum price) when UGI France’s costs fluctuate.
Properties
UGI France has an interest in three primary storage facilities, one of which is a refrigerated facility. In addition, UGI France is able to use 30,000 cubic meters of capacity of a storage facility, Donges, by virtue of Antargaz’ 50% ownership of GIE Donges.
In connection with the Totalgaz Acquisition and pursuant to the République Française Autorité de la Concurrence’s decision to approve the acquisition in May 2015, UGI France has agreed to sell certain depots and a portion of its interests in GIE Norgal and Cobogal; the sale related to GIE Norgal was completed in October 2015. The table below sets forth details of UGI France’s current ownership in its three primary storage facilities, including GIE Norgal and Cobogal:
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| Ownership % |  | UGI France Storage Capacity - Propane (m3) (1) |  | UGI France Storage Capacity - Butane (m3) (1)
GIE Norgal | 61.1 |  |  | 25,600 |  |  | 10,200 |
Geogaz-Lavera | 18.6 |  |  | 18,500 |  |  | 37,200 |
Cobogal | 60.0 |  |  | 5,200 |  |  | 1,800 |

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(1) | Cubic meters (1 cubic meter is equivalent to approximately 264 gallons).

UGI France has 54 secondary storage facilities, 42 of which are wholly-owned. The others are partially owned through joint ventures.
Employees
At September 30, 2015, UGI France had nearly 1,700 employees.
FLAGA & OTHER
During Fiscal 2015, our UGI International - Flaga & Other LPG distribution businesses were conducted principally in Europe through our wholly-owned subsidiaries, Flaga and AvantiGas, and in China through our majority-owned partnership, ChinaGas Partners, L.P. Flaga is referred to in this section collectively with its subsidiaries as “Flaga” unless the context otherwise requires. Flaga operates in Austria, the Czech Republic, Denmark, Finland, Hungary, Norway, Poland, Romania, Slovakia, Sweden and Switzerland. AvantiGas operates in the United Kingdom.
During Fiscal 2015, Flaga sold approximately 326 million gallons of LPG. Flaga is the largest distributor of LPG in Austria, Denmark, and Hungary and one of the largest distributors of LPG in Poland, the Czech Republic, Slovakia, Norway, and Sweden. During Fiscal 2015, AvantiGas sold over 156 million gallons of LPG and our majority-owned partnership in China sold approximately 10 million gallons of LPG.
FLAGA
Products, Services and Marketing
During Fiscal 2015, Flaga sold approximately 326 million gallons of LPG (of which approximately 19 million gallons were to wholesale customers). Flaga serves customers that use LPG for residential, commercial, industrial, agricultural, resale, and automobile fuel (“auto gas”) purposes. Flaga’s customers primarily use LPG for heating, cooking, motor fuel (including forklifts), leisure activities, construction work, manufacturing, crop and grain drying, power generation and irrigation. Flaga sells LPG in cylinders and in small, medium, and large bulk tanks. At September 30, 2015, Flaga had over 58,000 customers and nearly 5.8 million cylinders in circulation. Approximately 24% of Flaga’s Fiscal 2015 sales (based on volumes) were cylinder and small bulk, 34% auto gas, 38% large bulk, and 4% medium bulk.
Flaga has a total of 19 sales offices throughout the countries it serves. Sales offices generally consist of an office location where customers can directly purchase LPG. Except for Poland (51%), Sweden (10%), and Norway (10%), no single country represented more than approximately 10% of Flaga’s total LPG gallons sold in Fiscal 2015. Flaga distributes cylinders directly to its customers and through the use of distributors who resell the cylinders to end users under the distributor’s pricing and terms. No single customer represents or is anticipated to represent more than 5% of total revenues for Flaga, with the exception of one auto gas customer that represented approximately 10% of Flaga’s total revenues in Fiscal 2015.
LPG Supply and Storage
Flaga typically enters into an annual LPG supply agreement with TCO/Chevron. During Fiscal 2015, TCO/Chevron supplied approximately 48% of Flaga’s LPG requirements, with pricing based on internationally quoted market prices, and 32 suppliers accounted for the remaining 52% of Flaga’s LPG supply. Flaga also purchases LPG on the international market and on the domestic markets, under annual term agreements with international oil and gas trading companies, including SIBUR, NOVATEK, LOTOS, and PGNIG, and from domestic refineries, primarily OMV, Shell, MOL, and Statoil. In addition, LPG purchases are made on the spot market from international oil and gas traders.
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Flaga operates 16 main storage facilities, including one in Denmark and one in Finland that are located at deep sea harbor facilities, two LPG import terminals in Poland, one LPG import terminal in Romania, and 50 secondary storage facilities. Flaga manages a widespread logistics and transportation network including approximately 210 leased railcars, and also maintains various transloading and filling agreements with third parties. LPG stored in primary storage facilities is transported to smaller storage facilities by rail or truck.
Competition and Seasonality
The retail propane industry in the Western European countries in which Flaga operates is mature, with slight declines in overall demand in recent years, due primarily to the expansion of natural gas, customer conservation and economic conditions. In the Eastern European countries in which Flaga operates, the demand for LPG is expected to grow in certain segments. Competition for customers is based on contract terms as well as on product prices. Flaga competes with other LPG marketers, including competitors located in other European countries, and also competes with providers of other sources of energy, principally natural gas, electricity and wood.
Because many of Flaga’s customers use LPG for heating, sales volumes in Flaga’s sales territories are affected by the severity of the temperatures during the heating season months and traditionally fluctuate from year-to-year in response to variations in weather, prices and other factors, such as conservation efforts and the economic climate. Because Flaga’s profitability is sensitive to changes in wholesale LPG costs, Flaga generally seeks to pass on increases in the cost of LPG to customers. There is no assurance, however, that Flaga will always be able to pass on product cost increases fully when product costs rise. In parts of Flaga’s sales territories, it is particularly difficult to pass on rapid increases in the price of LPG due to the low per capita income of customers in several of its territories and the intensity of competition. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil and natural gas, or other unforeseen events. High LPG prices may result in slower than expected growth due to customer conservation and customers seeking less expensive alternative energy sources. In many of Flaga’s sales territories, government policies and incentives that favor alternative energy sources may result in customers migrating to energy sources other than LPG. Rules and regulations applicable to LPG industry operations in many of the Eastern European countries where Flaga operates are still evolving, or are not consistently enforced, causing intensified competitive conditions in those areas.
Government Regulation
Flaga’s business is subject to various laws and regulations at both the national and European levels with respect to matters such as protection of the environment and the storage and handling of hazardous materials and flammable substances.
Employees
At September 30, 2015, Flaga had approximately 1,000 employees.
AVANTIGAS
Products, Services and Marketing
During Fiscal 2015, AvantiGas sold over 156 million gallons of LPG (of which approximately 96 million gallons were wholesale gallons). At September 30, 2015, AvantiGas had over 14,500 customers. AvantiGas serves customers that use LPG for wholesale, aerosol, agricultural, residential, commercial, industrial, and auto gas purposes. AvantiGas’ customers primarily use LPG for heating, cooking, motor fuel (including forklifts), leisure activities, industrial processes and aerosol propellant. AvantiGas sells LPG in small, medium, and large bulk tanks with small bulk sales representing approximately 6% of Fiscal 2015 sales (based on volumes), medium bulk sales representing approximately 2% of Fiscal 2015 sales and large bulk sales representing approximately 92% of Fiscal 2015 sales.
AvantiGas serves its customer base through a centralized customer service center and, therefore, does not have sales offices in the United Kingdom. Sales to wholesale customers represented approximately 61% of gallons sold; aerosol customers 21%; agricultural customers 5%; residential customers 5%; and commercial, industrial and autogas 8%. Three wholesale customers and two aerosol customers collectively represented over 53% of AvantiGas’ total revenues in Fiscal 2015. No other customer represents or is anticipated to represent more than 5% of total revenues for AvantiGas.
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LPG Supply and Storage
AvantiGas has a five-year agreement with Essar Energy plc’s Stanlow refinery and a one-year agreement with Statoil UK Ltd.’s Mossmorran terminal for the supply of more than 90% of AvantiGas’ LPG requirements. Each agreement will terminate during Fiscal 2016. Pricing for such agreements is based on internationally quoted market prices. In Fiscal 2015, AvantiGas purchased the remainder of its LPG requirements from Centrica plc, through a one-year agreement that terminated in Fiscal 2015, and other third party suppliers.
AvantiGas operates eight main storage facilities in England, Scotland and Wales. AvantiGas manages a logistics and transportation network, consisting of approximately 40 trucks, and also maintains various transportation agreements with third parties. LPG stored in primary storage facilities is transported to smaller storage facilities or customers by truck.
Competition and Seasonality
The retail propane industry in the United Kingdom is highly concentrated and is mature, with slight declines in overall demand in recent years, due primarily to the expansion of natural gas, customer conservation and challenging economic conditions. Competition for customers is based on contract terms as well as on product prices. AvantiGas competes with other LPG marketers in the United Kingdom.
Because many of AvantiGas’ customers use gas for heating purposes, sales volumes in AvantiGas’ sales territories are affected principally by the severity of the temperatures during the heating season months and traditionally fluctuate from year-to-year in response to variations in weather, prices and other factors, such as energy conservation efforts and the economic climate. During Fiscal 2015, approximately 54% of AvantiGas’ retail sales volume occurred, and approximately 70% of AvantiGas’ operating income was earned, during the peak heating season where AvantiGas operates. Because AvantiGas’ profitability is sensitive to changes in wholesale LPG costs, AvantiGas generally seeks to pass on increases in the cost of LPG to customers. There is no assurance, however, that AvantiGas will always be able to pass on product cost increases fully when product costs rise. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities, such as crude oil and natural gas, or other unforeseen events. High LPG prices may result in slower than expected growth due to customer conservation and customers seeking less expensive alternative energy sources.
Government Regulation
AvantiGas’ business is subject to various laws and regulations at both the national and European levels with respect to matters such as competition, protection of the environment and the storage and handling of hazardous materials and flammable substances.
Employees
At September 30, 2015, AvantiGas had approximately 200 employees.
MIDSTREAM & MARKETING
ENERGY SERVICES
Retail Energy Marketing
Energy Services sells natural gas, liquid fuels and electricity to approximately 20,000 residential, commercial, and industrial customers at approximately 44,300 locations. Energy Services serves customers in all or portions of Pennsylvania, New Jersey, Delaware, New York, Ohio, Maryland, Massachusetts, Virginia, North Carolina, South Carolina and the District of Columbia. Energy Services delivers natural gas for customers located on the distribution systems of 36 local gas utilities. It supplies power to customers through the use of the transmission and distribution facilities of 20 utility systems.
Historically, a majority of Energy Services’ commodity sales have been made under fixed-price agreements, which typically contain a take-or-pay arrangement that requires customers to purchase a fixed amount of product for a fixed price during a specified period, and to pay for the product even if the customer does not take delivery of the product. However, a growing number of Energy Services’ commodity sales are currently being made under requirements contracts, under which Energy Services is typically an exclusive supplier and will supply as much product at a fixed price as the customer requires. Energy Services manages supply cost volatility related to these agreements by (i) entering into fixed-price supply arrangements with a diverse group of suppliers, (ii) holding its own interstate pipeline transportation and storage contracts to efficiently utilize gas supplies, (iii) entering into exchange-traded futures contracts on the New York Mercantile Exchange and the Intercontinental Exchange, (iv) entering into
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over-the-counter derivative arrangements with major international banks and major suppliers, (v) utilizing supply assets that it owns or manages, and (vi) utilizing financial transmission rights to hedge price risk against certain transmission costs. Energy Services also bears the risk for balancing and delivering natural gas and power to its customers under various gas pipeline and utility company tariffs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures.”
Midstream Assets
Energy Services operates a natural gas liquefaction, storage and vaporization facility in Temple, Pennsylvania (“Temple Facility”), and propane storage and propane-air mixing stations in Bethlehem, Reading, Hunlock Creek, and White Deer, Pennsylvania. It also operates propane storage, rail transshipment terminals, and propane-air mixing stations in Steelton and Williamsport, Pennsylvania. These assets are used in Energy Services’ energy peaking business that provides supplemental energy, primarily liquefied natural gas and propane-air mixtures, to gas utilities on interstate pipelines at times of high demand (generally during periods of coldest winter weather). In Fiscal 2015, Energy Services expanded its energy peaking services at the Temple Facility and sold liquefied natural gas to customers for use by trucks, drilling rigs, other motor vehicles and facilities located off the gas grid. Energy Services also manages natural gas pipeline and storage contracts for UGI Utilities, subject to a competitive bid process, as well as storage capacity owned by Energy Services.
A wholly-owned subsidiary of Energy Services owns and operates underground natural gas storage and related high pressure pipeline facilities, which have FERC approval to sell storage services at market-based rates. The storage facilities are located in the Marcellus Shale region of Pennsylvania and have a total storage capacity of 15 million dekatherms and a maximum daily withdrawal quantity of 224,000 dekatherms. In Fiscal 2015, Energy Services leased more than 80% of the capacity at its underground natural gas facilities to third parties. Through its operation of a compressor station, Energy Services also receives natural gas from the Tennessee Gas Pipeline for injection into a storage facility on a firm basis throughout the year.
In Fiscal 2015, Energy Services continued making investments in infrastructure projects to support the development of natural gas in the Marcellus Shale region of Pennsylvania. On October 28, 2015, Energy Services completed the last phase of a three-phase expansion of its Auburn gathering system in the Marcellus Shale region following the construction of three additional compressor units at its Manning Compressor Station in Wyoming County, Pennsylvania. Energy Services also announced that service commenced on its 9-mile pipeline (Auburn Loop project) connecting Susquehanna County to the Manning Compressor Station on November 1, 2015. In Fiscal 2015, Energy Services also completed construction of and commenced service on the Union Dale Lateral pipeline to deliver gas to a PNG delivery station in Union Dale, Pennsylvania and completed its Temple LNG project that increased the liquefaction capacity of its Temple Facility. In addition, Energy Services made progress on its participation in the PennEast Pipeline project to develop an approximately 118-mile pipeline from Luzerne County, Pennsylvania to the Trenton-Woodbury interconnection in New Jersey in Fiscal 2015. When completed, the pipeline will transport approximately 1 billion cubic feet of lower cost natural gas to residential and commercial customers each day. During Fiscal 2015, Energy Services also announced (i) its plans, through its wholly-owned subsidiary, UGI Sunbury, LLC, to construct an approximately 35-mile interstate natural gas pipeline in central Pennsylvania to serve the proposed Hummel Station combined-cycle 1,000 megawatt power generation facility near the Shamokin Dam in Snyder County, Pennsylvania (Sunbury Pipeline project) and (ii) its Invenergy pipeline project to provide natural gas service to a power generation facility in Jessup, Pennsylvania.
Future planned investments are expected to cover a range of midstream asset opportunities, including interstate pipelines, local gathering systems and gas storage facilities and complementary and related investments.
Competition
Energy Services competes with other midstream operators to sell gathering, compression, storage, and pipeline transportation services. Energy Services competes in both the regulated and non-regulated environment against interstate and intrastate pipelines that gather, compress, process, transport, and market natural gas. Energy Services sells midstream services primarily to producers, marketers, and utilities on the basis of price, customer service, flexibility, reliability, and operational experience. The competition in the midstream segment is significant and has grown recently in the northeast U.S. as more competitors seek opportunities offered by the development of the Marcellus and Utica Shales.
Energy Services also competes with other marketers, consultants, and local utilities to sell natural gas, liquid fuels, electric power, and related services to customers in its service area principally on the basis of price, customer service, and reliability. Energy Services has faced an increase in competition in recent years as new markets for natural gas, liquid fuels, electric power, and related services have emerged.
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Government Regulation
FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy, as well as the sales for resale of natural gas and related storage and transportation services. Energy Services has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates to the extent that Energy Services purchases power in excess of its retail customer needs. Two subsidiaries of Energy Services currently operate natural gas storage facilities under FERC certificate approvals and offer services to wholesale customers at FERC-approved market-based rates. In July 2015, UGI Sunbury, LLC filed for FERC approval for the Sunbury Pipeline project. Energy Services will become subject to additional FERC accounting regulations and standards of conduct upon FERC approval and completion of construction of this project. In addition, the PennEast Pipeline project filed an application for FERC approval in September 2015. Energy Services is also subject to FERC reporting requirements, market manipulation rules and other FERC enforcement and regulatory powers with respect to its commodity business.
Energy Services’ midstream operations include natural gas gathering pipelines and compression in northeastern Pennsylvania that are regulated under the Pipeline Safety Improvement Act of 2002 and subject to operational oversight by both the Pipeline and Hazardous Materials Safety Administration and the PUC.
Energy Services is subject to various federal, state and local environmental, safety and transportation laws and regulations governing the storage, distribution and transportation of propane and the operation of bulk storage LPG terminals. These laws include, among others, the Resource Conservation and Recovery Act, CERCLA, the Clean Air Act, OSHA, the Homeland Security Act of 2002, the Emergency Planning and Community Right-to-Know Act, the Clean Water Act and comparable state statutes. CERCLA imposes joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a “hazardous substance” into the environment without regard to fault or the legality of the original conduct. With respect to the operation of natural gas gathering and transportation pipelines, Energy Services also is required to comply with the provisions of the Pipeline Safety Improvement Act of 2002 and the regulations of the U.S. DOT.
Employees
At September 30, 2015, Energy Services had approximately 235 employees.
ELECTRIC GENERATION
Products and Services
UGID has an approximate 5.97% (approximately 102 megawatt) ownership interest in the Conemaugh generation station (“Conemaugh”), a 1,711-megawatt, coal-fired generation station located near Johnstown, Pennsylvania. Conemaugh is owned by a consortium of energy companies and operated by a unit of NRG Energy. UGID also owns and operates the Hunlock Station located near Wilkes-Barre, Pennsylvania, a 130-megawatt natural gas-fueled generating station which was converted to natural gas operations in July 2011.
UGID also owns and operates a landfill gas-fueled generation plant near Hegins, Pennsylvania, with gross generating capacity of 11 megawatts. The plant qualifies for renewable energy credits.
UGID also owns 13.5 megawatts of solar-powered generation capacity in Pennsylvania, Maryland and New Jersey.
Competition
UGID competes with other generation stations on the interface of PJM Interconnection, LLC (“PJM”), a regional transmission organization that coordinates the movement of wholesale electricity in certain states, including the states in which we operate, and bases sales on bid pricing. Generally, each power generator has a small share of the total market on PJM.
Government Regulation
UGID owns electric generation facilities that are within the control area of PJM and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. UGID receives certain revenues collected by PJM, determined under an approved rate schedule. Like Energy Services, UGID has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates. UGID is also subject to FERC reporting requirements, market manipulation rules and other FERC enforcement and regulatory powers.
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Employees
At September 30, 2015, UGID had approximately 25 employees.
GAS UTILITY
Gas Utility consists of the regulated natural gas distribution businesses of our subsidiary, UGI Utilities, and UGI Utilities’ subsidiaries, PNG and CPG. Gas Utility serves nearly 617,000 customers in eastern and central Pennsylvania and more than five hundred customers in portions of one Maryland county. Gas Utility is regulated by the PUC and, with respect to its customers in Maryland, the Maryland Public Service Commission.
Service Area; Revenue Analysis
Gas Utility provides natural gas distribution services to nearly 617,000 customers in certificated portions of 46 eastern and central Pennsylvania counties through its distribution system. Contemporary materials, such as plastic or coated steel, comprise approximately 88% of Gas Utility’s 12,000 miles of gas mains, with bare steel pipe comprising approximately 9% and cast iron pipe comprising approximately 3% of Gas Utility’s gas mains. In accordance with Gas Utility’s agreement with the PUC, Gas Utility will replace the cast iron portion of its gas mains by March of 2027 and the bare steel portion by September 2041. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock Haven, Pittston, Pottsville, and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility’s service area are major production centers for basic industries such as specialty metals, aluminum, glass and paper product manufacturing. Gas Utility also distributes natural gas to more than 500 customers in portions of one Maryland county.
System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2015 was approximately 213.5 billion cubic feet (“bcf”). System sales of gas accounted for approximately 31% of system throughput, while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for approximately 69% of system throughput.
Sources of Supply and Pipeline Capacity
Gas Utility is permitted to recover prudently incurred costs of natural gas it sells to its customers. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures” and Note 9 to Consolidated Financial Statements. Gas Utility meets its service requirements by utilizing a diverse mix of natural gas purchase contracts with marketers and producers, along with storage and transportation service contracts. These arrangements enable Gas Utility to purchase gas from Gulf Coast, Mid-Continent, Appalachian and Marcellus sources. For the transportation and storage function, Gas Utility has long-term agreements with a number of pipeline companies, including Texas Eastern Transmission, LP, Columbia Gas Transmission, LLC, Transcontinental Gas Pipeline Company, LLC, Dominion Transmission, Inc., ANR Pipeline Company, and Tennessee Gas Pipeline Company, L.L.C.
Gas Supply Contracts
During Fiscal 2015, Gas Utility purchased approximately 82.8 bcf of natural gas for sale to retail core-market customers (principally comprised of firm- residential, commercial and industrial customers that purchase their gas from Gas Utility (“retail core-market”)) and off-system sales customers. Approximately 83% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 17% of gas purchased by Gas Utility was supplied by approximately 24 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 12 months. Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the months of November through March.
Seasonality
Because many of its customers use gas for heating purposes, Gas Utility’s sales are seasonal. During Fiscal 2015, approximately 65% of Gas Utility’s sales volume was supplied, and more than 90% of Gas Utility’s operating income was earned, during the peak heating season from October through March.
Competition
Natural gas is a fuel that competes with electricity and oil and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of the equipment. Natural gas generally
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benefits from a competitive price advantage over oil, electricity, and propane, although the price gap between natural gas and oil narrowed in Fiscal 2015 due to a reduction in the price of oil. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility responds to this competition with marketing and sales efforts designed to retain, expand, and grow its customer base.
In substantially all of its service territories, Gas Utility is the only regulated gas distribution utility having the right, granted by the PUC or by law, to provide gas distribution services. Larger commercial and industrial customers have the right to purchase gas supplies from entities other than natural gas distribution utility companies. As a result of Pennsylvania’s Natural Gas Choice and Competition Act, effective July 1, 1999, all of Gas Utility’s customers, including core-market customers, have been afforded this opportunity.
A number of Gas Utility’s commercial and industrial customers have the ability to switch to an alternate fuel at any time and, therefore, are served on an interruptible basis under rates that are competitively priced with respect to the alternate fuel. Margin from these customers, therefore, is affected by the difference or “spread” between the customers’ delivered cost of gas and the customers’ delivered cost of the alternate fuel, the frequency and duration of interruptions, and alternative firm service options. See “Gas Utility Regulation and Rates - Pennsylvania Public Utility Commission Jurisdiction and Gas Utility Rates.”
Approximately 18% of Gas Utility’s annual throughput volume for commercial and industrial customers includes non-interruptible customers with locations that afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. In addition, approximately 25% of Gas Utility’s annual throughput volume for commercial and industrial customers is from customers who are served under interruptible rates and are also in a location near an interstate pipeline. Gas Utility has 25 such customers, 24 of which have transportation contracts extending beyond fiscal year 2016. The majority of these customers are served under transportation contracts having 3 to 20 year terms and all are among the largest customers for Gas Utility in terms of annual volumes. No single customer represents, or is anticipated to represent, more than 5% of Gas Utility’s total revenues.
Outlook for Gas Service and Supply
Gas Utility anticipates having adequate pipeline capacity, peaking services and other sources of supply available to it to meet the full requirements of all firm customers on its system through fiscal year 2016. Supply mix is diversified, market priced, and delivered pursuant to a number of long-term and short-term primary firm transportation and storage arrangements, including transportation contracts held by some of Gas Utility’s larger customers.
During Fiscal 2015, Gas Utility supplied transportation service to five major co-generation installations and four electric generation facilities. Gas Utility continues to seek new residential, commercial, and industrial customers for both firm and interruptible service. In Fiscal 2015, Gas Utility connected nearly 2,400 new commercial and industrial customers. In the residential market sector, Gas Utility connected approximately 15,000 residential heating customers during Fiscal 2015. Over 10,000 of these customers converted to natural gas heating from other energy sources, mainly oil and electricity. New home construction customers and existing non-heating gas customers who added gas heating systems to replace other energy sources primarily accounted for the other residential heating connections in Fiscal 2015.
UGI Utilities continues to monitor and participate, where appropriate, in rulemaking and individual rate and tariff proceedings before FERC affecting the rates and the terms and conditions under which Gas Utility transports and stores natural gas. Among these proceedings are those arising out of certain FERC orders and/or pipeline filings that relate to (i) the pricing of pipeline services in a competitive energy marketplace; (ii) the flexibility of the terms and conditions of pipeline service tariffs and contracts; and (iii) pipelines’ requests to increase their base rates, or change the terms and conditions of their storage and transportation services.
UGI Utilities’ objective in negotiations with interstate pipeline and natural gas suppliers, and in proceedings before regulatory agencies, is to assure availability of supply, transportation, and storage alternatives to serve market requirements at the lowest cost possible, taking into account the need for security with guaranteed deliverability and reliability of supply. Consistent with that objective, UGI Utilities negotiates the terms of firm transportation capacity on all pipelines serving it, arranges for appropriate storage and peak-shaving resources, negotiates with producers for competitively priced gas purchases and aggressively participates in regulatory proceedings related to transportation rights and costs of service.
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GAS UTILITY REGULATION AND RATES
Pennsylvania Public Utility Commission Jurisdiction and Gas Utility Rates
Gas Utility is subject to regulation by the PUC as to rates, terms and conditions of service, accounting matters, issuance of securities, contracts and other arrangements with affiliated entities, and various other matters. Rates that Gas Utility may charge for gas service come in two forms: (i) rates designed to recover purchased gas costs (“PGCs”); and (ii) rates designed to recover costs other than PGCs. Rates designed to recover PGCs are reviewed in PGC proceedings. Rates designed to recover costs other than PGCs are primarily established in general base rate proceedings.
The gas service tariffs for UGI Gas, PNG, and CPG contain PGC rates applicable to firm retail rate schedules. These PGC rates permit recovery of substantially all of the prudently incurred costs of natural gas that UGI Gas, PNG, and CPG sell to their customers. PGC rates are reviewed and approved annually by the PUC. UGI Gas, PNG, and CPG may request quarterly or, under certain conditions, monthly adjustments to reflect the actual cost of gas. Quarterly adjustments become effective on one day’s notice to the PUC and are subject to review during the next annual PGC filing. Each proposed annual PGC rate is required to be filed with the PUC six months prior to its effective date. During this period, the PUC holds hearings to determine whether the proposed rate reflects a least-cost fuel procurement policy consistent with the obligation to provide safe, adequate and reliable service. After completion of these hearings, the PUC issues an order permitting the collection of gas costs at levels that meet such standard. The PGC mechanism also provides for an annual reconciliation.
UGI Gas has two PGC rates: (i) applicable to small, firm, retail core-market customers consisting of the residential and small commercial and industrial classes; and (ii) applicable to firm, high-load factor, customers served on three separate rates. PNG and CPG each have one PGC rate applicable to all customers. Base rates for each of UGI Gas, PNG, and CPG were last established in 1995, 2009, and 2011, respectively.
On February 20, 2014, the PUC entered an order approving a Growth Extension Tariff (“GET Gas”) program under which UGI Gas, PNG, and CPG may invest up to $5 million per year for five years, or $75 million in the aggregate for all three utilities, to extend natural gas utility pipelines to provide service to unserved and underserved areas within their respective territories. Under the GET Gas program, customers utilizing the extended pipeline to receive natural gas will pay a monthly surcharge over a 10-year period to cover the cost of the extension. Gas Utility began connecting customers under the GET Gas program in October 2014.
In February 2012, Act 11 of 2012 (“Act 11”) became effective. Among other things, Act 11 authorized the PUC to permit electric and gas distribution companies, between base rate cases and subject to certain conditions, to recover reasonable and prudent costs incurred to repair, improve, or replace eligible property through a Distribution System Improvement Charge (“DSIC”) assessed to customers. DSICs are subject to quarterly adjustment, are capped at five percent of total customer charges absent a PUC-granted exception, may only be sought if a base rate case has been filed within the last five years, and are subject to certain earnings tests. In addition, Act 11 requires affected utilities to obtain approval of long-term infrastructure improvement plans (“LTIIP”) from the PUC. Act 11 also authorized electric and gas distribution companies to utilize a fully forecasted future test year when establishing rates in base rate cases before the PUC.
The PUC approved LTIIPs for UGI Gas in July 2014, and for PNG and CPG in September 2014. The PUC also approved DSIC mechanisms for PNG and CPG in September 2014 and July 2015, respectively; UGI Gas was not eligible to request a DSIC because it has not filed a base rate case within the last five years. PNG first began collecting revenues under its DSIC in April 2015. CPG has not yet qualified to begin collecting revenues under its DSIC.
FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers
UGI Utilities is subject to Section 4A of the Natural Gas Act, which prohibits the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of natural gas or natural gas transportation subject to the jurisdiction of FERC, and FERC regulations that are designed to promote the transparency, efficiency, and integrity of gas markets. UGI Utilities is also subject to Section 222 of the Federal Power Act which prohibits the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of electric energy or transmission service subject to the jurisdiction of FERC, and FERC regulations that are designed to promote the transparency, efficiency, and integrity of electric markets.
State Tax Surcharge Clauses
UGI Utilities’ gas service tariffs contain state tax surcharge clauses. The surcharges are recomputed whenever any of the tax rates
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included in their calculation are changed. These clauses protect UGI Utilities from the effects of increases in most of the Pennsylvania taxes to which it is subject.
Utility Franchises
UGI Utilities, PNG and CPG each hold certificates of public convenience issued by the PUC and certain “grandfather rights” predating the adoption of the Pennsylvania Public Utility Code and its predecessor statutes, which each of them believes are adequate to authorize them to carry on their business in substantially all of the territories to which they now render gas service. Under applicable Pennsylvania law, UGI Utilities, PNG and CPG also have certain rights of eminent domain as well as the right to maintain their facilities in streets and highways in their territories.
Other Government Regulation
In addition to regulation by the PUC and FERC, Gas Utility is subject to various federal, state and local laws governing environmental matters, occupational health and safety, pipeline safety and other matters. Gas Utility is subject to the requirements of the Resource Conservation and Recovery Act, CERCLA, and comparable state statutes with respect to the release of hazardous substances on property owned or operated by Gas Utility. See Note 16 to Consolidated Financial Statements.
Employees
At September 30, 2015, Gas Utility had approximately 1,450 employees.
ELECTRIC UTILITY AND HVAC
ELECTRIC UTILITY
Electric Utility supplies electric service to approximately 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania through a system consisting of over 2,200 miles of transmission and distribution lines and 13 substations. At September 30, 2015, UGI Utilities’ electric utility operations had approximately 70 employees.
Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with the PUC. UGI Utilities’ electric utility operations are subject to regulation by the PUC as to rates, terms and conditions of service, accounting matters, issuance of securities, contracts and other arrangements with affiliated entities, and various other matters. The most recent general base rate increase for Electric Utility became effective in 1996. PUC default service regulations became applicable to Electric Utility’s provision of default service effective January 1, 2010 and Electric Utility, consistent with these regulations, has received PUC approval through May 31, 2017 of (i) default service tariff rules, (ii) a reconcilable default service cost rate recovery mechanism to recover the cost of acquiring default service supplies, (iii) a plan for meeting the post-2009 requirements of the Alternative Energy Portfolio Standards Act (“AEPS Act”), which requires Electric Utility to directly or indirectly acquire certain percentages of its supplies from designated alternative energy sources, and (iv) a reconcilable AEPS Act cost recovery rate mechanism to recover the costs of complying with AEPS Act requirements applicable to default service supplies for service rendered through May 31, 2017. Under these rules, default service rates for most customers are adjusted quarterly.
FERC has jurisdiction over the rates and terms and conditions of service of electric transmission facilities used for wholesale or retail choice transactions. Electric Utility owns electric transmission facilities that are within the control area of PJM and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. PJM is a regional transmission organization that regulates and coordinates generation supply and the wholesale delivery of electricity. Electric Utility receives certain revenues collected by PJM, determined under a formulary rate schedule that is adjusted in June of each year to reflect annual changes in Electric Utility’s electric transmission revenue requirements, when its transmission facilities are used by third parties. FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy. Electric Utility has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates.
Under provisions of the Energy Policy Act of 2005 (“EPACT 2005”), Electric Utility is subject to certain electric reliability standards established by FERC and administered by an Electric Reliability Organization (“ERO”). Electric Utility anticipates that substantially all the costs of complying with the ERO standards will be recoverable through its PJM formulary electric transmission rate schedule.
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EPACT 2005 also granted FERC authority to impose substantial civil penalties for the violation of any regulations, orders, or provisions under the Federal Power Act and Natural Gas Act, and clarified FERC’s authority over certain utility or holding company mergers or acquisitions of electric utilities or electric transmitting utility property valued at $10 million or more.
HVAC
We conduct our heating, ventilation, air conditioning, refrigeration, mechanical & electrical contracting, and project management service business through HVAC, which serves portions of eastern and central Pennsylvania and portions of New Jersey and northern Delaware. This business serves customers in residential, commercial, industrial and new construction markets and had approximately 300 employees as of September 30, 2015.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income (loss) and identifiable assets attributable to each of UGI’s reportable business segments, and to the geographic areas in which we operate, for the 2015, 2014 and 2013 fiscal years appears in Note 22 to Consolidated Financial Statements included in Item 8 of this Report and is incorporated herein by reference.
EMPLOYEES
At September 30, 2015, UGI and its subsidiaries had nearly 13,570 employees.
ITEM 1A. RISK FACTORS
There are many factors that may affect our business and results of operations. Additional discussion regarding factors that may affect our business and operating results is included elsewhere in this Report.
Decreases in the demand for our energy products and services because of warmer-than-normal heating season weather or unfavorable weather may adversely affect our results of operations.
Because many of our customers rely on our energy products and services to heat their homes and businesses, our results of operations are adversely affected by warmer-than-normal heating season weather. Weather conditions have a significant impact on the demand for our energy products and services for both heating and agricultural purposes. Accordingly, the volume of our energy products sold is at its highest during the peak heating season of October through March and is directly affected by the severity of the winter weather. For example, historically, approximately 60% to 70% of AmeriGas Partners’ annual retail propane volume and UGI France’s annual retail LPG volume, and 60% to 70% of Gas Utility’s natural gas throughput (the total volume of gas sold to or transported for customers within our distribution system) has been sold during these months. There can be no assurance that normal winter weather in our market areas will occur in the future.
Our holding company structure could limit our ability to pay dividends or debt service.
We are a holding company whose material assets are the stock of our subsidiaries. Our ability to pay dividends on our common stock and to pay principal and accrued interest on our debt, if any, depends on the payment of dividends to us by our principal subsidiaries, AmeriGas, Inc., UGI Utilities, Inc. and UGI Enterprises, Inc. (including UGI France). Payments to us by those subsidiaries, in turn, depend upon their consolidated results of operations and cash flows. The operations of our subsidiaries are affected by conditions beyond our control, including weather, competition in national and international markets we serve, the costs and availability of propane, butane, natural gas, electricity, and other energy sources and capital market conditions. The ability of our subsidiaries to make payments to us is also affected by the level of indebtedness of our subsidiaries, which is substantial, and the restrictions on payments to us imposed under the terms of such indebtedness.
Our profitability is subject to LPG pricing and inventory risk.
The retail LPG business is a “margin-based” business in which gross profits are dependent upon the excess of the sales price over the LPG supply costs. LPG is a commodity, and, as such, its unit price is subject to volatile fluctuations in response to changes in supply or other market conditions. We have no control over these market conditions. Consequently, the unit price of the LPG that our subsidiaries and other marketers purchase can change rapidly over a short period of time. Most of our domestic LPG product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major U.S. storage points such as Mont Belvieu, Texas or Conway, Kansas. Most of our international LPG supply contracts are based on internationally quoted market prices. Because our subsidiaries’ profitability is sensitive to changes in wholesale propane supply
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costs, it will be adversely affected if we cannot pass on increases in the cost of propane to our customers. Due to competitive pricing in the industry, our subsidiaries may not fully be able to pass on product cost increases to our customers when product costs rise, or when our competitors do not raise their product prices in a timely manner. Finally, market volatility may cause our subsidiaries to sell LPG at less than the price at which they purchased it, which would adversely affect our operating results.
Energy efficiency and technology advances, as well as price induced customer conservation, may result in reduced demand for our energy products and services.
The trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, may reduce the demand for energy products. Prices for LPG and natural gas are subject to volatile fluctuations in response to changes in supply and other market conditions. During periods of high energy commodity costs, our prices generally increase, which may lead to customer conservation and attrition. A reduction in demand could lower our revenues and, therefore, lower our net income and adversely affect our cash flows. State and/or federal regulation may require mandatory conservation measures, which would reduce the demand for our energy products. We cannot predict the materiality of the effect of future conservation measures or the effect that any technological advances in heating, conservation, energy generation or other devices might have on our operations.
Economic recession, volatility in the stock market and the low interest rate environment may negatively impact our pension liability.
Economic recession, volatility in the stock market and the low interest rate environment have had a significant impact on our pension liability and funded status. Declines in the stock or bond market and valuation of stocks or bonds, combined with continued low interest rates, could further impact our pension liability and funded status and increase the amount of required contributions to our pension plans.
The adoption of financial reform legislation by the United States Congress and related regulations may have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.
Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Act”) in 2010, which contains comprehensive financial reform legislation. Title VII of the Act imposes regulation on the over-the-counter derivatives market and entities that participate in that market. The Act requires the Commodity Futures Trading Commission (“CFTC”), the U.S. Securities and Exchange Commission (“SEC”) and other regulators to implement the Act’s provisions. Most rules and regulations required to be issued by the CFTC under the Act have been finalized, but there are some additional rules and regulations that have yet to be adopted. It is possible that the rules and regulations under the Act may increase our cost of using derivative instruments to hedge risks associated with our business or may reduce the availability of such instruments to protect against risks we encounter. While costs imposed directly on us due to regulatory requirements for derivatives under the Act, such as reporting recordkeeping and electing the end-user exception from mandatory clearing, are relatively minor, increased costs may arise from clearing, trade execution, margin, capital, reporting, recordkeeping, compliance and business conduct requirements imposed upon our counterparties to the extent those costs are passed through to us. Position limits also may be imposed that could further limit our ability to hedge risks and may impose compliance and reporting obligations on us. To the extent new rules and regulations impose on our bank counterparties more collateral or margin for individual transactions, our available liquidity also may be adversely affected. Accordingly, our business and operating results may be adversely affected if, as a result of the Act and the rules and regulations promulgated under the Act, we are forced to reduce or modify our current use of derivatives.
Supplier defaults may have a negative effect on our operating results.
When the Company enters into fixed-price sales contracts with customers, it typically enters into fixed-price purchase contracts with suppliers. Depending on changes in the market prices of products compared to the prices secured in our contracts with suppliers of LPG, natural gas and electricity, a default of one or more of our suppliers under such contracts could cause us to purchase those commodities at higher prices, which would have a negative impact on our operating results.
We are dependent on our principal propane suppliers, which increases the risks from an interruption in supply and transportation.
During Fiscal 2015, AmeriGas Propane purchased over 88% of its propane needs from twenty suppliers. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, our earnings could be affected. Additionally, in certain areas, a single supplier may provide more than 50% of AmeriGas Propane’s propane requirements. Disruptions in supply in these areas could also have an adverse impact on our earnings. Our international businesses are similarly dependent upon their suppliers.
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For example, during Fiscal 2015, AvantiGas purchased over 90% of its propane needs from two suppliers. There is no assurance that our international businesses will be able to continue to acquire sufficient supplies of LPG to meet demand at prices or within time periods that would allow them to remain competitive. In addition, much of Flaga’s LPG is supplied by Kazakhstan and travels through Russia and the Ukraine. The imposition of sanctions on Flaga’s suppliers or a significant change in Flaga’s LPG supply route could lead to supply disruptions and higher costs, which could have an adverse impact on our earnings.
Changes in commodity market prices may have a significant negative effect on our liquidity.
Depending on the terms of our contracts with suppliers as well as our use of financial instruments to reduce volatility in the cost of propane, changes in the market price of propane can create margin payment obligations for us and expose us to an increased liquidity risk. In addition, increased demand for domestically produced propane overseas may, depending on production volumes in the U.S., result in higher domestic propane prices and expose us to additional liquidity risks.
Our operations may be adversely affected by competition from other energy sources.
Our energy products and services face competition from other energy sources, some of which are less costly for equivalent energy value. In addition, we cannot predict the effect that the development of alternative energy sources might have on our operations.
Our propane businesses compete for customers against suppliers of electricity, fuel oil and natural gas. Electricity is a major competitor of propane and, except in France, is generally more expensive than propane on a Btu equivalent basis for space heating, water heating and cooking. The convenience and efficiency of electricity makes it an attractive energy source for consumers and developers of new homes. Fuel oil is also a major competitor of propane and, although a less environmentally attractive energy source, is currently less expensive than propane. Furnaces and appliances that burn propane will not operate on fuel oil and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new equipment. Our customers generally have an incentive to switch to fuel oil only if fuel oil becomes significantly less expensive than propane. Except for certain industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is generally a significantly less expensive source of energy than propane. The gradual expansion of natural gas distribution systems in our service areas has resulted, and may continue to result, in the availability of natural gas in some areas that previously depended upon propane. As long as natural gas remains a less expensive energy source than propane, our propane business will lose customers in each region into which natural gas distribution systems are expanded. In France, the state-owned natural gas monopoly, Gaz de France, has in the past extended France’s natural gas grid. In addition, due to the prevalence of nuclear electric generation in France, the cost of electricity is generally less expensive than that of LPG, particularly when the cost to install new equipment to convert to LPG is considered.
Our natural gas businesses compete primarily with electricity and fuel oil, and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of fuel utilization equipment. There can be no assurance that our natural gas revenues will not be adversely affected by this competition.
Our potential to increase revenues may be affected by the decline of the retail propane industry and our ability to retain and grow our customer base.
The retail LPG distribution industry in the U.S. and each of the European countries in which we operate is mature and has been declining over the past several years in the U.S. and Europe, with no or modest growth in total demand foreseen in the next several years. Accordingly, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability to grow within the LPG industry is dependent on our ability to acquire other retail distributors and to achieve internal growth, which includes expansion of the domestic ACE and National Accounts programs in the U.S., as well as the success of our sales and marketing programs designed to attract and retain customers. A failure to retain and grow our customer base would have an adverse effect on our results.
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Volatility in credit and capital markets may restrict our ability to grow, increase the likelihood of defaults by our customers and counterparties and adversely affect our operating results.
The volatility in credit and capital markets may create additional risks to our businesses in the future. We are exposed to financial market risk (including refinancing risk) resulting from, among other things, changes in interest rates and conditions in the credit and capital markets. Developments in the credit markets during the past few years increase our possible exposure to the liquidity, default and credit risks of our suppliers, counterparties associated with derivative financial instruments and our customers. Although we believe that current financial market conditions, if they were to continue for the foreseeable future, will not have a significant impact on our ability to fund our existing operations, such market conditions could restrict our ability to grow through acquisitions, limit the scope of major capital projects if access to credit and capital markets is limited, or adversely affect our operating results.
Our ability to grow our businesses will be adversely affected if we are not successful in making acquisitions or integrating the acquisitions we have made.
One of our strategies is to grow through acquisitions in the U.S. and in international markets. We may choose to finance future acquisitions with debt, equity, cash or a combination of the three. We can give no assurances that we will find attractive acquisition candidates in the future, that we will be able to acquire such candidates on economically acceptable terms, that we will be able to finance acquisitions on economically acceptable terms, that any acquisitions will not be dilutive to earnings or that any additional debt incurred to finance an acquisition will not affect our ability to pay dividends.
In addition, the restructuring of the energy markets in the U.S. and internationally, including the privatization of government-owned utilities and the sale of utility-owned assets, is creating opportunities for, and competition from, well-capitalized competitors, which may affect our ability to achieve our business strategy.
To the extent we are successful in making acquisitions, such acquisitions involve a number of risks. These risks include, but are not limited to, the assumption of material liabilities, the diversion of management’s attention from the management of daily operations to the integration of operations, difficulties in the assimilation and retention of employees and difficulties in the assimilation of different cultures and practices and internal controls, as well as in the assimilation of broad and geographically dispersed personnel and operations. The failure to successfully integrate acquisitions could have an adverse effect on our business, financial condition and results of operations.
Expanding our midstream asset business by constructing new facilities subjects us to risks.
We seek to grow our midstream asset business by constructing new pipelines and gathering systems. These construction projects involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. These projects may not be completed on schedule, or at all, or at the anticipated costs. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. We may construct facilities to capture anticipated future growth in production and demand in an area in which anticipated growth and demand does not materialize. As a result, there is the risk that new and expanded facilities may not be able to attract enough customers to achieve our expected investment returns, which could have a material adverse effect on our business, financial condition and results of operations.
Our need to comply with, and respond to industry-wide changes resulting from, comprehensive, complex, and sometimes unpredictable governmental regulations, including regulatory initiatives aimed at increasing competition within our industry, may increase our costs and limit our revenue growth, which may adversely affect our operating results.
While we generally refer to our Gas Utility and Electric Utility segments as our “regulated segments,” there are many governmental regulations that have an impact on all of our businesses. Currently, we are subject to extensive and changing international, federal, state, and local safety, health, transportation, tax, and environmental laws and regulations governing the storage, distribution, and transportation of our energy products. Moreover, existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company that may affect our businesses in ways that we cannot predict.
New regulations, or a change in the interpretation of existing regulations, could result in increased expenditures. In addition, for many of our operations, we are required to obtain permits from regulatory authorities and, in some cases, such regulatory permits could subject our operations to additional regulations and standards of conduct. Failure to obtain or comply with these permits or applicable regulations and standards of conduct could result in civil and criminal fines or the cessation of the operations in violation. Governmental regulations and policies in the U.S. and Europe may provide for subsidies or incentives to customers who use alternative fuels instead of carbon fuels. These subsidies and incentives may result in reduced demand for our energy
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products and services.
We are investigating and remediating contamination at a number of present and former operating sites in the U.S., including former sites where we or our former subsidiaries operated manufactured gas plants. We have also received claims from third parties that allege that we are responsible for costs to clean up properties where we or our former subsidiaries operated a manufactured gas plant or conducted other operations. Costs we incur to remediate sites outside of Pennsylvania cannot currently be recovered in PUC rate proceedings, and insurance may not cover all or even part of these costs. Our actual costs to clean up these sites may exceed our current estimates due to factors beyond our control, such as:

• | the discovery of presently unknown conditions;

• | changes in environmental laws and regulations;

• | judicial rejection of our legal defenses to the third-party claims; or

• | the insolvency of other responsible parties at the sites at which we are involved.

Moreover, if we discover additional contaminated sites, we could be required to incur material costs, which would reduce our net income.
We also may be unable to timely respond to changes within the energy and utility sectors that may result from regulatory initiatives to further increase competition within our industry. Such regulatory initiatives may create opportunities for additional competitors to enter our markets and, as a result, we may be unable to maintain our revenues or continue to pursue our current business strategy.
Regulators may not allow timely recovery of costs for UGI Utilities and its subsidiaries in the future, which may adversely affect our results of operations.
In our Gas Utility and Electric Utility segments, our distribution operations are subject to regulation by the PUC. The PUC, among other things, approves the rates that UGI Utilities and its subsidiaries, PNG and CPG, may charge their utility customers, thus impacting the returns that UGI Utilities and its subsidiaries may earn on the assets that are dedicated to those operations. We expect that UGI Utilities and its subsidiaries will periodically file requests with the PUC to increase base rates that each company charges customers. If UGI Utilities or its applicable subsidiary is required in a rate proceeding to reduce the rates it charges its utility customers, or is unable to obtain approval for timely rate increases from the PUC, particularly when necessary to cover increased costs, UGI Utilities’ or such subsidiary’s revenue growth will be limited and earnings may decrease.
We are subject to operating and litigation risks that may not be covered by insurance.
Our business operations in the U.S. and other countries are subject to all of the operating hazards and risks normally incidental to the handling, storage and distribution of combustible products, such as LPG, propane and natural gas, and the generation of electricity. These risks could result in substantial losses due to personal injury and/or loss of life, and severe damage to and destruction of property and equipment arising from explosions and other catastrophic events, including acts of terrorism. As a result, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. There can be no assurance that our insurance will be adequate to protect us from all material expenses related to pending and future claims or that such levels of insurance will be available in the future at economical prices.
The risk of terrorism may adversely affect the economy and the price and availability of LPG, other refined fuels and natural gas.
Terrorist attacks and political unrest may adversely impact the price and availability of LPG (including propane), other refined fuels, and natural gas, as well as our results of operations, our ability to raise capital, and our future growth. The impact that the foregoing may have on our industries in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil or natural gas supplies and markets (the sources of LPG), cause price volatility in the cost of propane, fuel oil, and natural gas, and our infrastructure facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to transport LPG and other refined fuels if our means of supply transportation, such as rail or pipeline, become damaged as a result of an attack. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. We have opted to purchase insurance coverage for terrorist acts within our property and casualty insurance programs, but we can give no assurance that our insurance coverage will be adequate to fully compensate us for any losses to our business or property resulting from terrorist acts.
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If we are unable to protect our information technology systems against service interruption, misappropriation of data, or breaches of security resulting from cyber security attacks or other events, or we encounter other unforeseen difficulties in the operation of our information technology systems, our operations could be disrupted, our business and reputation may suffer, and our internal controls could be adversely affected.
In the ordinary course of business, we rely on information technology systems, including the Internet and third-party hosted services, to support a variety of business processes and activities and to store sensitive data, including (i) intellectual property, (ii) our proprietary business information and that of our suppliers and business partners, (iii) personally identifiable information of our customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. In addition, we rely on our information technology systems to process financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal, and tax requirements. Despite our security measures, our information technology systems may be vulnerable to attacks by hackers or breached due to employee error, malfeasance, sabotage, or other disruptions. A loss of our information technology systems, or temporary interruptions in the operation of our information technology systems, misappropriation of data, and breaches of security could have a material adverse effect on our business, financial condition, results of operations, and reputation. In addition, a cyber security attack could provide a cyber intruder with the ability to control or alter our pipeline operations. Such an act could result in critical pipeline failures.
Moreover, the efficient execution of the Company’s businesses is dependent upon the proper functioning of its internal systems, such as the information technology system that supports the Partnership’s Order-to-Cash business processes. Any significant failure or malfunction of such information technology systems may result in disruptions of our operations. In addition, the effectiveness of our internal controls could be adversely affected if we encounter unforeseen problems with respect to the operation of our information technology systems.
Our operations, capital expenditures and financial results may be affected by regulatory changes and/or market responses to global climate change.
There continues to be concern, both nationally and internationally, about climate change and the contribution of GHG emissions, most notably carbon dioxide, to global warming. Increased regulation of GHG emissions, including in the transportation sector, could impose significant additional costs on us, our suppliers and our customers. In addition to carbon dioxide, greenhouse gases include, among others, methane, a component of natural gas. Some states have adopted laws and regulations regulating the emission of GHGs for some industry sectors. For example, the California Environmental Protection Agency established a Cap & Trade program that requires certain covered entities, including propane companies, to purchase allowances to compensate for the GHG emissions created by their business operations. However, there is currently no federal or regional legislation mandating the reduction of GHG emissions in the U.S. Although Congress has not enacted federal climate change legislation, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs from motor vehicles and certain large stationary sources, and to require reporting of GHG emissions by certain regulated facilities on an annual basis. For the most part, our facilities are not currently subject to these regulations, but the potential increased costs of regulatory compliance and mandatory reporting by our customers and suppliers could have an effect on our operations or financial condition. The adoption of additional federal or state climate change legislation or regulatory programs to reduce emissions of GHGs could require us or our suppliers to incur increased capital and operating costs, with resulting impact on product price and demand. In September 2009, the EPA issued a final rule establishing a system for mandatory reporting of GHG emissions. In November 2010, the EPA expanded the reach of its GHG reporting requirements to include the petroleum and natural gas industries. Petroleum and natural gas facilities subject to the rule, which include facilities of our natural gas distribution business, were required to begin emissions monitoring in January 2011 and to submit detailed annual reports beginning in March 2012. The rule does not require affected facilities to implement GHG emission controls or reductions. However, in August 2015, the EPA finalized the Clean Power Plan rule, which provides standards and guidelines for reducing existing power plants’ GHG emissions and related pollutants by 2030. Under the Clean Power Plan’s standards and guidelines, existing power plants will be required to reduce emissions through a rate-based or a mass-based approach; states will begin submitting their reduction plans to the EPA in September 2016. The impact of new legislation and regulations will depend on a number of factors, including (i) which industry sectors would be impacted, (ii) the timing of required compliance, (iii) the overall GHG emissions cap level, (iv) the allocation of emission allowances to specific sources, and (v) the costs and opportunities associated with compliance. At this time, we cannot predict the effect that climate change regulation may have on our business, financial condition or operations in the future.
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Our international operations could be subject to increased risks, which may negatively affect our business results.
We currently operate LPG distribution businesses in Europe and China through our subsidiaries and we continue to explore the expansion of our international businesses. As a result, we face risks in doing business abroad that we do not face domestically. Certain aspects inherent in transacting business internationally could negatively impact our operating results, including:

• | costs and difficulties in staffing and managing international operations;

• | tariffs and other trade barriers;

• | difficulties in enforcing contractual rights;

• | longer payment cycles;

• | local political and economic conditions, including the current financial downturn in the euro zone;

• | potentially adverse tax consequences, including restrictions on repatriating earnings and the threat of “double taxation”;

• | fluctuations in currency exchange rates, which can affect demand and increase our costs;

• | internal control and risk management practices and policies;

• | potential violations of federal regulatory requirements, including the Foreign Corrupt Practices Act of 1977, as amended;

• | regulatory requirements and changes in regulatory requirements, including Norwegian, Swiss and EU competition laws that may adversely affect the terms of contracts with customers, including with respect to exclusive supply rights, and stricter regulations applicable to the storage and handling of LPG; and

• | new and inconsistently enforced LPG industry regulatory requirements, which can have an adverse effect on our competitive position.

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
With the exception of those matters set forth in Note 16 to Consolidated Financial Statements included in Item 8 of this Report, no material legal proceedings are pending involving the Company, any of its subsidiaries, or any of their properties, and no such proceedings are known to be contemplated by governmental authorities other than claims arising in the ordinary course of business.
ITEM 4. MINE SAFETY DISCLOSURES
None.
EXECUTIVE OFFICERS
Information regarding our executive officers is included in Part III of this Report and is incorporated in Part I by reference.
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PART II:

ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information
Our Common Stock is traded on the New York Stock Exchange under the symbol “UGI.” On July 29, 2014, the Company announced that its Board of Directors had approved a three-for-two split of its Common Stock. The additional shares were distributed September 5, 2014 to shareholders of record on August 22, 2014. Sales prices and dividends paid for all periods in Fiscal 2014 presented in the following tables are reflected on a post-split basis. The following table sets forth the high and low sales prices for the Common Stock on the New York Stock Exchange Composite Transactions tape as reported in The Wall Street Journal for each full quarterly period within the two most recent fiscal years.

2015 Fiscal Year |  | High |  | Low
4th Quarter |  | $ | 37.02 |  |  | $ | 32.80 |
3rd Quarter |  | $ | 37.85 |  |  | $ | 32.12 |
2nd Quarter |  | $ | 38.61 |  |  | $ | 31.54 |
1st Quarter |  | $ | 39.74 |  |  | $ | 33.39 |

2014 Fiscal Year |  | High |  | Low
4th Quarter |  | $ | 36.69 |  |  | $ | 31.53 |
3rd Quarter |  | $ | 33.73 |  |  | $ | 29.77 |
2nd Quarter |  | $ | 30.52 |  |  | $ | 26.83 |
1st Quarter |  | $ | 28.19 |  |  | $ | 25.25 |

Dividends
Quarterly dividends on our Common Stock were paid in Fiscal 2015 and Fiscal 2014 as follows:

2015 Fiscal Year |  | Amount
4th Quarter |  | $ | 0.2275 |
3rd Quarter |  | $ | 0.2175 |
2nd Quarter |  | $ | 0.2175 |
1st Quarter |  | $ | 0.2175 |

2014 Fiscal Year |  | Amount
4th Quarter |  | $ | 0.1967 |
3rd Quarter |  | $ | 0.1883 |
2nd Quarter |  | $ | 0.1883 |
1st Quarter |  | $ | 0.1883 |

Record Holders
On November 19, 2015, UGI had 6,370 holders of record of Common Stock.
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Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth information with respect to the Company’s repurchases of its Common Stock during the quarter ended September 30, 2015.

Period |  | (a) Total Number of Shares Purchased |  | (b) Average Price Paid per Share (or Unit) |  | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (1) |  | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1, 2015 to July 31, 2015 |  | 0 |  | 0 |  | $0 |  | 13.3 million
August 1, 2015 to August 31, 2015 |  | 45,000 |  | $34.12 |  | 45,000 |  | 13.2 million
September 1, 2015 to September 30, 2015 |  | 455,000 |  | $33.74 |  | 455,000 |  | 12.8 million
Total |  | 500,000 |  | $33.77 |  | 500,000 |  |

(1) Shares of UGI Corporation Common Stock are repurchased through a share repurchase program announced by the Company on January 30, 2014. The Board of Directors authorized the repurchase of up to 15 million shares of UGI Corporation Common Stock over a four-year period.
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ITEM 6. | SELECTED FINANCIAL DATA

|  | Year Ended September 30,
(Millions of dollars, except per share amounts) |  | 2015 |  | 2014 |  | 2013 |  | 2012 |  | 2011
FOR THE PERIOD: |  |  |  |  |  |  |  |  |  |
Income statement data: |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 6,691.1 |  |  | $ | 8,277.3 |  |  | $ | 7,194.7 |  |  | $ | 6,521.3 |  |  | $ | 6,090.9 |
Net income including noncontrolling interests |  | $ | 414.0 |  |  | $ | 532.6 |  |  | $ | 427.6 |  |  | $ | 197.7 |  |  | $ | 320.0 |
(Deduct net income) add net loss attributable to noncontrolling interests, principally in AmeriGas Partners |  | (133.0 | ) |  | (195.4 | ) |  | (149.5 | ) |  | 12.5 |  |  | (74.6 | )
Net income attributable to UGI Corporation |  | $ | 281.0 |  |  | $ | 337.2 |  |  | $ | 278.1 |  |  | $ | 210.2 |  |  | $ | 245.4 |
Earnings per common share attributable to UGI stockholders: |  |  |  |  |  |  |  |  |  |
Basic |  | $ | 1.62 |  |  | $ | 1.95 |  |  | $ | 1.63 |  |  | $ | 1.24 |  |  | $ | 1.46 |
Diluted |  | $ | 1.60 |  |  | $ | 1.92 |  |  | $ | 1.60 |  |  | $ | 1.24 |  |  | $ | 1.45 |
Cash dividends declared per common share |  | $ | 0.890 |  |  | $ | 0.791 |  |  | $ | 0.737 |  |  | $ | 0.707 |  |  | $ | 0.68 |
AT PERIOD END: |  |  |  |  |  |  |  |  |  |
Balance sheet data: |  |  |  |  |  |  |  |  |  |
Total assets |  | $ | 10,546.6 |  |  | $ | 10,093.0 |  |  | $ | 10,008.8 |  |  | $ | 9,676.9 |  |  | $ | 6,660.9 |
Capitalization: |  |  |  |  |  |  |  |  |  |
Debt: |  |  |  |  |  |  |  |  |  |
Short-term debt: |  |  |  |  |  |  |  |  |  |
AmeriGas Propane |  | $ | 68.1 |  |  | $ | 109.0 |  |  | $ | 116.9 |  |  | $ | 49.9 |  |  | $ | 95.5 |
UGI International |  | 0.6 |  |  | 8.0 |  |  | 6.5 |  |  | 21.0 |  |  | 18.9 |
UGI Utilities |  | 71.7 |  |  | 86.3 |  |  | 17.5 |  |  | 9.2 |  |  | — |
Energy Services |  | 49.5 |  |  | 7.5 |  |  | 87.0 |  |  | 85.0 |  |  | 24.3 |
Long-term debt (including current maturities): |  |  |  |  |  |  |  |  |  |
AmeriGas Propane |  | 2,283.5 |  |  | 2,291.7 |  |  | 2,300.1 |  |  | 2,328.0 |  |  | 933.5 |
UGI International |  | 782.8 |  |  | 565.0 |  |  | 654.4 |  |  | 573.9 |  |  | 571.3 |
UGI Utilities |  | 622.0 |  |  | 642.0 |  |  | 642.0 |  |  | 600.0 |  |  | 640.0 |
Other |  | 11.5 |  |  | 12.1 |  |  | 12.9 |  |  | 12.4 |  |  | 12.9 |
Total debt |  | 3,889.7 |  |  | 3,721.6 |  |  | 3,837.3 |  |  | 3,679.4 |  |  | 2,296.4 |
UGI Corporation stockholders’ equity |  | 2,692.0 |  |  | 2,659.1 |  |  | 2,492.5 |  |  | 2,229.8 |  |  | 1,973.5 |
Noncontrolling interests, principally in AmeriGas Partners |  | 880.4 |  |  | 1,004.1 |  |  | 1,055.4 |  |  | 1,085.6 |  |  | 213.0 |
Total capitalization |  | $ | 7,462.1 |  |  | $ | 7,384.8 |  |  | $ | 7,385.2 |  |  | $ | 6,994.8 |  |  | $ | 4,482.9 |
Ratio of capitalization: |  |  |  |  |  |  |  |  |  |
Total debt |  | 52.1 | % |  | 50.4 | % |  | 52.0 | % |  | 52.6 | % |  | 51.2 | %
UGI Corporation stockholders’ equity |  | 36.1 | % |  | 36.0 | % |  | 33.7 | % |  | 31.9 | % |  | 44.0 | %
Noncontrolling interests, principally in AmeriGas Partners |  | 11.8 | % |  | 13.6 | % |  | 14.3 | % |  | 15.5 | % |  | 4.8 | %
|  | 100.0 | % |  | 100.0 | % |  | 100.0 | % |  | 100.0 | % |  | 100.0 | %

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|  | Year Ended September 30,
(Million of dollars, except per share amounts) |  | 2015 |  | 2014 (a) |  | 2013 (a) |  | 2012 (a) |  | 2011 (a)
NON-GAAP RECONCILIATION: |  |  |  |  |  |  |  |  |  |
Adjusted net income attributable to UGI Corporation: |  |  |  |  |  |  |  |  |  |
Net income attributable to UGI Corporation |  | $ | 281.0 |  |  | $ | 337.2 |  |  | $ | 278.1 |  |  | $ | 210.2 |  |  | $ | 245.4 |
Add (deduct): |  |  |  |  |  |  |  |  |  |
Net after-tax losses (gains) on commodity derivative instruments not associated with current-period transactions |  | 53.3 |  |  | 6.6 |  |  | (4.3 | ) |  | (8.9 | ) |  | (17.4 | )
Net after-tax acquisition and transition expenses associated with Finagaz |  | 14.9 |  |  | 4.3 |  |  | — |  |  | — |  |  | — |
Net after-tax acquisition and transition expenses associated with the retail propane businesses of Energy Transfer Partners, L.P. (“Heritage Propane”) acquired by the Partnership on January 12, 2012 |  | — |  |  | — |  |  | 4.4 |  |  | 8.8 |  |  | — |
Losses on extinguishments of debt |  | 4.6 |  |  | — |  |  | — |  |  | 2.2 |  |  | 10.4 |
Retroactive impact of change in French tax law |  | — |  |  | 5.7 |  |  | — |  |  | — |  |  | — |
Adjusted net income attributable to UGI Corporation (b) |  | $ | 353.8 |  |  | $ | 353.8 |  |  | $ | 278.2 |  |  | $ | 212.3 |  |  | $ | 238.4 |
Adjusted earnings per common share attributable to UGI stockholders (b): |  |  |  |  |  |  |  |  |  |
Basic (b) |  | $ | 2.04 |  |  | $ | 2.05 |  |  | $ | 1.63 |  |  | $ | 1.26 |  |  | $ | 1.42 |
Diluted (b) |  | $ | 2.01 |  |  | $ | 2.02 |  |  | $ | 1.61 |  |  | $ | 1.25 |  |  | $ | 1.41 |

(a) | Periods prior to Fiscal 2015 have been adjusted to conform to the Fiscal 2015 definition of adjusted net income attributable to UGI Corporation and adjusted diluted earnings per share (see (b) below).

(b) Management uses "adjusted net income attributable to UGI" and "adjusted diluted earnings per share," both of which are non-GAAP financial measures, when evaluating UGI's overall performance. Adjusted net income attributable to UGI is defined as net income attributable to UGI after excluding net after-tax gains and losses on commodity derivative instruments not associated with current-period transactions (principally comprising unrealized gains and losses on commodity derivative instruments), losses on early extinguishments of debt, Finagaz and Heritage Propane transition and acquisition expenses and the retroactive impact of a change in French tax law.
Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide meaningful information to investors about UGI’s performance because they eliminate the impact of gains and losses on commodity derivative instruments not associated with current-period transactions and other discrete items that can affect the comparison of period-over-period results.
For further discussion of these non-GAAP financial measures, see the Executive Overview in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) discusses our results of operations and our financial condition. MD&A should be read in conjunction with our Items 1 & 2, “Business and Properties,” our Item 1A, “Risk Factors,” and our Consolidated Financial Statements in Item 8 below including “Segment Information” included in Note 22 to Consolidated Financial Statements.
Executive Overview
Fiscal 2015 was a year of significant strategic, operational and financial achievements for UGI, building on the strong foundation that we have established over the past decade. On May 29, 2015, UGI, through its wholly owned, indirect subsidiary, France SAS, completed the acquisition of all of the outstanding shares of Totalgaz, a retail distributor of LPG in France (the “Totalgaz Acquisition”). The Totalgaz Acquisition nearly doubles UGI’s retail LPG distribution business in France and is consistent with our growth strategies, one of which is to grow our core businesses through acquisitions. We expect the operations of Totalgaz (hereinafter referred to as Finagaz) will be accretive to UGI earnings beginning in Fiscal 2016 and in the years beyond Fiscal 2016 as we deliver the benefits of synergies with our existing Antargaz LPG business in France. In addition to the Totalgaz Acquisition, we expanded our presence in Europe by acquiring Total’s LPG distribution business in Hungary in August 2015.We also continued to invest in our Midstream & Marketing assets in Pennsylvania to address the current infrastructure gap that exists in bringing Marcellus Shale gas to markets in the Northeast and Mid-Atlantic regions. In Fiscal 2015, our Gas Utility continued to benefit from new customers converting to natural gas from other energy sources and continues to invest heavily in infrastructure replacement and upgrade projects. AmeriGas Propane continued to experience growth in its cylinder exchange program and National Accounts volumes and is executing on programs to gain new customers and retain existing customers in its core business. During Fiscal 2015, AmeriGas Propane completed nine small-scale acquisitions and is focused on a number of technology initiatives to benefit customer relations and increase operational efficiencies.
During Fiscal 2015, our businesses experienced the effects of two major macroeconomic events. First, during the first quarter of Fiscal 2015, worldwide energy commodity prices declined significantly. The lower commodity prices continued through most of Fiscal 2015. The decreases in energy prices were particularly evident in the prices our UGI International and AmeriGas Propane businesses pay for LPG. Second, the euro was significantly weaker versus the U.S. dollar in Fiscal 2015. The average unweighted euro-to-U.S. dollar translation rate was approximately $1.15 in Fiscal 2015 compared to a euro-to-U.S. dollar translation rate of approximately $1.36 in Fiscal 2014. The effects of these two macroeconomic conditions on our businesses are further described in our results of operations analysis below.
Earnings in Fiscal 2015 remained very strong as heating-season temperatures in the Northeast and Mid-Atlantic regions were colder than normal, although slightly warmer and less volatile than in Fiscal 2014. Our Midstream & Marketing business was once again able to take advantage of continued strong demand for natural gas in the Northeast and Mid-Atlantic regions of the U.S., and our integrated portfolio of assets in the Marcellus Shale in Pennsylvania allowed us to benefit from natural gas price volatility that occurred during the Fiscal 2015 heating season. For the second consecutive year, the colder weather, along with locational basis differences between Marcellus and non-Marcellus delivery points, resulted in sustained higher prices for pipeline capacity. Although Fiscal 2015 volatility in natural gas and pipeline capacity prices was less extreme than Fiscal 2014’s record prices, which were influenced by volatile winter weather conditions, such locational basis differences were longer in duration. The cold Fiscal 2015 winter weather also benefited our Gas Utility results. Gas Utility weather was nearly 6% colder than normal but approximately 3.7% warmer than last year. Gas Utility core market throughput increased slightly, notwithstanding the slightly warmer year-over-year temperatures, reflecting growth in the number of core market customers due in large part from customers converting to natural gas from oil. Although the Fiscal 2015 winter weather was colder than normal in the Northeast and Mid-Atlantic regions of the United States, weather in the Western United States was significantly warmer than normal, which negatively impacted AmeriGas Propane’s overall retail volumes.
At our UGI International businesses, Fiscal 2015 weather was significantly warmer than normal but slightly colder than in Fiscal 2014. The previously mentioned significant decrease in LPG commodity costs during Fiscal 2015 resulted in higher average retail LPG unit margins in most of our European markets. UGI International results in Fiscal 2015 include the operations of Finagaz in France for the period subsequent to its acquisition on May 29, 2015. Due to the seasonality of Finagaz’ operations favoring the winter heating season, the timing of the Totalgaz Acquisition (excluding the impacts of transition and acquisition expenses) did not have a material impact on net income attributable to UGI Corporation. Fiscal 2015 UGI International net income includes after-tax acquisition and transition expenses associated with Finagaz of $14.9 million, a $4.6 million after-tax loss on an early extinguishment of debt at Antargaz, and a $1.4 million net loss from Finagaz operations subsequent to its acquisition. Although the euro, and to a lesser extent the British pound sterling, were significantly weaker versus the U.S. dollar during Fiscal 2015
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which reduced UGI International net income, the effects of these weaker currencies on UGI International net income were offset, in large part, by gains on foreign currency exchange contracts.
As further described below under the caption, “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share,” UGI management uses “adjusted net income attributable to UGI” and “adjusted diluted earnings per share,” both of which are non-GAAP financial measures, when evaluating UGI’s overall performance. Adjusted net income attributable to UGI excludes (1) net after-tax gains and losses on commodity derivative instruments not associated with current-period transactions and (2) other significant discrete items that management believes affect the comparison of period-over-period results (as such items are further described below). Volatility in net income attributable to UGI as determined in accordance with accounting principles generally accepted in the U.S. (“GAAP”) can occur as a result of gains and losses on commodity derivative instruments not associated with current-period transactions. These gains and losses result principally from recording changes in unrealized gains and losses on unsettled commodity derivative instruments and, to a much lesser extent, certain realized gains and losses on settled commodity derivative instruments that are not associated with current-period transactions.
Fiscal 2015 Results
We recorded GAAP net income attributable to UGI Corporation for Fiscal 2015 of $281.0 million, equal to $1.60 per diluted share, compared to GAAP net income attributable to UGI Corporation for Fiscal 2014 of $337.2 million, equal to $1.92 per diluted share. The $56.2 million decrease in GAAP net income attributable to UGI includes after-tax losses on commodity derivative instruments not associated with current-period transactions in Fiscal 2015 of $53.3 million (equal to $0.30 per diluted share) compared to after-tax losses in Fiscal 2014 of $6.6 million (equal to $0.04 per diluted share). The $53.3 million of after-tax losses on commodity derivative instruments not associated with current-period transactions recorded in Fiscal 2015 reflect the effects of substantial declines in worldwide energy commodity prices. Although our GAAP net income was affected by these after-tax losses on commodity derivative contracts not associated with current-period transactions, because these contracts economically hedge future anticipated purchases of energy commodities we expect that such losses on these contracts will be largely offset by lower costs of commodity purchases when such derivative contracts are settled and the associated energy commodity is purchased or sold. GAAP net income attributable to UGI in Fiscal 2014 also reflects the retroactive effect to Fiscal 2013 of a change in tax laws in France, which increased Fiscal 2014 tax expense, and reduced Fiscal 2014 GAAP net income attributable to UGI, by $5.7 million or $0.03 per diluted share.
Adjusted net income attributable to UGI was $353.8 million (equal to $2.01 per diluted share) in Fiscal 2015 compared to $353.8 million (equal to $2.02 per diluted share) in Fiscal 2014. Fiscal 2015 changes in net income by business unit compared to Fiscal 2014 reflect (1) a $13.9 million increase in adjusted net income at UGI International (after excluding the after-tax effects of $14.9 million and $4.3 million of Finagaz acquisition and transition expenses in Fiscal 2015 and Fiscal 2014, respectively; a $4.6 million after-tax loss on extinguishment of debt at Antargaz in Fiscal 2015; and a $5.7 million income tax expense associated with the retroactive change in French tax law in Fiscal 2014); (2) an $8.9 million decrease in adjusted net income from Midstream & Marketing; (3) a $3.0 million decrease in net income from our Gas Utility; and (4) a $2.0 million decrease in adjusted net income attributable to UGI from AmeriGas Propane. UGI International average temperatures during Fiscal 2015 were significantly warmer than normal but slightly colder than in Fiscal 2014. UGI International unit margins in Fiscal 2015 benefited from lower LPG supply costs. The decrease in adjusted Midstream & Marketing results principally reflects slightly lower total margin and higher operating and depreciation expenses due in part to the expansion of our midstream assets. The lower AmeriGas Propane results principally reflect the effects on volumes sold of weather that was warmer than normal and warmer than in Fiscal 2014. Gas Utility results in Fiscal 2015 were slightly lower than the prior year, notwithstanding a slight increase in total margin, reflecting higher operating and administrative expenses.
Although the euro, and to a lesser the British pound sterling, were significantly weaker during Fiscal 2015, the effects of these weaker currencies on UGI International net income were offset in large part by gains on foreign currency exchange contracts.
We believe each of our business units has sufficient liquidity in the forms of revolving credit facilities and, with respect to Energy Services, an accounts receivable securitization facility, to fund business operations during Fiscal 2016. UGI Utilities has $247.0 million of long-term debt maturing in Fiscal 2016 and Flaga refinanced its €26.7 million of long-term debt due in late Fiscal 2016 in October 2015 (see “Financial Condition and Liquidity” below). UGI Utilities intends to refinance its maturing debt on a long-term basis.
Looking ahead, our results in Fiscal 2016 will be influenced by a number of factors including heating-season weather, the level and volatility of commodity prices for natural gas, LPG, electricity and oil, and economic conditions in the U.S. and Europe. We have made substantial progress on growth initiatives that will fuel earnings growth in the future. We expect that our Midstream & Marketing businesses will continue to benefit from the growing demand for natural gas in the Northeast and Mid-Atlantic
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regions and the current infrastructure gap that exists in bringing Marcellus Shale gas to markets in these regions. In addition, we expect to see the beneficial earnings impact from investments that are already in progress or recently completed, including projects to address the Marcellus Shale infrastructure gap. Acquisition activity in Europe over the last several years makes us an attractive supply partner and creates new business opportunities and our acquisition of Finagaz in France strengthens our position in Europe. At Gas Utility, we expect to continue to experience growth from conversions from oil as a result of sustained low natural gas prices and it is likely that UGI Gas will file a base rate case in Fiscal 2016, its first such filing in over twenty years. To the extent normal weather patterns return in our European LPG operations, we expect to reap the benefits from our acquisition activity in this region.
Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share
As previously mentioned, UGI management uses “adjusted net income attributable to UGI” and “adjusted diluted earnings per share,” both of which are non-GAAP financial measures, when evaluating UGI’s overall performance. Adjusted net income attributable to UGI is net income attributable to UGI after excluding net after-tax gains and losses on commodity derivative instruments not associated with current-period transactions (principally comprising changes in unrealized gains and losses on commodity derivative instruments), losses on extinguishments of debt, Finagaz and, in Fiscal 2013, Heritage Propane transition and acquisition expenses and, in Fiscal 2014, the retroactive impact of a change in French tax law. For further information on the Company’s accounting for commodity derivative instruments, see Note 2 to Consolidated Financial Statements.
Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide meaningful information to investors about UGI’s performance because they eliminate the impact of gains and losses on commodity derivative instruments not associated with current-period transactions and other discrete items that can affect the comparison of period-over-period results.
The following table reconciles net income attributable to UGI Corporation, the most directly comparable GAAP measure, to adjusted net income attributable to UGI Corporation, and reconciles diluted earnings per share, the most comparable GAAP measure, to adjusted diluted earnings per share, to reflect the adjustments referred to above:

(Millions of dollars, except per share amounts) |  | 2015 |  | 2014 (a) |  | 2013 (a)
Adjusted net income attributable to UGI Corporation: |  |  |  |  |  |
Net income attributable to UGI Corporation |  | $ | 281.0 |  |  | $ | 337.2 |  |  | $ | 278.1 |
Add (deduct): |  |  |  |  |  |
Net after-tax losses (gains) on commodity derivative instruments not associated with current-period transactions |  | 53.3 |  |  | 6.6 |  |  | (4.3 | )
Net after-tax acquisition and transition expenses associated with Finagaz |  | 14.9 |  |  | 4.3 |  |  | — |
Net after-tax transition expenses associated with Heritage Propane |  | — |  |  | — |  |  | 4.4 |
Loss on extinguishment of debt |  | 4.6 |  |  | — |  |  | — |
Retroactive impact of change in French tax law |  | — |  |  | 5.7 |  |  | — |
Adjusted net income attributable to UGI Corporation |  | $ | 353.8 |  |  | $ | 353.8 |  |  | $ | 278.2 |
Adjusted diluted earnings per share: |  |  |  |  |  |
UGI Corporation earnings per share - diluted |  | $ | 1.60 |  |  | $ | 1.92 |  |  | $ | 1.60 |
Add (deduct): |  |  |  |  |  |
Net after-tax losses (gains) on commodity derivative instruments not associated with current-period transactions |  | 0.30 |  |  | 0.04 |  |  | (0.02 | )
Net after-tax acquisition and transition expenses associated with Finagaz |  | 0.08 |  |  | 0.03 |  |  | — |
Net after-tax transition expenses associated with Heritage Propane |  | — |  |  | — |  |  | 0.03 |
Loss on extinguishment of debt |  | 0.03 |  |  | — |  |  | — |
Retroactive impact of change in French tax law |  | — |  |  | 0.03 |  |  | — |
Adjusted diluted earnings per share |  | $ | 2.01 |  |  | $ | 2.02 |  |  | $ | 1.61 |

(a) Fiscal 2014 and Fiscal 2013 amounts have been adjusted to conform to the Fiscal 2015 definition of adjusted net income attributable to UGI Corporation and adjusted diluted earnings per share.
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Results of Operations
The following analyses compare the Company’s results of operations for (1) Fiscal 2015 with Fiscal 2014 and (2) Fiscal 2014 with the fiscal year ended September 30, 2013 (“Fiscal 2013”).
Fiscal 2015 Compared with Fiscal 2014
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:

|  | 2015 |  | 2014 |  | Variance - Favorable (Unfavorable)
(Dollars in millions) |  | Amount |  | % of Total |  | Amount |  | % of Total |  | Amount |  | % Change
AmeriGas Propane |  | $ | 61.0 |  |  | 21.7 | % |  | $ | 63.0 |  |  | 18.7 | % |  | $ | (2.0 | ) |  | (3.2 | )%
UGI International (a) |  | 52.7 |  |  | 18.8 | % |  | 48.3 |  |  | 14.3 | % |  | 4.4 |  |  | 9.1 | %
Gas Utility |  | 115.8 |  |  | 41.2 | % |  | 118.8 |  |  | 35.2 | % |  | (3.0 | ) |  | (2.5 | )%
Midstream & Marketing |  | 108.9 |  |  | 38.8 | % |  | 117.8 |  |  | 34.9 | % |  | (8.9 | ) |  | (7.6 | )%
Corporate & Other (b) |  | (57.4 | ) |  | (20.5 | )% |  | (10.7 | ) |  | (3.1 | )% |  | (46.7 | ) |  | N.M. |
Net income attributable to UGI Corporation |  | $ | 281.0 |  |  | 100.0 | % |  | $ | 337.2 |  |  | 100.0 | % |  | $ | (56.2 | ) |  | (16.7 | )%

(a) | Fiscal 2015 includes a net after-tax loss of $4.6 million associated with an early extinguishment of debt at Antargaz and after-tax acquisition and transition expenses associated with Finagaz of $14.9 million. Fiscal 2014 includes after-tax acquisition-related expenses associated with Finagaz of $4.3 million and income tax expense of $5.7 million to reflect the retroactive effects of a change in tax laws in France.

(b) | Includes net after-tax losses on commodity derivative instruments not associated with current-period transactions of $53.3 million and $6.6 million in Fiscal 2015 and Fiscal 2014, respectively.

N.M. — Variance is not meaningful.
Fiscal 2015 Highlights

• | UGI International Fiscal 2015 net income includes a net after-tax loss of $4.6 million associated with an early extinguishment of debt at Antargaz and after-tax acquisition and integration-related costs associated with Finagaz of $14.9 million. UGI International Fiscal 2014 net income includes after-tax acquisition-related expenses associated with Finagaz of $4.3 million and income tax expense of $5.7 million to reflect the retroactive effects of a change in tax laws in France.

• | Fiscal 2015 UGI International local currency operating results (excluding acquisition and transition expenses associated with Finagaz) improved reflecting higher average unit margins resulting from a significant decline in LPG commodity prices.

• | Midstream & Marketing benefited from colder than normal Fiscal 2015 winter weather in the Northeast and Mid-Atlantic regions of the United States, which resulted in continued high demand for natural gas and continued high prices for pipeline capacity.

• | Notwithstanding Fiscal 2015 weather that was warmer than Fiscal 2014, Gas Utility core market throughput was slightly higher reflecting recent growth in the number of core market customers. Slightly higher Gas Utility total margin was more than offset by higher operating, administrative and depreciation expenses.

• | AmeriGas Propane retail volumes were lower in Fiscal 2015 reflecting, in large part, significantly warmer than normal weather in the western U.S.

• | The average euro-to-U.S. dollar exchange rate was $1.15 in Fiscal 2015 compared to $1.36 in Fiscal 2014. The effects of the weaker euro, and to a lesser extent the British pound sterling, on UGI International net income was offset, in large part, by gains on foreign currency exchange contracts.

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AmeriGas Propane |  | 2015 |  | 2014 |  | Decrease
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 2,885.3 |  |  | $ | 3,712.9 |  |  | $ | (827.6 | ) |  | (22.3 | )%
Total margin (a) |  | $ | 1,545.3 |  |  | $ | 1,605.8 |  |  | $ | (60.5 | ) |  | (3.8 | )%
Operating and administrative expenses |  | $ | 954.1 |  |  | $ | 964.1 |  |  | $ | (10.0 | ) |  | (1.0 | )%
Partnership Adjusted EBITDA (b) |  | $ | 619.2 |  |  | $ | 664.8 |  |  | $ | (45.6 | ) |  | (6.9 | )%
Operating income |  | $ | 427.6 |  |  | $ | 472.0 |  |  | $ | (44.4 | ) |  | (9.4 | )%
Retail gallons sold (millions) |  | 1,184.3 |  |  | 1,275.6 |  |  | (91.3 | ) |  | (7.2 | )%
Degree days – % (warmer) colder than normal (c) |  | (5.8 | )% |  | 3.4 | % |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2015 and Fiscal 2014 excludes net pre-tax losses of $47.8 million and $9.5 million, respectively, on AmeriGas Propane commodity derivative instruments not associated with current-period transactions.

(b) | Partnership Adjusted EBITDA should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 22 to Consolidated Financial Statements).

(c) | Deviation from average heating degree days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska.

AmeriGas Propane’s retail gallons sold during Fiscal 2015 decreased 7.2% compared with the prior year. The decline in retail gallons sold in Fiscal 2015 principally reflects average temperatures based upon heating degree days that were 5.8% warmer than normal and 8.9% warmer than in Fiscal 2014 principally reflecting significantly warmer than normal weather in the western U.S.
Retail propane revenues decreased $ 736.9 million during Fiscal 2015 reflecting lower average retail selling prices ($500.2 million), principally the result of the lower propane product costs, and the effects of lower retail volumes sold ($236.7 million). Wholesale propane revenues decreased $91.5 million during Fiscal 2015 reflecting the effects of lower wholesale volumes sold ($55.6 million) and lower wholesale selling prices ($35.9 million). Average daily wholesale propane commodity prices during Fiscal 2015 at Mont Belvieu, Texas were more than 50% lower than such prices during Fiscal 2014. Revenues from fee income and other ancillary sales and services in Fiscal 2015 were slightly higher than in Fiscal 2014. Total cost of sales decreased $767.1 million principally reflecting a decline in propane cost of sales. Total propane cost of sales during Fiscal 2015 decreased $771.8 million principally reflecting the effects of the significantly lower average propane product costs ($582.4 million) and the effects of the lower retail and wholesale volumes sold ($189.4 million) on propane cost of sales.
Total margin decreased $60.5 million in Fiscal 2015 principally reflecting lower retail propane total margin ($53.8 million) and, to a much lesser extent, lower margin from wholesale sales and ancillary sales and services. The decrease in retail propane total margin largely reflects the previously mentioned decline in retail gallons sold partially offset by higher average propane retail unit margins.
Partnership Adjusted EBITDA in Fiscal 2015 decreased $45.6 million principally reflecting the lower total margin ($60.5 million) offset in part by lower operating and administrative expenses and higher other operating income ($3.9 million) resulting, in large part, from sales of excess assets. The decrease in operating and administrative expenses reflects, among other things, lower vehicle expenses ($18.3 million), principally reflecting lower vehicle fuel expenses, and lower uncollectible accounts expense ($10.6 million) partially offset by, among other things, higher insured and self-insured casualty and liability expenses. AmeriGas Propane operating income decreased $44.4 million principally reflecting the lower Partnership Adjusted EBITDA ($45.6 million) partially offset by lower depreciation expense.
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UGI International |  | 2015 |  | 2014 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 1,808.5 |  |  | $ | 2,322.4 |  |  | $ | (513.9 | ) |  | (22.1 | )%
Total margin (a) |  | $ | 688.5 |  |  | $ | 664.4 |  |  | $ | 24.1 |  |  | 3.6 | %
Operating and administrative expenses (b) |  | $ | 493.7 |  |  | $ | 470.2 |  |  | $ | 23.5 |  |  | 5.0 | %
Operating income |  | $ | 112.8 |  |  | $ | 117.5 |  |  | $ | (4.7 | ) |  | (4.0 | )%
Income before income taxes (c) |  | $ | 76.4 |  |  | $ | 87.4 |  |  | $ | (11.0 | ) |  | (12.6 | )%
Retail gallons sold (millions) (d) |  | 697.0 |  |  | 631.1 |  |  | 65.9 |  |  | 10.4 | %
UGI France degree days – % (warmer) than normal (e) |  | (11.0 | )% |  | (14.1 | )% |  | — |  |  | — |
Flaga degree days – % (warmer) than normal (e) |  | (12.6 | )% |  | (15.7 | )% |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2015 excludes net pre-tax losses of $28.4 million on UGI International’s commodity derivative instruments not associated with current-period transactions.

(b) | Includes Finagaz transition and acquisition-related expenses in Fiscal 2015 and Fiscal 2014 of $22.6 million and $6.5 million, respectively.

(c) | Fiscal 2015 income before income taxes is net of $10.3 million of incremental interest expense associated with an early extinguishment of debt at Antargaz.

(d) | Excludes retail gallons from operations in China.

(e) | Deviation from average heating degree days for the 30-year period 1981-2010 at locations in our UGI France and Flaga service territories.

UGI International results include the results of Finagaz subsequent to its acquisition on May 29, 2015. Based upon heating degree day data, temperatures during Fiscal 2015 in our UGI International European LPG territories were significantly warmer than normal but slightly colder than in Fiscal 2014. Total retail gallons sold during Fiscal 2015 were higher than Fiscal 2014 reflecting in large part incremental retail gallons from Finagaz for the period subsequent to its acquisition. During Fiscal 2015, average wholesale commodity prices for propane and butane in northwest Europe were more than 40% lower than in Fiscal 2014.
UGI International local currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting periods. The functional currency of a significant portion of our UGI International results is the euro. During Fiscal 2015 and Fiscal 2014, the average un-weighted euro-to-U.S. dollar translation rates were approximately $1.15 and $1.36, respectively. The significantly lower euro-to-U.S. dollar translation rates and, to a lesser extent, the lower British pound sterling-to-U.S. dollar translation rates, reduced UGI International net income but this decrease was offset, in large part, by gains from foreign currency exchange contracts during Fiscal 2015.
UGI International revenues decreased $513.9 million during Fiscal 2015 principally reflecting the combined impact on revenues of the significantly weaker euro and, to a lesser extent, the British pound sterling ($298.2 million) and the effects of lower average LPG sales prices at each of our European LPG businesses. The lower average LPG sales prices reflect the previously mentioned significant decline in commodity LPG prices. These decreases in revenues were partially offset by the effects on revenues from the higher retail LPG volumes sold and higher revenues from increased natural gas marketing volumes at UGI France. UGI International cost of sales decreased $538.0 million during Fiscal 2015 principally reflecting the lower average LPG wholesale prices during Fiscal 2015 and the effects of the significantly weaker euro and, to a lesser extent, the British pound sterling ($177.2 million) partially offset by the effects on cost of sales from the higher UGI International retail LPG volumes sold and increased natural gas marketing volumes at UGI France.
UGI International total margin increased $24.1 million in Fiscal 2015 as incremental margin from Finagaz for the period subsequent to its acquisition on May 29, 2015, and slightly higher local currency total margin at AvantiGas and UGI France’s legacy operations, was offset in large part by the translation effects on local currency total margin of the significantly weaker euro and, to a lesser extent, the British pound sterling. U.S. dollar-denominated total margin at UGI France increased $46.7 million principally reflecting incremental margin from Finagaz ($78.0 million) partially offset by the effects of the weaker euro on UGI France’s legacy operations gross margin. Total U.S. dollar-denominated margin from AvantiGas increased $4.4 million from higher local currency margin while total U.S. dollar-denominated margin from Flaga declined principally reflecting the impact of the weaker euro in Fiscal 2015 and slightly lower average retail unit margins. Local currency average retail unit margins were higher at UGI France and AvantiGas principally reflecting the effects of the lower LPG commodity prices. Local currency retail unit margins at Flaga were slightly lower reflecting in part the negative effects from the time lag of supply in certain of Flaga’s eastern European service
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territories caused by rapidly falling LPG prices early in Fiscal 2015, and the effects of the rapidly falling euro on U.S. dollar-denominated supply hedges.
The $4.7 million decrease in UGI International operating income reflects the $24.1 million increase in total margin offset by a $23.5 million increase in operating and administrative expenses and a $5.3 million increase in depreciation and amortization expense. The increase in these expenses principally reflects incremental Finagaz operating, administrative and depreciation expenses subsequent to its acquisition on May 29, 2015, and $22.6 million of Finagaz acquisition and transition expenses compared with $6.5 million of Finagaz acquisition-related expenses in Fiscal 2014. The effects of these increases in operating, administrative and depreciation expenses associated with Finagaz were partially offset by the translation effects of the weaker euro and British pound sterling on such expenses of our legacy European LPG operations.
UGI International income before income taxes decreased $11.0 million principally reflecting the $4.7 million decrease in operating income and a $5.2 million increase in interest expense. In May 2015, France SAS borrowed €600 million under its Senior Facilities Agreement with a consortium of banks (the “2015 Senior Facilities Agreement”), the proceeds of which were used to prepay €342 million principal amount, plus accrued interest, outstanding under Antargaz’ 2011 Senior Facilities Agreement due March 2016 (the “2011 Senior Facilities Agreement”) and to fund a portion of the cash purchase price of Finagaz. UGI International interest expense in Fiscal 2015 includes a $10.3 million pre-tax loss resulting from early extinguishments of term loan debt under the 2011 Senior Facilities Agreement. Excluding the effects of this pre-tax loss of $10.3 million, UGI International interest expense declined $5.1 million as incremental interest expense associated with the higher principal amount outstanding under the 2015 Senior Facilities Agreement was more than offset by the translation effects of the weaker euro and a lower effective interest rate on the 2015 Senior Facilities Agreement term loan compared with the 2011 Senior Facilities Agreement term loan.

Gas Utility |  | 2015 |  | 2014 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 933.1 |  |  | $ | 977.3 |  |  | $ | (44.2 | ) |  | (4.5 | )%
Total margin (a) |  | $ | 484.5 |  |  | $ | 480.5 |  |  | $ | 4.0 |  |  | 0.8 | %
Operating and administrative expenses |  | $ | 196.9 |  |  | $ | 183.8 |  |  | $ | 13.1 |  |  | 7.1 | %
Operating income |  | $ | 226.5 |  |  | $ | 236.2 |  |  | $ | (9.7 | ) |  | (4.1 | )%
Income before income taxes |  | $ | 187.4 |  |  | $ | 199.6 |  |  | $ | (12.2 | ) |  | (6.1 | )%
System throughput – billions of cubic feet (“bcf”) - |  |  |  |  |  |  |  |
Core market |  | 81.3 |  |  | 80.4 |  |  | 0.9 |  |  | 1.1 | %
Total |  | 213.5 |  |  | 208.8 |  |  | 4.7 |  |  | 2.3 | %
Degree days – % colder than normal (b) |  | 5.9 | % |  | 10.0 | % |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales.

(b) | Deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory.

Temperatures in Gas Utility’s service territory in Fiscal 2015 based upon heating degree days were 5.9% colder than normal but 3.7% warmer than in Fiscal 2014. Total distribution system throughput increased 4.7 bcf, notwithstanding the warmer weather, principally reflecting higher large firm delivery service volumes and slightly higher core market volumes reflecting, in large part, a 1.9% year-over-year increase in the number of core market customers. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.
Gas Utility revenues decreased $44.2 million in Fiscal 2015 principally reflecting lower revenues from off-system sales ($31.8 million) and lower revenues from core market customers ($7.6 million). The decrease in core market revenues principally reflects the effects of lower average purchased gas cost (“PGC”) rates during Fiscal 2015 partially offset by the slightly higher core market throughput. Increases or decreases in retail core-market revenues and cost of sales principally result from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the 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
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core-market margin. Gas Utility’s cost of sales was $448.6 million in Fiscal 2015 compared with $496.8 million in Fiscal 2014 principally reflecting the effects of the lower off-system sales ($31.8 million) and the effects on retail core-market cost of sales of the lower average PGC rates partially offset by slightly higher core market throughput.
Fiscal 2015 Gas Utility total margin increased $4.0 million principally reflecting higher core market total margin ($4.3 million) on the higher core market sales and higher large firm delivery service total margin ($5.7 million). These increases were partially offset principally by lower margin from interruptible customers ($7.0 million).
Gas Utility operating income and income before income taxes during Fiscal 2015 decreased $9.7 million and $12.2 million, respectively. The $9.7 million decrease in Gas Utility operating income, notwithstanding the $4.0 million increase in total margin, principally reflects higher operating and administrative expenses and higher depreciation expense partially offset by an increase in other operating income. Fiscal 2015 operating and administrative expenses were higher than in Fiscal 2014 principally reflecting, among other things, higher Fiscal 2015 distribution system expenses ($4.8 million), and higher employee benefits, uncollectible accounts and other general administrative expenses. Gas Utility depreciation expense increased $4.1 million reflecting the effects of greater distribution system capital expenditures. Other operating income increased $3.4 million reflecting, among other things, incremental income from construction services. The $12.2 million decrease in Gas Utility income before income taxes reflects the lower operating income ($9.7 million) and higher long-term debt interest expense.

Midstream & Marketing |  | 2015 |  | 2014 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues (a) |  | $ | 1,104.6 |  |  | $ | 1,368.9 |  |  | $ | (264.3 | ) |  | (19.3 | )%
Total margin (b) |  | $ | 284.6 |  |  | $ | 292.2 |  |  | $ | (7.6 | ) |  | (2.6 | )%
Operating and administrative expenses |  | $ | 73.0 |  |  | $ | 70.6 |  |  | $ | 2.4 |  |  | 3.4 | %
Operating income |  | $ | 184.8 |  |  | $ | 198.6 |  |  | $ | (13.8 | ) |  | (6.9 | )%
Income before income taxes |  | $ | 182.7 |  |  | $ | 195.7 |  |  | $ | (13.0 | ) |  | (6.6 | )%

(a) | Amounts are net of intercompany revenues between Midstream & Marketing’s Energy Services and Electric Generation segments.

(b) | Total margin represents total revenues less total cost of sales. Amounts exclude net pre-tax losses on commodity derivative instruments not associated with current-period transactions of $42.9 million and $8.5 million during Fiscal 2015 and Fiscal 2014, respectively.

Midstream & Marketing Fiscal 2015 total revenues were $264.3 million lower than Fiscal 2014 principally reflecting lower natural gas ($202.0 million), retail power ($44.9 million), peaking ($12.2 million) and Electric Generation revenues partially offset by higher natural gas gathering revenues. The decrease in natural gas revenues principally reflects lower wholesale and retail natural gas prices during Fiscal 2015. The lower retail power revenues principally reflect lower sales volumes and, to a lesser extent, lower average prices. In addition, Fiscal 2015 total capacity management revenues were slightly below Fiscal 2014. Energy Services capacity management revenues continued to benefit from significant locational basis differences between Marcellus and non-Marcellus delivery points in Fiscal 2015 although not as extreme as those experienced during the volatile temperature conditions experienced in January and February 2014. Midstream & Marketing cost of sales decreased to $820.0 million in Fiscal 2015 compared to $1,076.7 million in Fiscal 2014 principally reflecting lower natural gas ($194.8 million), retail power ($52.4 million) and peaking ($7.7 million) cost of sales.
Midstream & Marketing total margin decreased $7.6 million in Fiscal 2015 principally reflecting lower natural gas marketing total margin ($7.1 million), lower peaking total margin ($4.4 million), lower capacity management total margin ($4.1 million) and slightly lower Electric Generation total margin. These declines were partially offset by higher total margin from retail power ($7.5 million) and higher natural gas gathering total margin ($3.5 million). The decline in natural gas marketing total margin principally reflects the effects of lower average unit margins. The lower peaking total margin principally reflects lower Fiscal 2015 natural gas prices. The higher retail power total margin reflects the effects of higher unit margins while the increase in natural gas gathering total margin reflects incremental margin from the expansion of our natural gas gathering system in the Marcellus shale region of northern Pennsylvania.
Midstream & Marketing operating income and income before income taxes during Fiscal 2015 decreased $13.8 million and $13.0 million, respectively, principally reflecting the previously mentioned decrease in total margin ($7.6 million), slightly higher operating and administrative costs and higher depreciation expense principally reflecting incremental depreciation associated with storage and natural gas gathering assets and higher depreciation associated with the Conemaugh generating unit.
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Interest Expense. Our consolidated interest expense during Fiscal 2015 was $241.9 million, slightly higher than the $237.7 million of interest expense in Fiscal 2014. Interest expense in Fiscal 2015 includes a $10.3 million pre-tax loss principally comprising the settlement of interest rate swaps associated with an early extinguishment of debt at Antargaz. Excluding the effects of this pre-tax loss, interest expense decreased $6.1 million principally reflecting (1) the effects of the weaker euro on UGI International local currency interest expense and (2) slightly lower interest expense at AmeriGas Propane and Midstream & Marketing. These decreases were partially offset by higher long-term debt interest at UGI Utilities.
Income Taxes. Our effective income tax rate (excluding the effects on such rate of pre-tax income associated with noncontrolling interests not subject to federal income taxes) of 38.8% in Fiscal 2015 was lower than such rate in Fiscal 2014 of 41.1%. The decrease in the effective income tax rate reflects in large part a lower effective tax rate on UGI International pre-tax income. UGI International’s effective tax rate in Fiscal 2014 was higher due, in part, to $5.7 million of income taxes associated with a change in tax laws in France that was retroactive to Fiscal 2013.
Fiscal 2014 Compared with Fiscal 2013
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:

|  | 2014 |  | 2013 |  | Variance - Favorable (Unfavorable)
(Dollars in millions) |  | Amount |  | % of Total |  | Amount |  | % of Total |  | Amount |  | % Change
AmeriGas Propane |  | $ | 63.0 |  |  | 18.7 | % |  | $ | 47.5 |  |  | 17.1 | % |  | $ | 15.5 |  |  | 32.6 | %
UGI International (a) |  | 48.3 |  |  | 14.3 | % |  | 82.7 |  |  | 29.7 | % |  | (34.4 | ) |  | (41.6 | )%
Gas Utility |  | 118.8 |  |  | 35.2 | % |  | 94.3 |  |  | 33.9 | % |  | 24.5 |  |  | 26.0 | %
Midstream & Marketing |  | 117.8 |  |  | 34.9 | % |  | 52.5 |  |  | 18.9 | % |  | 65.3 |  |  | 124.4 | %
Corporate & Other (b) |  | (10.7 | ) |  | (3.1 | )% |  | 1.1 |  |  | 0.4 | % |  | (11.8 | ) |  | N.M. |
Net income attributable to UGI Corporation |  | $ | 337.2 |  |  | 100.0 | % |  | $ | 278.1 |  |  | 100.0 | % |  | $ | 59.1 |  |  | 21.3 | %

(a) | Fiscal 2014 includes income tax expense of $5.7 million to reflect the retroactive effects of a change in tax laws in France and after-tax acquisition-related expenses associated with Finagaz of $4.3 million.

(b) | Includes net after-tax gains (losses) on Midstream & Marketing’s commodity derivative instruments not associated with current-period transactions, and net after-tax gains (losses) on AmeriGas Propane’s unsettled commodity derivative instruments entered into beginning April 1, 2014, totaling $(6.6) million in Fiscal 2014 and $4.3 million in Fiscal 2013.

N.M. — Variance is not meaningful.
Fiscal 2014 Highlights

• | Fiscal 2014 results reflect significantly colder and more volatile winter weather at Midstream & Marketing and significantly colder weather at Gas Utility and in AmeriGas Propane’s service territory east of the Rocky Mountains.

• | Midstream & Marketing’s integrated assets portfolio in the Marcellus Shale in Pennsylvania provided it with the opportunity to take advantage of periods of extreme cold winter weather that resulted in heightened natural gas price volatility due to locational basis differentials and increased the demand for winter peaking services.

• | Our UGI International operations in Europe experienced weather that was much warmer than normal which reduced retail volumes sold.

• | Fiscal 2014 results reflect the retroactive effects of a change in tax laws in France which increased UGI International tax expense and reduced Fiscal 2014 net income by $(5.7) million (equal to $(0.03) per diluted share).

• | Net income in Fiscal 2014 includes after-tax losses of $(6.6) million (equal to $(0.04) per diluted share) on commodity derivative instruments not associated with current-period transactions while net income in Fiscal 2013 includes after-tax gains of $4.3 million (equal to $0.02 per diluted share) on commodity derivative instruments not associated with current-period transactions.

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AmeriGas Propane |  | 2014 |  | 2013 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 3,712.9 |  |  | $ | 3,168.8 |  |  | $ | 544.1 |  |  | 17.2 | %
Total margin (a) |  | $ | 1,605.8 |  |  | $ | 1,511.6 |  |  | $ | 94.2 |  |  | 6.2 | %
Operating and administrative expenses |  | $ | 964.1 |  |  | $ | 945.1 |  |  | $ | 19.0 |  |  | 2.0 | %
Partnership Adjusted EBITDA (b) |  | $ | 664.8 |  |  | $ | 596.5 |  |  | $ | 68.3 |  |  | 11.5 | %
Operating income |  | $ | 472.0 |  |  | $ | 394.4 |  |  | $ | 77.6 |  |  | 19.7 | %
Retail gallons sold (millions) |  | 1,275.6 |  |  | 1,245.2 |  |  | 30.4 |  |  | 2.4 | %
Degree days – % colder (warmer) than normal (c) |  | 3.4 | % |  | (4.9 | )% |  | — |  |  | — |

(a) Total margin represents total revenues less total cost of sales. Total margin in Fiscal 2014 excludes net pre-tax losses of $9.5 million on AmeriGas Propane unsettled commodity derivative instruments entered into beginning April 1, 2014, not associated with current-period transactions.

(b) | Partnership Adjusted EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 22 to Consolidated Financial Statements). Partnership Adjusted EBITDA for Fiscal 2013 includes transition expenses of $26.5 million associated with the integration of Heritage Propane acquired in January 2012.

Deviation from average heating degree days for the 30-year period 1971-2000 based upon national weather statistics provided by NOAA for 335 airports in the United States, excluding Alaska.
The 2.4% increase in retail gallons sold in Fiscal 2014 reflects average temperatures based upon heating degree days that were 3.4% colder than normal and 8.8% colder than the prior year. The colder average weather reflects significantly colder winter weather in the eastern half of the United States partially offset by warmer weather in the western U.S. The effects of the colder winter weather on retail gallons sold, however, were muted by supply challenges in certain regions of the U.S. that experienced prolonged periods of unusually cold winter weather. In order to ensure that customers in these regions were adequately supplied during these extreme weather conditions, the Partnership instituted supply allocation measures in certain areas, which limited total retail volumes sold and increased distribution costs per gallon.
Retail propane revenues increased $529.7 million during Fiscal 2014 reflecting the effects of higher average retail selling prices ($461.9 million), largely the result of higher propane product costs, and the higher retail volumes sold ($67.8 million). Wholesale propane revenues increased $24.9 million during Fiscal 2014 reflecting the effects of higher wholesale selling prices ($33.8 million) partially offset by the effects of slightly lower wholesale volumes sold ($8.9 million). Average daily wholesale propane commodity prices during Fiscal 2014 at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 25% higher than such prices during Fiscal 2013. In addition, certain regions of the U.S. experienced an even greater increase in wholesale commodity prices due to supply constraints caused by industry-wide storage and transportation issues exacerbated by the unusually cold winter weather conditions. Partially offsetting the higher retail and wholesale revenues were slightly lower revenues from fee income and other ancillary sales and services. Total cost of sales during Fiscal 2014 increased $449.9 million principally reflecting the effects of the higher average propane product costs ($429.2 million) and, to a lesser extent, the effects of the greater retail and wholesale volumes sold ($27.1 million) partially offset by lower cost of sales from ancillary sales and services.
Total margin increased $94.2 million in Fiscal 2014 principally reflecting higher retail propane total margin ($97.4 million) partially offset by lower margin from ancillary sales and services. The increase in retail propane total margin reflects modestly higher average retail propane unit margins and, to a lesser extent, the previously mentioned increase in retail volumes sold.
Partnership Adjusted EBITDA in Fiscal 2014 increased $68.3 million principally reflecting the higher total margin ($94.2 million) partially offset by slightly higher operating and administrative expenses ($19.0 million) and lower other income. Partnership operating and administrative expenses in the prior fiscal year include $26.5 million of transition expenses associated with the integration of Heritage Propane acquired in January 2012 (see Note 4 to Consolidated Financial Statements). Excluding the effects of the Heritage Propane transition expenses in the prior year, Partnership operating and administrative expenses increased $45.5 million. The increase in operating and administrative expenses excluding the effects of the Heritage Propane transition expenses in the prior-year period reflects, among other things, higher distribution-related expenses associated with the higher retail volumes sold and higher distribution costs caused by the supply challenges in certain regions of the U.S. during the second quarter of Fiscal 2014. The increase in operating and administrative costs also reflects higher uncollectible accounts expense ($9.9 million) and
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higher casualty and general liability expenses ($6.3 million). Operating income increased $77.6 million in Fiscal 2014 principally reflecting the higher Partnership EBITDA ($68.3 million) and slightly lower depreciation expense.

UGI International |  | 2014 |  | 2013 |  | Increase (Decrease)
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 2,322.4 |  |  | $ | 2,179.2 |  |  | $ | 143.2 |  |  | 6.6 | %
Total margin (a) |  | $ | 664.4 |  |  | $ | 680.8 |  |  | $ | (16.4 | ) |  | (2.4 | )%
Operating and administrative expenses |  | $ | 470.2 |  |  | $ | 454.4 |  |  | $ | 15.8 |  |  | 3.5 | %
Operating income |  | $ | 117.5 |  |  | $ | 147.0 |  |  | $ | (29.5 | ) |  | (20.1 | )%
Income before income taxes |  | $ | 87.4 |  |  | $ | 116.2 |  |  | $ | (28.8 | ) |  | (24.8 | )%
Retail gallons sold (millions) (b) |  | 631.1 |  |  | 592.4 |  |  | 38.7 |  |  | 6.5 | %
UGI France degree days – % (warmer) colder than normal (c) |  | (14.1 | )% |  | 3.7 | % |  | — |  |  | — |
Flaga degree days – % (warmer) colder than normal (c) |  | (15.7 | )% |  | 0.9 | % |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales.

(b) | Excludes retail gallons from operations in China.

(c) | Deviation from average heating degree days for the 30-year period 1981-2010 at locations in our UGI France and Flaga service territories.

Based upon heating degree day data, temperatures during Fiscal 2014 at our UGI International European LPG territories were significantly warmer than normal compared to temperatures in Fiscal 2013 that were slightly colder than normal. Total retail gallons sold were slightly higher reflecting the effects of the significantly warmer Fiscal 2014 weather more than offset by incremental retail gallons associated with BP Poland’s former LPG business in Poland acquired by Flaga in September 2013 (“BP Poland acquisition”). During Fiscal 2014, the average wholesale commodity price for propane in northwest Europe was approximately 9% lower than in the prior-year period while the average wholesale commodity price for butane was approximately 3% lower than the prior-year period.
UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting periods. The functional currency of a significant portion of our UGI International results is the euro. During Fiscal 2014 and Fiscal 2013, the average un-weighted euro-to-dollar translation rate was approximately $1.36 and $1.31, respectively. The difference in euro to U.S. dollar translation rates and, to a lesser extent, the difference in the British pound sterling to the U.S. dollar translation rates, did not have a material impact on net income attributable to UGI.
UGI International revenues increased $143.2 million principally reflecting greater total revenues at Flaga ($178.3 million) including incremental retail and wholesale revenues resulting from the BP Poland acquisition, and, to a much lesser extent, the currency conversion effects of the slightly stronger euro and British pound sterling. This increase in revenues was partially offset by lower total revenues at UGI France ($27.1 million) and, to a lesser extent, at AvantiGas principally on lower LPG retail volumes sold partially offset by the currency conversion effects of the slightly stronger euro and British pound sterling. Cost of sales increased $159.6 million as greater cost of sales at Flaga ($172.1 million), primarily reflecting retail and wholesale gallons associated with the BP Poland acquisition and, to a lesser extent, the effects of the slightly stronger euro, were partially offset by lower cost of sales at UGI France and AvantiGas principally as a result of the lower retail LPG gallons sold partially offset by the currency conversion effects of the slightly stronger euro and British pound sterling.
Total UGI International margin decreased $16.4 million during Fiscal 2014 reflecting lower total margin at UGI France ($30.2 million) principally on the lower retail volumes partially offset by the effects of the slightly stronger euro. This decrease in margin was offset in part by slightly higher total margin at Flaga, due primarily to incremental margin associated with the BP Poland acquisition and the slightly stronger euro, and higher total margin at AvantiGas, principally the result of higher average retail unit margins and the slightly stronger British pound sterling.
UGI International operating income and income before income taxes decreased $29.5 million and $28.8 million, respectively. The decreases principally reflect the lower total margin ($16.4 million); increased operating, administrative and depreciation expenses at Flaga ($9.2 million) principally incremental expenses resulting from the BP Poland acquisition and to a lesser extent the currency conversion effects of the slightly stronger euro; and the currency conversion effects of the stronger euro and British pound sterling
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on UGI France and AvantiGas operating, administrative and depreciation expenses. Fiscal 2014 UGI International operating and administrative costs also include $6.5 million of incremental expenses associated with the proposed acquisition of Totalgaz.

Gas Utility |  | 2014 |  | 2013 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues |  | $ | 977.3 |  |  | $ | 839.0 |  |  | $ | 138.3 |  |  | 16.5 | %
Total margin (a) |  | $ | 480.5 |  |  | $ | 431.8 |  |  | $ | 48.7 |  |  | 11.3 | %
Operating and administrative expenses |  | $ | 183.8 |  |  | $ | 176.2 |  |  | $ | 7.6 |  |  | 4.3 | %
Operating income |  | $ | 236.2 |  |  | $ | 196.5 |  |  | $ | 39.7 |  |  | 20.2 | %
Income before income taxes |  | $ | 199.6 |  |  | $ | 159.1 |  |  | $ | 40.5 |  |  | 25.5 | %
System throughput – bcf |  |  |  |  |  |  |  |
Core market |  | 80.4 |  |  | 70.6 |  |  | 9.8 |  |  | 13.9 | %
Total |  | 208.8 |  |  | 192.1 |  |  | 16.7 |  |  | 8.7 | %
Degree days – % colder (warmer) than normal (b) |  | 10.0 | % |  | (0.5 | )% |  | — |  |  | — |

(a) | Total margin represents total revenues less total cost of sales.

(b) | Deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory.

Temperatures in Gas Utility’s service territory in Fiscal 2014 based upon heating degree days were 10.0% colder than normal and 10.6% colder than Fiscal 2013. Total distribution system throughput increased 16.7 bcf principally reflecting a 9.8 bcf (13.9%) increase in demand from Gas Utility’s core market customers and, to a lesser extent, greater net large firm and interruptible delivery service volumes. 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 relative to heating oil prices.
Gas Utility revenues increased $138.3 million during Fiscal 2014 principally reflecting higher revenues from core market customers ($83.6 million), higher revenues from off-system sales ($36.4 million) and, to a much lesser extent, higher revenues from large firm delivery service customers on higher throughput ($12.5 million). The increase in core market revenues principally reflects the effects of the higher core market throughput. Gas Utility’s cost of sales was $496.8 million in Fiscal 2014 compared with $407.2 million in Fiscal 2013 principally reflecting the effects of the greater retail core-market volumes sold ($50.1 million) and the effects of the higher off-system sales ($36.4 million).
Fiscal 2014 Gas Utility total margin increased $48.7 million principally reflecting higher core market total margin ($33.8 million) and greater large firm delivery service total margin ($10.8 million). The higher core market and large firm delivery service total margin reflects the effects of the previously mentioned colder weather and customer growth.
Gas Utility operating income and income before income taxes during Fiscal 2014 increased $39.7 million and $40.5 million, respectively, over Fiscal 2013. The increase in Gas Utility operating income principally reflects the $48.7 million increase in total margin partially offset by higher operating and administrative expenses. Operating and administrative expenses in Fiscal 2014 were modestly higher than the prior year principally reflecting greater Fiscal 2014 distribution system maintenance expenses ($5.3 million), higher uncollectible accounts expense ($3.0 million) and greater incentive compensation expense partially offset by lower pension expense. The increase in Gas Utility income before income taxes reflects the greater operating income ($39.7 million) and slightly lower interest expense.
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Midstream & Marketing |  | 2014 |  | 2013 |  | Increase
(Dollars in millions) |  |  |  |  |  |  |  |
Revenues (a) |  | $ | 1,368.9 |  |  | $ | 1,037.6 |  |  | $ | 331.3 |  |  | 31.9 | %
Total margin (b) |  | $ | 292.2 |  |  | $ | 164.0 |  |  | $ | 128.2 |  |  | 78.2 | %
Operating and administrative expenses |  | $ | 70.6 |  |  | $ | 57.0 |  |  | $ | 13.6 |  |  | 23.9 | %
Operating income |  | $ | 198.6 |  |  | $ | 90.0 |  |  | $ | 108.6 |  |  | 120.7 | %
Income before income taxes |  | $ | 195.7 |  |  | $ | 86.8 |  |  | $ | 108.9 |  |  | 125.5 | %

(a) | Amounts are net of intercompany revenues between Midstream & Marketing’s Energy Services and Electric Generation segments.

(b) | Total margin represents total revenues less total cost of sales. Amounts exclude net pre-tax (losses) gains on commodity derivative instruments not associated with current-period transactions of $(8.5) million and $7.4 million in Fiscal 2014 and Fiscal 2013, respectively.

Fiscal 2014 total revenues were $331.3 million higher than Fiscal 2013 principally reflecting higher natural gas revenues ($255.9 million) and, to a much lesser extent, higher capacity management ($61.6 million), peaking ($25.4 million) and natural gas gathering revenues ($12.9 million). The increase in natural gas revenues principally reflects higher wholesale and retail natural gas volumes sold and higher natural gas prices during Fiscal 2014. The greater capacity management and peaking service revenues principally reflect higher demand for natural gas pipeline capacity at significantly higher prices caused by periods of extreme cold weather in the Northeast and Mid-Atlantic regions primarily during the months of January and February 2014. Midstream & Marketing revenues were also higher due to incremental revenues from the Auburn pipeline extension which was placed in service during the first quarter of Fiscal 2014. Midstream & Marketing cost of sales increased to $1,076.7 million in Fiscal 2014 compared to $873.6 million in Fiscal 2013 principally reflecting the higher natural gas volumes and prices.
Midstream & Marketing total margin increased $128.2 million (78.2%) in Fiscal 2014 principally reflecting higher capacity management and peaking service total margin ($78.8 million), higher retail natural gas total margin ($24.5 million), higher Electric Generation total margin ($13.9 million) and increased natural gas gathering total margin ($12.9 million) primarily reflecting incremental margin from the previously mentioned Auburn pipeline extension. The significant increase in total margin from capacity management and peaking activities reflects the effects of periods of extreme cold winter weather primarily during January and February which resulted in heightened natural gas price volatility due to locational basis differentials and also increased the demand for, and the value of, winter peaking services. The greater total margin from Electric Generation principally reflects the impact of higher unit margins at the Hunlock natural gas-fired electricity generating facility due in large part to lower locally-sourced natural gas feedstock costs, greater electricity production, and higher Electric Generation capacity revenues. These increases in total margin were partially offset by lower total margin from retail power sales.
Midstream & Marketing operating income and income before income taxes during Fiscal 2014 increased $108.6 million and $108.9 million, respectively, over Fiscal 2013 reflecting the previously mentioned significant increase in total margin ($128.2 million) partially offset by higher operating and administrative expenses ($13.6 million) and depreciation expenses ($5.4 million). The higher operating, administrative and depreciation expenses include, among other things, increased operating and depreciation expenses associated with storage and natural gas gathering assets and higher incentive compensation costs. Electric Generation operating expenses in Fiscal 2014 were slightly higher primarily a result of the increased production activity at the Hunlock electricity generating facility offset, in part, by lower maintenance costs at the Conemaugh generating facility.
Interest Expense. Our consolidated interest expense during Fiscal 2014 was $237.7 million, approximately equal to the $240.3 million of interest expense recorded during Fiscal 2013.
Income Taxes. Our effective income tax rate (excluding the effects on such rate of pre-tax income associated with noncontrolling interests not subject to federal income taxes) of 41.1% in Fiscal 2014 was higher than such rate in Fiscal 2013 of 36.9%. The higher effective tax rate in Fiscal 2014 reflects, in large part, the effects of new tax legislation in France approved by the French Parliament in December 2013 and, to a lesser extent, a higher proportion of pretax earnings from higher tax rate domestic business units. The new tax legislation in France, among other things, limits UGI France’s ability to deduct certain interest expense for income tax purposes and increases the corporate surtax rate for a period of two years. Based upon our review of the new tax legislation, provisions of the new tax legislation associated with the deductibility of certain interest expense at UGI France applies retroactively to Fiscal 2013. During the quarter ended December 31, 2013, the Company recorded additional income taxes of $5.7 million to reflect the retroactive effects of the new French tax legislation associated with the deductibility of certain interest expense.
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Financial Condition and Liquidity
We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities and, in the case of Midstream & Marketing, also from an accounts receivable securitization facility. Long-term cash requirements not met by cash from operations are generally met through issuance of long-term debt or equity securities. We believe that each of our business units has sufficient liquidity in the forms of cash and cash equivalents on hand; cash expected to be generated from operations; credit facility and accounts receivable securitization facility borrowings; and the ability to obtain long-term financing to meet anticipated contractual and projected cash commitments. Issuances of debt and equity securities in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.
Our cash and cash equivalents totaled $369.7 million at September 30, 2015, compared with $419.5 million at September 30, 2014. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30, 2015 and 2014, UGI had cash and cash equivalents of $77.2 million and $245.9 million, respectively, most of which are located in the U.S. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.
The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business units.
AmeriGas Propane’s ability to pay dividends to UGI is dependent upon distributions it receives from AmeriGas Partners. At September 30, 2015, our 27% effective ownership interest in the Partnership consisted of approximately 23.8 million Common Units and an aggregate 2% general partner interest. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, as amended (the “Partnership Agreement”)) relating to such fiscal quarter. AmeriGas Propane, as general partner of AmeriGas Partners, is entitled to receive incentive distributions when AmeriGas Partners’ quarterly distribution exceeds $0.605 per limited partner unit. During Fiscal 2015, Fiscal 2014 and Fiscal 2013, the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests in the Partnership totaled $39.3 million, $32.4 million and $27.4 million, respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2015, Fiscal 2014 and Fiscal 2013 of $30.4 million, $23.9 million and $19.3 million, respectively (see Note 15 to Consolidated Financial Statements).
During Fiscal 2015, Fiscal 2014 and Fiscal 2013, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:

Year Ended September 30, |  | 2015 |  | 2014 |  | 2013
(Millions of dollars) |  |  |  |  |  |
AmeriGas Propane |  | $ | 97.3 |  |  | $ | 92.0 |  |  | $ | 96.2 |
UGI Utilities |  | 65.6 |  |  | 77.4 |  |  | 59.0 |
UGI International |  | 31.3 |  |  | 11.2 |  |  | 22.3 |
Total |  | $ | 194.2 |  |  | $ | 180.6 |  |  | $ | 177.5 |

Dividends and Distributions
On April 28, 2015, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.2275 per Common Share, equal to $0.91 on an annualized basis. The dividend rate reflects an approximately 4.6% increase from the previous quarterly rate of $0.2175. The new quarterly dividend rate was effective with the dividend payable on July 1, 2015, to shareholders of record on June 15, 2015.
On April 27, 2015, the General Partner’s Board of Directors approved an increase in the quarterly dividend rate on AmeriGas Partners Common Units to $0.92 per Common Unit, equal to $3.68 per Common Unit on an annualized basis. The distribution reflects a 4.5% increase from the previous quarterly rate of $0.88. The new quarterly rate was effective with the distribution payable on May 18, 2015, to unitholders of record on May 11, 2015.
Repurchase of Common Stock
In January 2014, the UGI Board of Directors authorized a share repurchase program for up to 15 million shares of UGI Corporation Common Stock. The authorization permits the execution of the share repurchase program over a four-year period. Pursuant to
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such authorization, during Fiscal 2015 and Fiscal 2014, the Company purchased on the open market 1.0 million and 1.2 million shares at a total purchase price of $34.1 million and $39.8 million, respectively.
Long-term Debt and Credit Facilities
The Company’s debt outstanding at September 30, 2015, totaled $3,889.7 million (including current maturities of long-term debt of $258.0 million and short-term borrowings of $189.9 million) compared to debt outstanding at September 30, 2014, of $3,721.6 million (including current maturities of long-term debt of $77.2 million and short-term borrowings of $210.8 million). Total debt outstanding at September 30, 2015, consists of (1) $2,351.6 million of Partnership debt; (2) $783.4 million of UGI International debt; (3) $693.7 million of UGI Utilities debt; (4) $49.5 million of Energy Services debt; and (5) $11.5 million of other debt. For a detailed description of the Company’s debt, see below and Notes 5 and 6 to the Consolidated Financial Statements.
AmeriGas Partners. AmeriGas Partners’ total debt at September 30, 2015, includes $2,250.8 million of AmeriGas Partners’ Senior Notes, $32.7 million of other long-term debt and $68.1 million of AmeriGas OLP short-term borrowings.
UGI International. UGI International’s total debt at September 30, 2015, includes a $670.7 million (€600 million) term loan outstanding under France SAS’s Senior Facilities Agreement, a $59.1 million U.S. dollar-denominated term loan at Flaga and a combined $51.2 million (€45.8 million) outstanding under Flaga’s euro-denominated term loans. Total UGI International debt outstanding at September 30, 2015, also includes (1) $0.6 million (€0.5 million) of Flaga short-term borrowings, and (2) $1.8 million (€1.6 million) of other long-term debt.
For detailed information on the Company’s short-term and long-term borrowings, see Notes 5 and 6 to Consolidated Financial Statements.
UGI France
On May 29, 2015, France SAS, an indirect wholly owned subsidiary of UGI, borrowed €600 million ($659.6 million) under the 2015 Senior Facilities Agreement. France SAS entered into the 2015 Senior Facilities Agreement on April 30, 2015, in anticipation of the Totalgaz Acquisition. The 2015 Senior Facilities Agreement consists of a €600 million variable-rate term loan and a €60 million revolving credit facility. Borrowings under the 2015 Senior Facilities Agreement €600 million term loan and the €60 million revolving credit facility bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate, which euribor rate has a floor of zero. France SAS has entered into pay-fixed, receive-variable interest rate swaps through April 30, 2019, to generally fix the underlying euribor rate on the €600 million term loan. At September 30, 2015, the effective interest rate on the term loan was approximately 2.70%.The term loan proceeds were used (1) to fund a portion of the Totalgaz Acquisition, including related fees and expenses; (2) to make a capital contribution from France SAS to its wholly owned subsidiary, AGZ Holding, in order to prepay €342 million principal amount, plus accrued interest, outstanding under the 2011 Senior Facilities Agreement due March 2016; (3) to settle Antargaz’ existing pay-fixed, receive-variable interest rate swaps associated with the 2011 Senior Facilities Agreement; and (4) for general corporate purposes.
As a result of prepaying the term loan outstanding under the 2011 Senior Facilities Agreement and concurrently settling the associated pay-fixed, receive-variable interest rate swaps, we recorded a pre-tax loss of $10.3 million comprising a $9.0 million loss on interest rate swaps and the write-off of $1.3 million of debt issuance costs. These amounts are included in interest expense on the Consolidated Statements of Income.
Flaga
In September 2015, Flaga terminated its then-existing $52 million U.S. dollar-denominated variable-rate term loan due September 2016 and concurrently entered into a $59.1 million U.S. dollar-denominated variable-rate term loan with the same bank. The $59.1 million term loan matures in September 2018. Also in September 2015, Flaga prepaid its €13.3 million ($14.9 million) euro-based term loan due September 2016. The $59.1 million term loan bears interest at the one-month LIBOR rate plus a margin of 1.125%. Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments under the $59.1 million term loan, by entering into a cross-currency swap arrangement with a bank. At September 30, 2015, the effective interest rate on the $59.1 million term loan was 0.87%%. At September 30, 2014, the effective interest rate on the $52 million term loan was 1.82%.
In October 2015, Flaga entered into the Flaga Credit Facility Agreement which includes, among other things, a €45.8 million variable-rate term loan facility. In October 2015, Flaga used proceeds from the issuance of the €45.8 million variable-rate term loan to refinance its €19.1 million ($21.4 million) term loan due October 2016, and its €26.7 million ($29.8 million) term loan due August 2016. The €45.8 million term loan matures in October 2020. The term loan under the Flaga Credit Facility Agreement bears interest at three-month euribor rates, plus a margin. The margin on such borrowings ranges from 0.40% to 1.80% and is
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based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined. Flaga expects to enter into pay-fixed, receive-variable interest rate swaps that will effectively fix the underlying euribor rate on the term loan. Because the €26.7 million term loan due August 2016 was refinanced on a long-term basis in October 2015, we have classified this debt as long-term on the September 30, 2015 Consolidated Balance Sheet.
Prior to its refinancing in October 2015, the Flaga €19.1 million term loan bore interest at three-month euribor rates plus a margin. The margin on such borrowings ranged from 1.175% to 2.525% and was based upon certain consolidated equity, return on assets and debt to EBITDA ratios. Flaga had effectively fixed the euribor component of the interest rate on this term loan at 1.79% by entering into an interest rate swap agreement. The effective interest rates on this term loan at September 30, 2015 and 2014, were 3.40%.
Prior to their refinancings in October 2015 and September 2015, respectively, Flaga’s €26.7 million and €13.3 million euro-based term loans bore interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus margins. The margins on such borrowings ranged from 1.125% to 2.55% and were based upon certain consolidated equity, return on assets and debt to EBITDA ratios. Flaga had effectively fixed the euribor component of the interest rates on these term loans through September 2016 at 2.68% by entering into interest rate swap agreements. The effective interest rates on these term loans outstanding as of September 30, 2015 and 2014 were 4.21% and 4.25%, respectively.
UGI Utilities. UGI Utilities’ total debt at September 30, 2015, includes long-term debt comprising $450.0 million of Senior Notes, $172.0 million of Medium-Term Notes and $71.7 million of short-term borrowings. UGI Utilities expects to refinance $247 million of maturing long-term debt during Fiscal 2016.
Short-term Debt
Due to the seasonal nature of the Company’s businesses, cash provided by operating activities is generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services consumed during the peak heating season months. Conversely, cash from operating activities is generally at its lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest. AmeriGas Propane and UGI Utilities primarily use their credit facilities to satisfy their seasonal operating cash flow needs. Energy Services historically has used its Receivables Facility to satisfy its operating cash flow needs. Energy Services also has a $240 million credit facility, which it can use for working capital and general corporate purposes. Flaga principally uses borrowings under its credit agreements to satisfy its operating cash flow needs. During Fiscal 2015, Fiscal 2014 and Fiscal 2013, UGI France generally funded its operating cash flow needs without using its revolving credit facilities and AvantiGas has funded its operating cash flow needs from cash on hand. Borrowings under the credit facilities and under the Energy Services Accounts Receivable Securitization Facility are classified as short-term debt on the Consolidated Balance Sheets. See Note 5 to Consolidated Financial Statements for further information on the Company’s short-term credit facilities.
AmeriGas Partners. AmeriGas OLP’s Amended and Restated Credit Agreement (“AmeriGas Credit Agreement”) with a group of banks provides for borrowings up to $525 million (including a sublimit of $125 million for letters of credit) and expires in June 2019. The AmeriGas Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin.
UGI International.
UGI France
As previously mentioned, France SAS entered into the 2015 Senior Facilities Agreement, which includes a €60 million revolving credit facility that expires in April 2020 (“UGI France Credit Facility”). Pursuant to the UGI France Credit Facility, each of France SAS’s wholly owned operating subsidiaries, Antargaz and Finagaz, can draw on such facility for up to €30 million each. The UGI France Credit Facility replaces the €40 million credit facility that was available under the 2011 Senior Facilities Agreement (“Antargaz Credit Facility”). For further information on these credit facilities, see Note 5 to Consolidated Financial Statements.
Flaga
At September 30, 2015, Flaga had one principal working capital facility (the “Flaga Multi-Currency Working Capital Facility”) and, prior to its expiration on September 30, 2015, also had a euro-denominated working capital facility (that provided for borrowings and issuances of guarantees totaling €12 million (the “Euro Working Capital Facility”)).
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The Flaga Multi-Currency Working Capital Facility comprises a €46 million multi-currency working capital facility which includes an uncommitted €6 million overdraft facility. There were no borrowings outstanding under the Flaga Multi-Currency Working Capital Facility at September 30, 2015, and no borrowings outstanding under either the Flaga Multi-Currency Working Capital facility or the Euro Working Capital Facility at September 30, 2014. Flaga also has certain in-country uncommitted overdraft facilities which it uses, from time to time, to fund short-term working capital needs. At September 30, 2015 and 2014, borrowings outstanding under these overdraft facilities totaled €0.5 million ($0.6 million) and €6.3 million ($8.0 million), respectively.
Borrowings under the Flaga Multi-Currency Working Capital Facility (prior to its termination in October 2015 as described below) and the Euro Working Capital Facility (prior to its expiration on September 30, 2015) generally bore interest at market rates (a daily euro-based rate or three-month euribor rates) plus margins. Issued and outstanding letters of credit, which reduce available borrowings under these agreements, totaled €19.9 million ($22.2 million) and €32.3 million ($40.8 million) at September 30, 2015 and 2014, respectively.
In October 2015, Flaga entered into a €100.8 million Credit Facility Agreement (the “Flaga Credit Facility Agreement”) with a bank. The Flaga Credit Facility Agreement includes a €25 million multi-currency revolving credit facility, a €25 million guarantee facility, a €5 million overdraft facility and a €45.8 million term loan facility. Borrowings under the multi-currency revolving credit facility bear interest at market rates (generally one, three or six-month euribor rates) plus margins. The margins on revolving facility borrowings, which range from 1.45% to 3.65%, are based upon the actual currency borrowed and certain consolidated equity, return on assets and debt to EBITDA ratios, as defined in the Flaga Credit Facility Agreement. The Flaga Credit Facility Agreement terminates in October 2020. Concurrent with Flaga entering into the Flaga Credit Facility Agreement, the Flaga Multi-Currency Working Capital Facility was terminated.
UGI Utilities. On March 27, 2015, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2015 Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2015 Credit Agreement, UGI Utilities terminated its then-existing $300 million revolving credit agreement dated as of May 25, 2011. Under the UGI Utilities 2015 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2015 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.0. The UGI Utilities 2015 Credit Agreement is scheduled to expire in March 2020.
Midstream & Marketing. Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings up to $240 million (including a $50 million sublimit for letters of credit) that expires in June 2016 and is expected to be amended and extended during Fiscal 2016. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries and to fund dividend payments provided that, after giving effect to such dividend payments, Energy Services maintains a specified ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement.
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Information about the Company’s principal credit agreements (excluding the Energy Services Receivables Facility which is discussed below) as of September 30, 2015 and 2014, is presented in the tables below.

(Millions of dollars or euros) |  | Total Capacity |  | Borrowings Outstanding |  | Letters of Credit and Guarantees Outstanding |  | Available Capacity |  | Weighted Average Interest Rate - End of Year
September 30, 2015 |  |  |  |  |  |  |  |  |  |
AmeriGas Credit Agreement |  | $525.0 |  | $68.1 |  | $64.7 |  | $392.2 |  | 2.20 | %
UGI France Credit Facility |  | €60.0 |  | €0.0 |  | €0.0 |  | €60.0 |  | N.A. |
Flaga Credit Agreements |  | €46.0 |  | €0.0 |  | €19.9 |  | €26.1 |  | N.A. |
UGI Utilities Credit Agreement |  | $300.0 |  | $71.7 |  | $2.0 |  | $226.3 |  | 1.07 | %
Energy Services Credit Agreement |  | $240.0 |  | $30.0 |  | $0.0 |  | $210.0 |  | 2.75 | %
September 30, 2014 |  |  |  |  |  |  |  |  |  |
AmeriGas Credit Agreement |  | $525.0 |  | $109.0 |  | $64.7 |  | $351.3 |  | 2.16 | %
Antargaz Credit Facility |  | €40.0 |  | €0.0 |  | €0.0 |  | €40.0 |  | N.A. |
Flaga Credit Agreements |  | €58.0 |  | €0.0 |  | €32.3 |  | €25.7 |  | N.A. |
UGI Utilities Credit Agreement |  | $300.0 |  | $86.3 |  | $2.0 |  | $211.7 |  | 1.03 | %
Energy Services Credit Agreement |  | $240.0 |  | $0.0 |  | $0.0 |  | $240.0 |  | N.A. |

The average daily and peak short-term borrowings under the Company’s principal credit agreements during Fiscal 2015 and Fiscal 2014 are as follows:

|  | 2015 |  | 2014
(Millions of dollars or euros) |  | Average |  | Peak |  | Average |  | Peak
AmeriGas Credit Agreement |  | $119.5 |  | $349.0 |  | $156.6 |  | $320.0
Flaga Credit Agreements |  | €2.6 |  | €3.6 |  | €1.1 |  | €3.6
UGI Utilities Credit Agreement |  | $61.7 |  | $163.6 |  | $29.9 |  | $86.3
Energy Services Credit Agreement |  | $22.9 |  | $97.5 |  | $41.4 |  | $114.0

Energy Services has an accounts receivable securitization facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper. On October 30, 2015, the expiration date of the Receivables Facility was extended to October 28, 2016. The Receivables Facility, as amended, provides Energy Services with the ability to borrow up to $150 million of eligible receivables during the period November through April, and up to $75 million of eligible receivables during the period May through October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank.
At September 30, 2015, the outstanding balance of ESFC trade receivables was $44.1 million and there was $19.5 million that was sold to the bank and reflected as short-term borrowings on the Consolidated Balance Sheets. At September 30, 2014, the outstanding balance of ESFC trade receivables was $46.4 million of which $7.5 million was sold to a commercial paper conduit of the bank. During Fiscal 2015 and Fiscal 2014, peak sales of receivables were $67.5 million and $70.0 million, respectively, and average daily amounts sold were $19.4 million and $15.7 million, respectively.
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Cash Flows
Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the fourth and first fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest.
Operating Activities:

Year Ended September 30, |  | 2015 |  | 2014 |  | 2013
(Millions of dollars) |  |  |  |  |  |
Net cash provided by operating activities |  | $ | 1,163.8 |  |  | $ | 1,005.4 |  |  | $ | 801.5 |

Year-to-year variations in our cash flow from operations can be significantly affected by changes in operating working capital especially during periods of significant changes in energy commodity prices. Cash flow from operating activities was higher in Fiscal 2015 compared to Fiscal 2014 reflecting greater cash flow from changes in operating working capital. Cash flow from operating activities before changes in operating working capital was $972.0 million in Fiscal 2015, $1,011.9 million in Fiscal 2014 and $845.6 million in Fiscal 2013. The decrease in Fiscal 2015 cash flow from operating activities before changes in operating working capital compared to such amount for Fiscal 2014 reflects, in large part, lower non-cash charges for deferred income taxes. The significant increase in Fiscal 2014 cash flow from operating activities before changes in operating working capital compared to such amount in Fiscal 2013 largely reflects the higher Fiscal 2014 operating results. Changes in operating working capital provided (used) operating cash flow of $191.8 million in Fiscal 2015, $(6.5) million in Fiscal 2014 and $(44.1) million in Fiscal 2013. The increase in cash flow from changes in operating working capital in Fiscal 2015 reflects, in large part, the impact on such cash flows from the previously mentioned significant decline in energy commodity costs which occurred during Fiscal 2015.The lower cash required to fund changes in working capital in Fiscal 2014 compared with Fiscal 2013 reflects, in large part, the greater net cash flow from changes in accounts receivable resulting from the significantly warmer weather at UGI International partially offset by cash used to fund Fiscal 2014 increases in propane inventories at AmeriGas Propane and natural gas inventories at UGI France.
Investing Activities:

Year Ended September 30, |  | 2015 |  | 2014 |  | 2013
(Millions of dollars) |  |  |  |  |  |
Net cash used by investing activities |  | $ | (976.3 | ) |  | $ | (487.6 | ) |  | $ | (553.3 | )

Investing activity cash flow is principally affected by cash expenditures for property, plant and equipment; cash paid for acquisitions of businesses; changes in restricted cash balances and net cash proceeds from sales of property, plant and equipment. Cash paid for acquisitions in Fiscal 2015 principally reflects the Totalgaz Acquisition consideration of approximately $496.6 million, net of cash acquired of $86.8 million, in addition to cash paid for acquisitions in Hungary and several Partnership acquisitions. Cash paid for acquisitions in Fiscal 2014 includes the acquisition by Midstream & Marketing of the retail natural gas marketing business of EQT Energy, LLC, and several Partnership acquisitions. Cash paid for acquisitions in Fiscal 2013 largely includes Flaga’s acquisition of BP’s LPG distribution business in Poland, Midstream & Marketing’s acquisition of a non-operating working interest in natural gas acreage in the Marcellus Shale region of Pennsylvania, and several Partnership acquisitions. Cash expenditures for property, plant and equipment totaled $490.6 million in Fiscal 2015, $456.8 million in Fiscal 2014 and $486.0 million in Fiscal 2013. The increase in capital expenditures in Fiscal 2015 reflects, in large part, higher Gas Utility replacement and infrastructure improvement capital expenditures. Cash from changes in restricted cash, primarily cash in futures brokerage accounts, used cash of $52.8 million in Fiscal 2015, $8.3 million in Fiscal 2014 and $5.3 million in Fiscal 2013. The amount of restricted cash required in such accounts is generally the result of changes in underlying commodity prices.
Financing Activities:

Year Ended September 30, |  | 2015 |  | 2014 |  | 2013
(Millions of dollars) |  |  |  |  |  |
Net cash used by financing activities |  | $ | (217.1 | ) |  | $ | (475.7 | ) |  | $ | (186.1 | )

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Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; short-term borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units; and issuances or repurchases of equity instruments.
The increases in dividends on UGI Common Stock and distributions on AmeriGas Partners’ publicly held Common Units during the three-year period principally reflects annual increases in quarterly dividend and distribution rates. Financing cash flows in Fiscal 2015 include net proceeds from the issuance of long-term debt under the 2015 Senior Facilities Agreement totaling $652.6 million, the proceeds of which were used principally to fund a portion of the Totalgaz Acquisition and to prepay term loans outstanding under the 2011 Senior Facilities Agreement. For further information on debt transactions see Note 6 to Consolidated Financial Statements.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions but include capital leases) for Fiscal 2015, Fiscal 2014 and Fiscal 2013. We also provide amounts we expect to spend in Fiscal 2016. We expect to finance a substantial portion of our Fiscal 2016 capital expenditures from cash generated by operations, borrowings under credit facilities, cash on hand and, in the case of Gas Utility, also from cash proceeds from issuance of long-term debt expected to occur in Fiscal 2016.

Year Ended September 30, |  | 2016 |  | 2015 |  | 2014 |  | 2013
(Millions of dollars) |  | (estimate) |  |  |  |  |  |
AmeriGas Propane |  | $ | 110.0 |  |  | $ | 102.0 |  |  | $ | 113.9 |  |  | $ | 111.1 |
UGI International |  | 99.9 |  |  | 87.5 |  |  | 73.2 |  |  | 70.8 |
Gas Utility |  | 301.8 |  |  | 189.7 |  |  | 156.4 |  |  | 144.4 |
Midstream & Marketing |  | 214.0 |  |  | 88.2 |  |  | 83.4 |  |  | 156.4 |
Other |  | 13.0 |  |  | 8.0 |  |  | 9.5 |  |  | 6.4 |
Total |  | $ | 738.7 |  |  | $ | 475.4 |  |  | $ | 436.4 |  |  | $ | 489.1 |

The higher levels of Midstream & Marketing’s estimated capital expenditures in Fiscal 2016 reflect capital expenditures principally related to Marcellus Shale infrastructure projects. The higher levels of Gas Utility capital expenditures in Fiscal 2015, as well as those estimated for Fiscal 2016, reflect greater main replacement and system improvement capital expenditures, increases in new business capital expenditures and, in Fiscal 2016, expected investments in new information technology projects.
Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2015. Such obligations include scheduled repayments of long-term debt, interest on long-term fixed-rate debt, operating lease payments, unconditional purchase obligations for pipeline capacity, pipeline transportation and natural gas storage services and commitments to purchase natural gas, LPG and electricity, capital expenditures and derivative instruments. The following table presents contractual cash obligations with non-affiliates under agreements existing as of September 30, 2015:

|  | Payments Due by Period
(Millions of dollars) |  | Total |  | Fiscal 2016 |  | Fiscal 2017 - 2018 |  | Fiscal 2019 - 2020 |  | Thereafter
Long-term debt (a) |  | $ | 3,697.3 |  |  | $ | 287.4 |  |  | $ | 221.4 |  |  | $ | 1,614.8 |  |  | $ | 1,573.7 |
Interest on long-term-fixed rate debt (b) |  | 1,431.6 |  |  | 209.2 |  |  | 386.4 |  |  | 337.8 |  |  | 498.2 |
Operating leases |  | 338.7 |  |  | 73.4 |  |  | 102.6 |  |  | 73.1 |  |  | 89.6 |
AmeriGas Propane supply contracts |  | 58.3 |  |  | 53.5 |  |  | 4.8 |  |  | — |  |  | — |
UGI International supply contracts |  | 452.1 |  |  | 452.1 |  |  | — |  |  | — |  |  | — |
Midstream & Marketing supply contracts |  | 332.7 |  |  | 165.9 |  |  | 134.2 |  |  | 32.6 |  |  | — |
UGI Utilities supply, storage and transportation contracts |  | 323.0 |  |  | 122.0 |  |  | 97.0 |  |  | 43.5 |  |  | 60.5 |
Derivative instruments (c) |  | 142.2 |  |  | 112.9 |  |  | 28.6 |  |  | 0.7 |  |  | — |
Total |  | $ | 6,775.9 |  |  | $ | 1,476.4 |  |  | $ | 975.0 |  |  | $ | 2,102.5 |  |  | $ | 2,222.0 |

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(a) | Based upon stated maturity dates for debt outstanding at September 30, 2015. Amounts exclude the effects of Flaga’s October 2015 debt refinancing transactions (see “Long-term Debt and Credit Facilities” above).

(b) | Based upon stated interest rates adjusted for the effects of interest rate swaps.

(c) | Represents the sum of amounts due from us if derivative instrument liabilities were settled at September 30, 2015, amounts reflected in the Consolidated Balance Sheet (but excluding amounts associated with interest rate swaps).

Other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2015, principally comprise refundable tank and cylinder deposits (as further described in Note 2 to Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”); litigation, property and casualty liabilities and obligations under environmental remediation agreements (see Note 16 to Consolidated Financial Statements); pension and other postretirement benefit liabilities recorded in accordance with accounting guidance relating to employee retirement plans (see Note 8 to Consolidated Financial Statements); and liabilities associated with executive compensation plans (see Note 14 to Consolidated Financial Statements). These liabilities are not included in the table of Contractual Cash Obligations and Commitments because they are estimates of future payments and not contractually fixed as to timing or amount. Required minimum contributions to UGI Utilities’ pension plan (as further described below under “U.S. Pension Plan”) in Fiscal 2016 are not expected to be material. Required minimum contributions to the U.S. Pension Plan in years beyond Fiscal 2016 will depend, in large part, on the impact of future returns and interest rates on pension plan assets. Certain of our operating lease arrangements, primarily vehicle leases with remaining lease terms of one to ten years, have residual value guarantees. Although such fair values at the end of the leases have historically exceeded the guaranteed amount, at September 30, 2015, the maximum potential amount of future payments under lease guarantees assuming the leased equipment was deemed worthless was approximately $32.4 million.
Totalgaz Acquisition
On May 29, 2015, UGI, through its wholly owned indirect subsidiary, France SAS, completed the Totalgaz Acquisition for €451.8 million ($496.6 million) in cash, including €30.0 million ($33.0 million) for estimated working capital. In November 2015, France SAS received €1.1 million ($1.2 million) of cash as a result of the completion of the final working capital amount. After its acquisition, the Totalgaz business is referred to herein as Finagaz. The Totalgaz Acquisition nearly doubles our retail LPG distribution business in France and is consistent with our growth strategies, one of which is to grow our core business through acquisitions. The Totalgaz Acquisition was funded from existing cash balances and a portion of loan proceeds from France SAS’s May 29, 2015, issuance of a €600 million term loan under its 2015 Senior Facilities Agreement (see Note 6 to Consolidated Financial Statements). For additional information on the Totalgaz Acquisition, see Note 4 to the Consolidated Financial Statements.
U.S. Pension Plan
In the U.S., we sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). The fair values of the U.S. Pension Plan’s assets totaled $430.8 million and $442.4 million at September 30, 2015 and 2014, respectively. At September 30, 2015 and 2014, the underfunded positions of the U.S. Pension Plan, defined as the excess of the projected benefit obligation (“PBO”) over the U.S. Pension Plan’s assets, were $132.8 million and $97.3 million, respectively.
We believe we are in compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations. Required minimum contributions to the U.S. Pension Plan in Fiscal 2016 are not expected to be material. Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2015 was $10.9 million. Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2016 is expected to be approximately $12.8 million.
GAAP guidance associated with pension and other postretirement plans generally requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and other postretirement benefit plans with current year changes recognized in shareholders’ equity unless such amounts are subject to regulatory recovery. At September 30, 2015, we have recorded after-tax charges to UGI Corporation’s stockholders’ equity of $19.7 million and recorded regulatory assets totaling $140.8 million in order to reflect the funded status of our pension and other postretirement benefit plans. For a more detailed discussion of the U.S. Pension Plan and our other postretirement benefit plans, see Note 8 to Consolidated Financial Statements.
Related Party Transactions
During Fiscal 2015, Fiscal 2014 and Fiscal 2013, we did not enter into any related-party transactions that had a material effect on our financial condition, results of operations or cash flows.
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Off-Balance-Sheet Arrangements
UGI primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the recognition and measurement guidance relating to guarantees under GAAP.
We do not have any off-balance-sheet arrangements that are expected to have a material effect on our financial condition, change in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Utility Matters
Growth Extension Tariff. On February 20, 2014, the PUC entered an order approving a Growth Extension Tariff (“GET Gas”) program under which UGI Gas, PNG and CPG may invest up to $5 million per year for five years to extend natural gas utility pipelines to provide service to unserved and underserved areas within their respective territories. Under the GET Gas program, customers utilizing the extended pipeline to receive natural gas will pay a monthly surcharge over a 10-year period to cover the cost of the extension. UGI Gas, PNG, and CPG began connecting customers under the GET Gas program in October 2014.
Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at five percent of the amount billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014, while UGI Gas has not had a general rate filing within the required time period to be eligible. Beginning on April 1, 2015, PNG was able to begin charging a DSIC at a rate other than zero. The impact of the DSIC charge at PNG did not have a material effect on Gas Utility results of operations.
Manufactured Gas Plants
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 $1.8 million and $1.1 million, respectively, in any calendar year. The CPG-COA 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 September 30, 2015 and 2014, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $13.8 million and $10.7 million, 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.
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (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 and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2015, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.
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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.
Market Risk Disclosures
Our primary market risk exposures are (1) commodity price risk; (2) interest rate risk; and (3) foreign currency exchange 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.
Commodity Price Risk
The risk associated with fluctuations in the prices the Partnership and our UGI International operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for LPG and other energy commodities. Their profitability is sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. The Partnership and UGI International may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements and over-the-counter derivative commodity instruments including price swap and option contracts. Our UGI International operations use over-the-counter derivative commodity instruments and may from time to time enter into other derivative contracts, similar to those used by the Partnership, to reduce market risk associated with a portion of their LPG purchases. Over-the-counter derivative commodity instruments used to economically hedge forecasted purchases of propane are generally settled at expiration of the contract. In addition, UGI France hedges a portion of its future U.S. dollar-denominated LPG product purchases through the use of forward foreign exchange contracts as further described below.
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 our Gas Utility operations. Gas Utility uses derivative financial instruments, including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”), to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility's PGC recovery mechanism.
Electric Utility's default service (“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.
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 or operating expenses.
In order to manage market price risk relating to substantially all of Midstream & Marketing’s fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX, Intercontinental Exchange and over-the-counter natural gas and electricity futures and natural gas basis swap contracts or enters into fixed-price supply arrangements. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge a portion of its anticipated sales of electricity from its electricity generation facilities. Although Midstream & Marketing’s fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas or electricity would adversely impact Midstream & Marketing’s results. In order to reduce this risk of supplier nonperformance, Midstream & Marketing has diversified its purchases across a number of suppliers.
Midstream & Marketing purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. Midstream & Marketing from time to time also enters into New York Independent System Operator
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(“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Midstream & Marketing also uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane.
Midstream & Marketing has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to supply electricity under these agreements, Midstream & Marketing would be required to purchase electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact Midstream & Marketing’s results.
Interest Rate Risk
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact their fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt comprises (1) short-term borrowings and (2) UGI France’s and Flaga’s variable-rate term loans. These debt agreements have interest rates that are generally indexed to short-term market interest rates. UGI France and Flaga, through the use of pay-fixed receive-variable interest rate swaps, have generally fixed the underlying euribor interest rates on their euro-denominated term loans through all, or a substantial portion of, the periods such debt is outstanding (assuming such underlying euribor rate is not less than zero). In addition, Flaga’s U.S. dollar-denominated loans have been swapped from fixed-rate U.S. dollars to fixed-rate euro currency at issuance through cross currency swaps, removing interest rate risk and foreign currency exchange risk associated with the underlying interest and principal payments. At September 30, 2015, combined borrowings outstanding under variable-rate debt agreements, excluding UGI France’s and Flaga’s effectively fixed-rate term loans and Flaga’s U.S. dollar-denominated loan, totaled $189.9 million. Based upon average borrowings outstanding under variable-rate borrowings (excluding UGI France’s and Flaga’s effectively fixed-rate term loan debt and Flaga’s U.S. dollar-denominated loans), an increase in short-term interest rates of 100 basis points (1%) would have increased our Fiscal 2015 and Fiscal 2014 interest expense by approximately $2.0 million and $2.3 million, respectively. The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of approximately $130.5 million and $143 million at September 30, 2015 and 2014, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of approximately $121.8 million and $120 million at September 30, 2015 and 2014, respectively.
Long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce interest rate risk associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”).
Foreign Currency Exchange Rate Risk
Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. From time to time, we use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Gains or losses on net investment hedges remain in accumulated other comprehensive income until such foreign operations are liquidated. At September 30, 2015, there were no unsettled net investment hedges outstanding. With respect to our net investments in our UGI International operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar would reduce their aggregate net book value at September 30, 2015, by approximately $105 million, which amount would be reflected in other comprehensive income.
In addition, in order to reduce volatility, UGI France hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases during the months of October through March through the use of forward foreign exchange contracts.
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Derivative Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties' financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions as deemed appropriate.
Certain of these derivative instrument agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2015 and 2014, restricted cash in brokerage accounts totaled $54.9 million and $16.6 million, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at September 30, 2015. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At September 30, 2015, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
The following table summarizes the fair values of unsettled market risk sensitive derivative instrument assets (liabilities) held at September 30, 2015 and 2014. The table also includes the changes in fair values of derivative instruments that would result if there were (1) a 10% adverse change in the market prices of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges; (2) a 50 basis point adverse change in the three-month and one-month euribor rates; and (3) a 10% change in the value of the euro versus the U.S. dollar. Gas Utility’s and Electric Utility’s derivative instruments other than gasoline futures and swap contracts are excluded from the table below because any associated net gains or losses are refundable to or recoverable from customers in accordance with Gas Utility and Electric Utility ratemaking.

|  | Asset (Liability)
(Millions of dollars) |  | Fair Value |  | Change in Fair Value
September 30, 2015: |  |  |  |
Commodity price risk |  | $ | (135.7 | ) |  | $ | (58.1 | )
Interest rate risk |  | $ | (10.8 | ) |  | $ | (36.6 | )
Foreign currency exchange rate risk |  | $ | 29.4 |  |  | $ | (26.0 | )
September 30, 2014: |  |  |  |
Commodity price risk |  | $ | (23.2 | ) |  | $ | (64.7 | )
Interest rate risk |  | $ | (20.9 | ) |  | $ | (3.7 | )
Foreign currency exchange rate risk |  | $ | 14.8 |  |  | $ | (26.4 | )

Critical Accounting Policies and Estimates
Accounting policies and estimates discussed in this section are those that we consider to be the most critical to an understanding of our financial statements because they involve significant judgments and uncertainties. Changes in these policies and estimates could have a material effect on the financial statements. The application of these accounting policies and estimates necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements. Management has reviewed these critical accounting policies, and the estimates and assumptions associated with them, with the Company’s Audit Committee. In addition, management has reviewed the following disclosures regarding the application of these critical accounting policies and estimates with the Audit Committee. Also, see Note 2 to Consolidated Financial Statements which discusses the significant accounting policies that we have selected from acceptable alternatives.
Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation regarding pending claims and legal actions that arise in the normal course of business. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere, and PNG and CPG owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with GAAP, when a loss is considered probable and reasonably estimable, we record a liability in the amount of our best estimate for the ultimate loss. When there is a range of possible loss with equal likelihood, liabilities recorded are based upon the low end of such range. The likelihood of a loss with respect to
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a particular contingency is often difficult to predict and determining a reasonable estimate of the loss or a range of possible loss may not be practicable based upon the information available and the potential effects of future events and decisions by third parties that will determine the ultimate resolution of the contingency. Reasonable estimates involve management judgments based on a broad range of information and prior experience. These judgments are reviewed quarterly as more information is received, and the amounts reserved are updated as necessary. Such estimated reserves may differ materially from the actual liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted.
Accounting For Derivative Instruments At Fair Value. The Company enters into derivative instruments to economically hedge the risks associated with changes in commodity prices, interest rates and foreign currency rates. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies. These derivatives are recognized as assets and liabilities at fair value on the Consolidated Balance Sheets. Derivative assets and liabilities are presented net by counterparty on our Consolidated Balance Sheets if the right of offset exists. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. Changes in the fair values of certain derivative instruments that qualify and are designated as cash flow hedges are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, both of which are components of equity, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. Changes in the fair values of derivative instruments that we do not designate as, or that do not qualify for, hedge accounting under GAAP, which currently comprises all of our commodity derivative instruments, are recognized in earnings on the Consolidated Statements of Income. The fair values of our derivative instruments are determined based upon actively-quoted market prices for identical assets and liabilities, indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Gains and losses associated with derivatives utilized by UGI Utilities to manage the price risk inherent in its natural gas and electricity purchasing activities are recoverable through PGC or Electric Utility DS mechanisms, subject to PUC approval. Accordingly, the offset to the changes in fair values of these derivatives for which the normal purchases and normal sales exception under GAAP does not apply are recorded as either a regulatory asset or liability on the Consolidated Balance Sheets. At September 30, 2015, the net fair value of our derivative assets totaled $39.6 million and the net fair value of our derivative liabilities totaled $153.0 million.
Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation by the PUC. In accordance with accounting guidance associated with rate-regulated entities, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2015, our regulatory assets and regulatory liabilities totaled $304.2 million and $71.0 million, respectively. For additional information on regulatory assets and liabilities, see Notes 2 and 9 to Consolidated Financial Statements.
Depreciation and Amortization of Long-Lived Assets. We compute depreciation on utility property, plant and equipment on a straight-line basis over the average remaining lives of its various classes of depreciable property and on our non-utility property, plant and equipment on a straight-line basis over estimated useful lives generally ranging from 3 to 40 years. We also use amortization methods and determine asset values of intangible assets subject to amortization using reasonable assumptions and projections. Changes in the estimated useful lives of property, plant and equipment and changes in intangible asset amortization methods or values could have a material effect on our results of operations. As of September 30, 2015, our net property, plant and equipment totaled $4,994.1 million and we recorded depreciation expense of $313.2 million during Fiscal 2015. As of September 30, 2015, our net intangible assets subject to amortization totaled $478.7 million and we recorded amortization expense on intangible assets subject to amortization of $52.0 million during Fiscal 2015.
Purchase Price Allocations. From time to time, the Company enters into material business combinations. In accordance with accounting guidance associated with business combinations, the purchase price is allocated to the various assets acquired and liabilities assumed at their estimated fair value. Fair values of assets acquired and liabilities assumed are based upon available information and we may involve an independent third party to perform appraisals. Estimating fair values can be complex and subject to significant business judgment and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, if necessary, up to one year from the acquisition date to finalize the purchase price allocation.
Impairment of Goodwill. We perform impairment tests on goodwill resulting from purchase business combinations at least annually at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated if they have similar economic characteristics. In accordance with GAAP, each of our reporting units with goodwill is
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required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. For certain of our reporting units, we assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we bypass the qualitative assessment and perform the first step of the two-step quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value and the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill as determined in the same manner as goodwill is recognized in a business combination. As of September 30, 2015, our goodwill totaled $2,953.4 million. We did not record any impairments of goodwill in Fiscal 2015, Fiscal 2014 or Fiscal 2013.
Pension Plan Assumptions. Pension plan assumptions are significant inputs to the actuarial models that measure pension benefit obligations and pension expense. The cost of providing benefits under the U.S. Pension Plan is dependent on historical information such as employee age, length of service, level of compensation and the actual rate of return on plan assets. In addition, certain assumptions relating to the future are used to determine pension expense including mortality assumptions, the discount rate applied to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase, among others. In October 2014, the Society of Actuaries developed an updated set of mortality assumptions presented in its RP-2014 Mortality Tables Report. During Fiscal 2015, we undertook a review of our U.S. Pension Plan mortality assumptions in light of the RP-2014 Mortality Tables Report. Based upon such review, we believe that the RP-2014 Mortality Table, adjusted for UGI’s own experience and reflecting a blue-collar adjustment, with future improvements using the IRS scale BB-2D, represents the best estimate of future mortality improvement for the U.S. Pension Plan. The new mortality assumptions increased the September 30, 2015, U.S. Pension Plan PBO by less than 5%, and we expect the new mortality assumptions will have the effect of increasing U.S. Pension Plan expense in Fiscal 2016 by approximately $3.5 million. Assets of the U.S. Pension Plan are held in trust and consist principally of equity and fixed income mutual funds and common stock. Changes in plan assumptions as well as fluctuations in actual equity or fixed income market returns could have a material impact on future pension costs. We believe the two most critical assumptions are (1) the expected rate of return on plan assets and (2) the discount rate. A decrease in the expected rate of return on U.S. Pension Plan assets of 50 basis points to a rate of 7.05% would result in an increase in pre-tax pension cost of approximately $2.1 million in Fiscal 2016. A decrease in the discount rate of 50 basis points to a rate of 4.10% would result in an increase in pre-tax pension cost of approximately $3.7 million in Fiscal 2016. For additional information on our U.S. Pension Plan, see Note 8 to Consolidated Financial Statements.
Income Taxes. We use the asset and liability method of accounting for income taxes. Under this method, income tax expense is recognized for the amount of taxes payable or refundable for the current year and for deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. Positions taken by an entity in its tax returns must satisfy a more-likely-than-not recognition threshold assuming the positions will be examined by tax authorities with full knowledge of relevant information. We use assumptions, judgments and estimates to determine our current provision for income taxes. We also use assumptions, judgments and estimates to determine our deferred tax assets and liabilities and any valuation allowance to be recorded against a deferred tax asset. Our assumptions, judgments and estimates relative to the current provision for income tax give consideration to current tax laws, our interpretation of current tax laws and possible outcomes of current and future audits conducted by foreign and domestic tax authorities. Changes in tax law or our interpretation thereof and the resolution of current and future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. Our assumptions, judgments and estimates relative to the amount of deferred income taxes take into account estimates of the amount of future taxable income. Actual taxable income or future estimates of taxable income could render our current assumptions, judgments and estimates inaccurate. Changes in the assumptions, judgments and estimates mentioned above could cause our actual income tax obligations to differ significantly from our estimates. As of September 30, 2015, our net deferred tax liabilities totaled $1,142.7 million.
Recently Issued Accounting Pronouncements
See Note 3 to the Consolidated Financial Statements for a discussion of the effects of recently issued accounting guidance.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

“Quantitative and Qualitative Disclosures About Market Risk” are contained in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Market Risk Disclosures” and are incorporated by reference.

ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Annual Report on Internal Control Over Financial Reporting and the financial statements and financial statement schedules referred to in the Index contained on page F-2 of this Report are incorporated herein by reference.

ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. | CONTROLS AND PROCEDURES

(a) | 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 or submitted 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 September 30, 2015, were effective at the reasonable assurance level.

(b) | For “Management’s Annual Report on Internal Control Over Financial Reporting” see Item 8 of this Report (which information is incorporated herein by reference).

(c) | During the most recent fiscal quarter, no change in the Company’s internal control over financial reporting occurred that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. | OTHER INFORMATION

None.
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PART III:
ITEMS 10 THROUGH 14.
In accordance with General Instruction G(3), and except as set forth below, the information required by Items 10, 11, 12, 13 and 14 is incorporated in this Report by reference to the following portions of UGI’s Proxy Statement, which will be filed with the SEC by December 31, 2015.

| Information |  | Captions of Proxy Statement Incorporated by Reference
Item 10. | Directors, Executive Officers and Corporate Governance |  | Election of Directors - Nominees; Corporate Governance; Director Independence; Board Leadership Structure and Role in Risk Management; Board Meetings and Attendance; Board and Committee Structure; Communications with the Board; Securities Ownership of Directors and Executive Officers - Section 16(a) - Beneficial Ownership Reporting Compliance; Report of the Audit Committee of the Board of Directors
| The Code of Ethics for the Chief Executive Officer and Senior Financial Officers of UGI Corporation is available without charge on the Company’s website, www.ugicorp.com, or by writing to Treasurer, UGI Corporation, P. O. Box 858, Valley Forge, PA 19482. |  |
Item 11. | Executive Compensation |  | Compensation of Directors; Report of the Compensation and Management Development Committee of the Board of Directors; Compensation Discussion and Analysis; Compensation of Executive Officers; Compensation Committee Interlocks and Insider Participation
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |  | Securities Ownership of Certain Beneficial Owners; Securities Ownership of Directors and Executive Officers
Item 13. | Certain Relationships and Related Transactions, and Director Independence |  | Election of Directors - Director Independence and Board and Committee Structure; Policy for Approval of Related Person Transactions
Item 14. | Principal Accounting Fees and Services |  | Our Independent Registered Public Accounting Firm

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Equity Compensation Table
The following table sets forth information as of the end of Fiscal 2015 with respect to compensation plans under which our equity securities are authorized for issuance.

Plan category |  | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) |  | Weighted average exercise price of outstanding options, warrants and rights (b) |  | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) |
Equity compensation plans approved by security holders |  | 9,255,377 |  | (1) | $ | 23.97 |  |  | 15,563,672 |  | (2)
|  | 1,136,251 |  | (3) | $ | 0 |  |  |  |
Equity compensation plans not approved by security holders |  | 0 |  |  |  |  |  |
Total |  | 10,391,628 |  |  | $ | 23.97 |  | (4) |  |

(1) | Represents 9,255,377 stock options under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 and the UGI Corporation 2013 Omnibus Incentive Compensation Plan.

(2) | Represents 34,774 securities remaining for future issuance of stock options from the 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 and 15,528,898 of securities for issuance from the UGI Corporation 2013 Omnibus Incentive Compensation Plan. The UGI Corporation 2013 Omnibus Incentive Compensation Plan was approved by shareholders on January 24, 2013.

(3) | Represents 1,136,251 phantom share units under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 and the UGI Corporation 2013 Omnibus Incentive Compensation Plan.

(4) | Weighted-average exercise price of outstanding options; excludes phantom share units.

The information concerning the Company’s executive officers required by Item 10 is set forth below.
EXECUTIVE OFFICERS

Name |  | Age |  | Position
John L. Walsh |  | 60 |  | President and Chief Executive Officer
Kirk R. Oliver |  | 57 |  | Chief Financial Officer
Davinder S. Athwal |  | 48 |  | Vice President - Accounting and Financial Control and Chief Risk Officer
Jerry E. Sheridan |  | 50 |  | President and Chief Executive Officer, AmeriGas Propane, Inc.
Robert F. Beard |  | 50 |  | President and Chief Executive Officer, UGI Utilities, Inc.
Monica M. Gaudiosi |  | 53 |  | Vice President, General Counsel and Secretary
Bradley C. Hall |  | 62 |  | Vice President - New Business Development

All officers are elected for a one-year term at the organizational meetings of the respective Boards of Directors held each year.
There are no family relationships between any of the officers or between any of the officers and any of the directors.
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John L. Walsh
Mr. Walsh is a Director and President (since 2005) and Chief Executive Officer (since 2013) of UGI Corporation. In addition, Mr. Walsh serves as a Director and Vice Chairman of AmeriGas Propane, Inc. (since 2005) and UGI Utilities, Inc. (since 2005), both of which are subsidiaries of UGI Corporation. Previously, he also served as Chief Operating Officer of UGI Corporation (2005 to 2013) and as President and Chief Executive Officer of UGI Utilities, Inc. (2009 to 2011). Mr. Walsh was the Chief Executive of the Industrial and Special Products Division of the BOC Group plc, an industrial gases company, a position he assumed in 2001. He was also an Executive Director of BOC (2001 to 2005). He joined BOC in 1986 as Vice President - Special Gases and held various senior management positions in BOC, including President of Process Gas Solutions, North America (2000 to 2001) and President of BOC Process Plants (1996 to 2000). Mr. Walsh also serves as a Vice President and Director of the World LPG Association.
Kirk R. Oliver
Mr. Oliver is Chief Financial Officer of UGI Corporation (since October 2012). From December 2011 until September 2012, Mr. Oliver served as Senior Managing Director & Chief Operating Officer of InfraREIT Capital Partners, LLC, a partnership that invests in infrastructure assets, primarily electric transmission and gas pipeline assets. Prior to joining InfraREIT Capital, Mr. Oliver served as Senior Vice President and Chief Financial Officer of Allegheny Energy, Inc., an electric utility company (2008 to 2011) and as a Senior Executive at Hunt Power, LLC, a company that develops and invests in electric and gas utility projects (2007 to 2008). Mr. Oliver served in various positions at TXU Corp. (now Energy Future Holdings Corp.), an electricity distribution, generation and transmission company in Texas (1998 to 2006), including as Executive Vice President and Chief Financial Officer (2004 to 2006), Senior Vice President, Finance (2000 to 2003) and Vice President, Treasurer and Assistant Secretary (1998 to 1999). Prior to joining TXU Corp., Mr. Oliver spent eleven years as an investment banker in the Global Power and Energy Group at Lehman Brothers and six years at Motorola Inc.
Davinder S. Athwal
Mr. Athwal is Vice President - Accounting and Financial Control and Chief Risk Officer (since January 2009). He previously served as the Global Mergers & Acquisitions Controller of Nortel Networks, Inc., a global supplier of telecommunications equipment and solutions from 2007 through 2008. Mr. Athwal served as Director, Global Revenue Governance for Nortel Networks, Inc. from 2006 through 2007. Mr. Athwal previously served in both accounting and risk management roles for IBM Corporation, a globally integrated innovation and technology company (2003 to 2006).
Jerry E. Sheridan
Mr. Sheridan is President, Chief Executive Officer and a Director of AmeriGas Propane, Inc. (since March 2012). Previously, he served as Vice President - Operations and Chief Operating Officer (2011 to 2012) and as Vice President - Finance and Chief Financial Officer (2005 to 2011) of AmeriGas Propane, Inc. Mr. Sheridan served as President and Chief Executive Officer (2003 to 2005) of Potters Industries, Inc., a global manufacturer of engineered glass materials and a wholly-owned subsidiary of PQ Corporation, a global producer of inorganic specialty chemicals. In addition, Mr. Sheridan served as Executive Vice President (2003 to 2005) and as Vice President and Chief Financial Officer (1999 to 2003) of PQ Corporation. Mr. Sheridan also serves on the Management Board of CP Kelco (since 2013), a privately held company that provides innovative products and solutions through the use of nature-based chemistry.
Robert F. Beard
Mr. Beard is President and Chief Executive Officer and a Director of UGI Utilities, Inc. (since September 2011). He previously served as Vice President - Marketing, Rates and Gas Supply (2010 to 2011) and Vice President - Southern Region (2008 to 2010) of UGI Utilities, Inc. From 2006 until 2008, Mr. Beard served as Vice President - Operations and Engineering of PPL Gas Utilities Corporation and, from 2002 until 2006, he served as Director - Operations and Engineering of PPL Gas Utilities Corporation.
Monica M. Gaudiosi
Ms. Gaudiosi is the Vice President, General Counsel and Secretary of UGI Corporation and UGI Utilities, Inc. (since April 2012). She is also Vice President (since 2012), General Counsel (since July 2015) and Secretary (since 2012) of AmeriGas Propane, Inc. Prior to joining UGI Corporation, Ms. Gaudiosi served as Senior Vice President and General Counsel (2007 to 2012) and Senior Vice President and Associate General Counsel (2005 to 2007) of Southern Union Company. Prior to joining Southern Union Company in 2005, Ms. Gaudiosi held various positions with General Electric Capital Corporation (1997 to 2005). Before joining
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General Electric Capital Corporation, Ms. Gaudiosi was an associate at the law firms of Hunton & Williams (1994 to 1997) and Sutherland, Asbill & Brennan (1988 to 1994).
Bradley C. Hall
Mr. Hall is Vice President - New Business Development (since October 1994). He also serves as President of UGI Enterprises, Inc. (since 1994) and UGI Energy Services, LLC (since 1995). He joined the Company in 1982 and held various positions in UGI Utilities, Inc., including Vice President - Marketing and Rates.
PART IV:

ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) | Documents filed as part of this report:

(1) | Financial Statements:

Included under Item 8 are the following financial statements and supplementary data:
Management’s Annual Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm (on Internal Control Over Financial Reporting) - Ernst & Young LLP
Report of Independent Registered Public Accounting Firm (on Consolidated Financial Statements and Schedules) - Ernst & Young LLP
Report of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP
Consolidated Balance Sheets as of September 30, 2015 and 2014
Consolidated Statements of Income for the years ended September 30, 2015, 2014 and 2013
Consolidated Statements of Comprehensive Income for the years ended September 30, 2015, 2014 and 2013
Consolidated Statements of Cash Flows for the years ended September 30, 2015, 2014 and 2013
Consolidated Statements of Changes in Equity for the years ended September 30, 2015, 2014 and 2013
Notes to Consolidated Financial Statements

(2) | Financial Statement Schedules:

I — Condensed Financial Information of Registrant (Parent Company)
II — Valuation and Qualifying Accounts for the years ended September 30, 2015, 2014 and 2013
We have omitted all other financial statement schedules because the required information is (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.

(3) | List of Exhibits:

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

Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
2.1 | Contribution and Redemption Agreement, dated October 15, 2011, by and among AmeriGas Partners, L.P., Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P. and Heritage ETC, L.P | AmeriGas Partners, L.P. | Form 8-K (10/15/11) | 2.1
2.2 | Amendment No. 1, dated as of December 1, 2011, to the Contribution and Redemption Agreement, dated as of October 15, 2011, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P. | AmeriGas Partners, L.P. | Form 8-K (12/1/11) | 2.1
2.3 | Amendment No. 2, dated as of January 11, 2012, to the Contribution and Redemption Agreement, dated as of October 15, 2012, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P. | AmeriGas Partners, L.P. | Form 8-K (1/11/12) | 2.1
2.4 | Letter Agreement, dated as of January 11, 2012, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P. | AmeriGas Partners, L.P. | Form 8-K (1/11/12) | 2.1
2.5 | Amendment to Contribution and Redemption Agreement, dated as of October 15, 2011, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P., dated as of March 20, 2013. | AmeriGas Partners, L.P. | Form 10-Q (3/31/13) | 2.1
3.1 | (Second) Amended and Restated Articles of Incorporation of the Company as amended through June 6, 2005. | UGI | Form 10-Q (6/30/05) | 3.1
3.2 | Articles of Amendment to the Amended and Restated Articles of Incorporation of UGI Corporation. | UGI | Form 8-K (7/29/14) | 3.1
3.3 | Amended and Restated Bylaws of UGI Corporation. | UGI | Form 8-K (9/29/15) | 3.1

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
4.1 | Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of long-term debt not required to be filed pursuant to Item 601(b)(4) of Regulation S-K). |  |  |
4.2 | The description of the Company’s Common Stock contained in the Company’s registration statement filed under the Securities Exchange Act of 1934, as amended. | UGI | Form 8-B/A (4/17/96) | 3.(4)
4.3 | UGI Corporation’s (Second) Amended and Restated Articles of Incorporation and Bylaws referred to in 3.1 and 3.3 above. |  |  |
4.4 | Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of July 27, 2009. | AmeriGas Partners, L.P. | Form 10-Q (6/30/09) | 3.1
4.5 | Amendment No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of March 13, 2012. | AmeriGas Partners, L.P. | Form 8-K (3/14/12) | 3.1
4.6 | Amendment No. 2 to Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of July 27, 2015. | AmeriGas Partners, L.P. | Form 8-K (7/27/15) | 3.1
4.7 | Indenture, dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee. | AmeriGas Partners, L.P. | Form 10-Q (12/31/10) | 4.1
4.8 | First Supplemental Indenture, dated as of January 20, 2011, to Indenture dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee. | AmeriGas Partners, L.P. | Form 8-K (1/19/11) | 4.1

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
4.9 | Second Supplemental Indenture, dated as of August 10, 2011, to Indenture dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee. | AmeriGas Partners, L.P. | Form 8-K (8/10/11) | 4.1
4.10 | Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994. | Utilities | Registration Statement No. 33-77514 (4/8/94) | 4(c)
4.11 | Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association. | Utilities | Form 8-K (9/12/06) | 4.2
4.12 | Indenture, dated as of January 12, 2012, among AmeriGas Finance Corp., AmeriGas Finance LLC, AmeriGas Partners, L.P., as guarantor, and U.S. Bank National Association, as trustee. | AmeriGas Partners, L.P. | Form 8-K (1/12/12) | 4.1
4.13 | First Supplemental Indenture, dated as of January 12, 2012, among AmeriGas Finance Corp., AmeriGas Finance LLC, AmeriGas Partners, L.P., as guarantor, and U.S. Bank National Association, as trustee. | AmeriGas Partners, L.P. | Form 8-K (1/12/12) | 4.2
4.14 | Form of Fixed Rate Medium-Term Note. | Utilities | Form 8-K (8/26/94) | 4(i)
4.15 | Form of Fixed Rate Series B Medium-Term Note. | Utilities | Form 8-K (8/1/96) | 4(i)
4.16 | Form of Floating Rate Series B Medium-Term Note. | Utilities | Form 8-K (8/1/96) | 4(ii)
4.17 | Officer’s Certificate establishing Medium-Term Notes Series. | Utilities | Form 8-K (8/26/94) | 4(iv)
4.18 | Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture. | Utilities | Form 8-K (8/1/96) | 4(iv)

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
4.19 | Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture. | Utilities | Form 8-K (5/21/02) | 4.2
4.20 | Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes. | Utilities | Form 8-K (5/21/02) | 4.1
4.21 | Form of Note Purchase Agreement dated October 30, 2013 between the Company and the purchasers listed as signatories thereto. | Utilities | Form 8-K (10/30/13) | 4.1
10.1** | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006. | UGI | Form 8-K (2/27/07) | 10.1
10.2** | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 - Terms and Conditions as amended and restated effective November, 2012. | UGI | Form 10-K (9/30/13) | 10.2
10.3** | UGI Corporation 2013 Omnibus Incentive Compensation Plan, effective as of January 24, 2013. | UGI | Registration Statement No. 333-186178 (1/24/13) | 99.1
10.4** | UGI Corporation Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012. | UGI | Form 10-Q (6/30/13) | 10.1
10.5** | UGI Corporation Executive Employee Severance Plan, as amended and restated as of November 16, 2012. | UGI | Form 10-Q (6/30/13) | 10.2
10.6** | UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006, as amended November 16, 2012. | UGI | Form 10-Q (3/31/13) | 10.14
10.7** | AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective July 30, 2010. | AmeriGas Partners, L.P. | Form 8-K (7/30/10) | 10.2
10.8** | AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective July 30, 2010 - Terms and Conditions. | AmeriGas Partners, L.P. | Form 10-K (9/30/10) | 10.10

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.9** | Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Performance Unit Grant Letter for Employees, dated January 21, 2015. | AmeriGas Partners, L.P. | Form 10-Q (3/31/15) | 10.1
10.10** | Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Phantom Unit Grant Letter for Directors, dated January 8, 2015. | AmeriGas Partners, L.P. | Form 10-Q (3/31/15) | 10.2
10.11** | AmeriGas Propane, Inc. Non-Qualified Deferred Compensation Plan, as Amended and Restated effective November 22, 2013. | AmeriGas Partners, L.P. | Form 10-Q (3/31/14) | 10.4
10.12** | AmeriGas Propane, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 15, 2012. | AmeriGas Partners, L.P. | Form 10-Q (6/30/13) | 10.1
10.13** | AmeriGas Propane, Inc. Executive Employee Severance Plan, as amended and restated as of November 15, 2012. | AmeriGas Partners, L.P. | Form 10-Q (6/30/13) | 10.2
10.14** | AmeriGas Propane, Inc. Supplemental Executive Retirement Plan, as Amended and Restated effective November 22, 2013. | AmeriGas Partners, L.P. | Form 10-Q (3/31/14) | 10.5
10.15** | AmeriGas Propane, Inc. Executive Annual Bonus Plan, effective as of October 1, 2006, as amended November 15, 2012. | AmeriGas Partners, L.P. | Form 10-Q (3/31/13) | 10.9
10.16** | UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012. | Utilities | Form 10-Q (6/30/13) | 10.1
10.17** | UGI Utilities, Inc. Executive Annual Bonus Plan, effective as of October 1, 2006, as amended as of November 16, 2012. | Utilities | Form 10-Q (3/31/13) | 10.2
10.18** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Employees, dated January 1, 2015. | UGI | Form 10-Q (3/31/15) | 10.1

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.19** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Stock Unit Grant Letter for Non Employee Directors, dated January 8, 2015. | UGI | Form 10-Q (3/31/15) | 10.2
10.20** | Form of UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 8, 2015. | UGI | Form 10-Q (3/31/15) | 10.1
10.21** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2015. | UGI | Form 10-Q (3/31/15) | 10.9
10.22** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for AmeriGas Employees, dated January 21, 2015. | UGI | Form 10-Q (3/31/15) | 10.30
10.23** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2015. | Utilities | Form 10-Q (3/31/15) | 10.2
10.24** | Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2015. | Utilities | Form 10-Q (3/31/15) | 10.1
10.25** | UGI Corporation 2009 Deferral Plan, as Amended and Restated effective January 24, 2014. | UGI | Form 10-Q (3/31/14) | 10.5
*10.26** | Description of oral compensation arrangements for Messrs. Walsh, Hall, and Oliver and Ms. Gaudiosi. |  |  |
10.27** | Description of oral compensation arrangement for Mr. Sheridan. | AmeriGas Partners, L.P. | Form 10-K (9/30/15) | 10.25
*10.28** | Summary of Director Compensation as of October 1, 2015. |  |  |

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.29** | Form of Confidentiality and Post-Employment Activities Agreement with AmeriGas Propane, Inc. for Mr. Sheridan. | AmeriGas Partners, L.P. | Form 10-K (9/30/09) | 10.29
10.30** | Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Mr. Walsh. | UGI | Form 10-Q (6/30/08) | 10.3
10.31** | Change in Control Agreement for Monica M. Gaudiosi dated as of April 23, 2012. | UGI | Form 10-Q (6/30/12) | 10.1
10.32** | Change in Control Agreement for Kirk R. Oliver dated as of October 1, 2012. | UGI | Form 10-Q (12/31/12) | 10.1
10.33** | Change in Control Agreement for Mr. Sheridan Amended and Restated as of March 3, 2012. | AmeriGas Partners, L.P. | Form 10-Q (3/31/12) | 10.6
10.34** | 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
10.35** | 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
10.36 | Trademark License Agreement dated April 19, 1995 among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | UGI | Form 10-K (9/30/10) | 10.37
10.37 | Trademark License Agreement, dated April 19, 1995 among AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | AmeriGas Partners, L.P. | Form 10-Q (12/31/10) | 10.1
10.38 | Release of Liens and Termination of Security Documents dated as of November 6, 2006 by and among AmeriGas Propane, Inc., Petrolane Incorporated, AmeriGas Propane, L.P., AmeriGas Propane Parts & Service, Inc. and Wachovia Bank, National Association, as Collateral Agent for the Secured Creditors, pursuant to the Intercreditor and Agency Agreement dated as of April 19, 1995. | AmeriGas Partners, L.P. | Form 10-K (9/30/06) | 10.3

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.39 | Receivables Purchase Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 8 thereto dated April 22, 2010 and Amendment No. 9 thereto dated August 26, 2010, by and among UGI Energy Services, Inc., as servicer, Energy Services Funding Corporation, as seller, Market Street Funding, LLC, as issuer, and PNC Bank, National Association, as administrator. | UGI | Form 10-K (9/30/11) | 10.47
10.40 | Amendment No. 10, dated as of April 21, 2011 to Receivables Purchase Agreement, dated as of November 30, 2001(as amended, supplemented or modified from time to time), by and among UGI Energy Services, Inc. as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator. | UGI | Form 8-K (4/21/11) | 10.1
10.41 | Amendment No. 11, dated as of April 19, 2012, to Receivables Purchase Agreement, dated as of November 30, 2001 (as amended, supplemented or modified from time to time), by and among UGI Energy Services, Inc., as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator. | UGI | Form 8-K (4/19/12) | 10.1
10.42 | Amendment No. 12, dated as of April 18, 2013, to Receivables Purchase Agreement, dated as of November 30, 2001 (as amended, supplemented, or modified from time to time), by and among UGI Energy Services, Inc., as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator. | UGI | Form 8-K (4/18/13) | 10.1

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.43 | Amendment No. 13, dated as of October 1, 2013, to Receivables Purchase Agreement, dated as of November 30, 2001 (as amended, supplemented, or modified from time to time), by and among UGI Energy Services, LLC, as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator. | UGI | Form 10-K (9/30/13) | 10.72
10.44 | Amendment No. 14, dated as of November 1, 2013, to Receivables Purchase Agreement, dated as of November 30, 2001 (as amended, supplemented, or modified from time to time), by and among UGI Energy Services, LLC, as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator. | UGI | Form 10-K (9/30/13) | 10.74
10.45 | Amendment No. 15, dated as of October 31, 2014, to Receivables Purchase Agreement, dated as of November 30, 2001 (as amended, supplemented, or modified from time to time), by and among UGI Energy Services, LLC, as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator. | UGI | Form 8-K (10/31/14) | 10.1
10.46 | Amendment No. 16, dated as of October 30, 2015, to Receivables Purchase Agreement, dated as of November 30, 2001 (as amended, supplemented, or modified from time to time), by and among UGI Energy Services, LLC, as servicer, Energy Services Funding Corporation, as seller, and PNC Bank, National Association, as issuer and administrator. | UGI | Form 8-K (10/30/15) | 10.1

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.47 | Purchase and Sale Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 3 thereto dated August 26, 2010, by and between UGI Energy Services, Inc. and Energy Services Funding Corporation. | UGI | Form 10-K (9/30/10) | 10.47
10.48 | Amendment No. 4 dated as of October 1, 2013 to Purchase and Sale Agreement dated as of November 30, 2001 by and between UGI Energy Services, LLC and Energy Services Funding Corporation. | UGI | Form 10-K (9/30/13) | 10.73
10.49 | Amended and Restated Credit Agreement, dated as of December 18, 2012, among UGI Energy Services, Inc., as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, PNC Bank, National Association, as syndication agent, and Wells Fargo Bank, National Association, as documentation agent. | UGI | Form 8-K (12/18/12) | 10.1
10.50 | Amendment No. 1, dated as of March 15, 2013, to Amended and Restated Credit Agreement, dated as of December 18, 2012, among UGI Energy Services, Inc., as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, PNC Bank, National Association, as syndication agent, and Wells Fargo Bank, National Association, as documentation agent. | UGI | Form 10-Q (3/31/13) | 10.1
10.51 | FSS Service Agreement No. 79028 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc. | Utilities | Form 10-K (9/30/14) | 10.16
10.52 | SST Service Agreement No. 79133 effective as of December 1, 2014 by and between Columbia Gas Transmission, LLC and UGI Utilities, Inc. | Utilities | Form 10-K (9/30/14) | 10.19
10.53 | Gas Supply and Delivery Service Agreement between UGI Energy Services, LLC and UGI Penn Natural Gas, Inc., effective November 1, 2015. | Utilities | Form 10-K (9/30/15) | 10.18

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.54 | Contingent Residual Support Agreement dated as of January 12, 2012, among Energy Transfer Partners, L.P., AmeriGas Finance LLC, AmeriGas Finance Corp., AmeriGas Partners, L.P., and for certain limited purposes only, UGI Corporation. | AmeriGas Partners, L.P. | Form 8-K (1/11/12) | 10.1
10.55 | Amendment to Contingent Residual Support Agreement dated as of January 12, 2012, among Energy Transfer Partners, L.P., AmeriGas Finance LLC, AmeriGas Finance Corp., AmeriGas Partners, L.P., and for certain limited purposes only, UGI Corporation, dated as of March 20, 2013. | AmeriGas Partners, L.P. | Form 10-Q (3/31/13) | 10.1
10.56 | Unitholder Agreement, dated as of January 12, 2012, by and among Heritage ETC, L.P., AmeriGas Partners, L.P., and, for limited purposes, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., and Energy Transfer Equity, L.P. | AmeriGas Partners, L.P. | Form 8-K (1/11/12) | 10.2
10.57 | Amended and Restated Credit Agreement dated as of June 18, 2014 by and among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as Guarantor, Wells Fargo Securities, LLC, as Sole Lead Arranger and Sole Book Manager, and the other financial institutions from time to time party thereto. | AmeriGas | Form 8-K (6/18/14) | 10.1

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
10.58 | Credit Agreement, dated as of March 27, 2015 among UGI Utilities, Inc., as borrower, PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and Citizens Bank, N.A., as joint lead arrangers and joint bookrunners, and PNC Bank, National Association, Citizens Bank of Pennsylvania, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, The Bank of New York Mellon, Bank of America, N.A., and the other financial institutions from time to time parties thereto. | Utilities | Form 8-K (3/27/15) | 10.1
10.59 | Senior Facilities Agreement dated April 30, 2015 by and among UGI France, as Borrower, Guarantor and Security Grantor, Natixis, as Facility Agent and Security Agent, Barclays Bank PLC, BNP Paribas, Caisse Régionale de Crédit Agricole Mutuel de Paris et d'Ile de France, Crédit Lyonnais SA, ING Bank N.V. (acting through its French branch), Société Générale Corporate & Investment Banking, and Natixis, as Mandated Lead Arrangers, Underwriters and Bookrunners, and HSBC France, as Senior Mandated Lead Arranger. | UGI | Form 10-Q (6/30/15) | 10.1
10.60 | First Amendment, dated as of November 18, 2015, to Trademark License Agreement, dated April 19, 1995, by and among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P., and AmeriGas Propane, L.P. | AmeriGas Partners, L.P. | Form 10-K (9/30/15) | 10.40
14 | Code of Ethics for principal executive, financial and accounting officers. | UGI | Form 10-K (9/30/03) | 14
*21 | Subsidiaries of the Registrant. |  |  |
*23.1 | Consent of Ernst & Young LLP |  |  |

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Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit
*23.2 | Consent of PricewaterhouseCoopers LLP |  |  |
*31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2015 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-K for the fiscal year ended September 30, 2015 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-K for the fiscal year ended September 30, 2015, 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 |  |  |

* | Filed herewith.

** | As required by Item 15(a)(3), this exhibit is identified as a compensatory plan or arrangement.

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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 CORPORATION
Date: | November 30, 2015 | By: | /s/ Kirk R. Oliver
|  |  | Kirk R. Oliver Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 30, 2015, by the following persons on behalf of the Registrant in the capacities indicated.

Signature |  | Title
/s/ John L. Walsh |  | President and Chief Executive Officer (Principal Executive Officer) and Director
John L. Walsh |
/s/ Kirk R. Oliver |  | Chief Financial Officer (Principal Financial Officer)
Kirk R. Oliver |
/s/ Davinder S. Athwal |  | Vice President - Accounting and Financial Control, Chief Risk Officer (Principal Accounting Officer)
Davinder S. Athwal |
/s/ Lon R. Greenberg |  | Chairman and Director
Lon R. Greenberg |
/s/ M. Shawn Bort |  | Director
M. Shawn Bort |  |
/s/ Richard W. Gochnauer |  | Director
Richard W. Gochnauer |
/s/ Frank S. Hermance |  | Director
Frank S. Hermance |
/s/ Ernest E. Jones |  | Director
Ernest E. Jones |
/s/ Anne Pol |  | Director
Anne Pol |
/s/ Marvin O. Schlanger |  | Director
Marvin O. Schlanger |
/s/ James B. Stallings, Jr. |  | Director
James B. Stallings, Jr. |  |
/s/ Roger B. Vincent |  | Director
Roger B. Vincent |

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UGI CORPORATION AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2015
F-1

Table of Contents
UGI CORPORATION
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

| Pages
Management’s Annual Report on Internal Control over Financial Reporting | F-3
Financial Statements: |
Report of Independent Registered Public Accounting Firm (on Internal Control Over Financial Reporting) - Ernst & Young LLP | F-4
Report of Independent Registered Public Accounting Firm (on Consolidated Financial Statements and Schedules) - Ernst & Young LLP | F-5
Report of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP | F-6
Consolidated Balance Sheets as of September 30, 2015 and 2014 | F-7
Consolidated Statements of Income for the years ended September 30, 2015, 2014 and 2013 | F-8
Consolidated Statements of Comprehensive Income for the years ended September 30, 2015, 2014 and 2013 | F-9
Consolidated Statements of Cash Flows for the years ended September 30, 2015, 2014 and 2013 | F-10
Consolidated Statements of Changes in Equity for the years ended September 30, 2015, 2014 and 2013 | F-11
Notes to Consolidated Financial Statements | F-12
Financial Statement Schedules: |
For the years ended September 30, 2015, 2014 and 2013: |
I — Condensed Financial Information of Registrant (Parent Company) | S-1
II — Valuation and Qualifying Accounts | S-4

We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
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Table of Contents
Reports of Management
Financial Statements
The Company’s consolidated financial statements and other financial information contained in this Annual Report were prepared by management, which is responsible for their fairness, integrity and objectivity. The consolidated financial statements and related information were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include amounts that are based on management’s best judgments and estimates.
The Audit Committee of the Board of Directors is composed of three members, each of whom is independent and a non-employee director of the Company. The Committee is responsible for monitoring and overseeing the financial reporting process, the adequacy of internal accounting controls, the independence and performance of the Company’s independent registered accounting firm and internal auditors. The Committee meets regularly, with and without management present, with the independent registered accounting firm and the internal auditors, both of which report directly to the Committee. In addition, the Committee provides regular reports to the Board of Directors.
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, of the Company’s internal control over financial reporting as of September 30, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO 2013 Framework”). The scope of that assessment excluded the Finagaz business acquired on May 29, 2015, by UGI France SAS (a Société par actions simplifiée) (formerly UGI Bordeaux Holding), a wholly owned indirect subsidiary of UGI Corporation. Finagaz’ total assets represented approximately 8% of the Company’s consolidated total assets at September 30, 2015 and approximately 2% of its consolidated revenues for the year then ended. Such exclusion is permitted based upon current guidance of the U.S. Securities & Exchange Commission.
Internal control over financial reporting refers to the process, designed under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, and effected by the Company’s Board of Directors, to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changing conditions, or the degree of compliance with the policies or procedures may deteriorate.
Based on its assessment, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2015, based on the COSO 2013 Framework. Ernst & Young LLP, our independent registered public accounting firm, has audited the effectiveness of the Company’s internal control over financial reporting as of September 30, 2015, as stated in their report, which appears herein.
/s/ John L. Walsh
Chief Executive Officer
/s/ Kirk R. Oliver
Chief Financial Officer
/s/ Davinder S. Athwal
Chief Accounting Officer
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Table of Contents
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of UGI Corporation.
We have audited UGI Corporation’s internal control over financial reporting as of September 30, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). UGI Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Finagaz, which is included in the fiscal year 2015 consolidated financial statements of UGI Corporation and constituted approximately 8% of total assets as of September 30, 2015 and approximately 2% of consolidated revenues for the year then ended. Our audit of internal control over financial reporting of UGI Corporation also did not include an evaluation of the internal control over financial reporting of Finagaz.
In our opinion, UGI Corporation maintained, in all material respects, effective internal control over financial reporting as of September 30, 2015, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of UGI Corporation, as of September 30, 2015, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended of UGI Corporation and our report dated November 30, 2015 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
November 30, 2015
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Table of Contents
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of UGI Corporation
We have audited the accompanying consolidated balance sheet of UGI Corporation as of September 30, 2015, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended. Our audit also included the financial statement schedules listed in the Index at Item 15(a). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of UGI Corporation at September 30, 2015, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), UGI Corporation’s internal control over financial reporting as of September 30, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November 30, 2015 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
November 30, 2015
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of UGI Corporation:
In our opinion, the consolidated balance sheet as of September 30, 2014 and the related consolidated statements of income, of comprehensive income, of changes in equity and of cash flows for each of the two years in the period ended September 30, 2014 present fairly, in all material respects, the financial position of UGI Corporation and its subsidiaries at September 30, 2014, and the results of their operations and their cash flows for each of the two years in the period ended September 30, 2014, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules for each of the two years in the period ended September 30, 2014 present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
November 28, 2014
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UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)

| September 30,
| 2015 |  | 2014
ASSETS |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 369.7 |  |  | $ | 419.5 |
Restricted cash | 69.3 |  |  | 16.6 |
Accounts receivable (less allowances for doubtful accounts of $29.7 and $39.1, respectively) | 619.7 |  |  | 684.7 |
Accrued utility revenues | 12.1 |  |  | 14.3 |
Inventories | 239.9 |  |  | 423.0 |
Deferred income taxes | 7.8 |  |  | 10.1 |
Utility regulatory assets | 4.1 |  |  | 13.2 |
Derivative instruments | 23.3 |  |  | 14.5 |
Prepaid expenses and other current assets | 113.9 |  |  | 67.1 |
Total current assets | 1,459.8 |  |  | 1,663.0 |
Property, plant and equipment |  |  |
Non-utility | 5,075.6 |  |  | 4,608.2 |
Utilities | 2,753.5 |  |  | 2,568.5 |
| 7,829.1 |  |  | 7,176.7 |
Accumulated depreciation and amortization | (2,835.0 | ) |  | (2,633.0 | )
Net property, plant, and equipment | 4,994.1 |  |  | 4,543.7 |
Goodwill | 2,953.4 |  |  | 2,833.4 |
Intangible assets, net | 610.1 |  |  | 576.4 |
Utility regulatory assets | 300.1 |  |  | 255.0 |
Derivative instruments | 16.3 |  |  | 12.5 |
Other assets | 212.8 |  |  | 209.0 |
Total assets | $ | 10,546.6 |  |  | $ | 10,093.0 |
LIABILITIES AND EQUITY |  |  |
Current liabilities |  |  |
Current maturities of long-term debt | $ | 258.0 |  |  | $ | 77.2 |
Short-term borrowings | 189.9 |  |  | 210.8 |
Accounts payable | 392.9 |  |  | 459.8 |
Employee compensation and benefits accrued | 133.4 |  |  | 106.5 |
Deposits and advances | 242.0 |  |  | 211.5 |
Derivative instruments | 121.8 |  |  | 40.2 |
Accrued interest | 57.4 |  |  | 57.9 |
Other current liabilities | 283.5 |  |  | 267.0 |
Total current liabilities | 1,678.9 |  |  | 1,430.9 |
Debt and other liabilities |  |  |
Long-term debt | 3,441.8 |  |  | 3,433.6 |
Deferred income taxes | 1,134.0 |  |  | 1,005.1 |
Deferred investment tax credits | 3.6 |  |  | 3.9 |
Derivative instruments | 31.2 |  |  | 16.6 |
Other noncurrent liabilities | 684.7 |  |  | 539.7 |
Total liabilities | 6,974.2 |  |  | 6,429.8 |
Commitments and contingencies (Note 16) |  |  |
Equity: |  |  |
UGI Corporation stockholders’ equity: |  |  |
UGI Common Stock, without par value (authorized - 450,000,000 shares; issued - 173,806,991 and 173,770,641 shares, respectively) | 1,214.6 |  |  | 1,215.6 |
Retained earnings | 1,636.9 |  |  | 1,509.4 |
Accumulated other comprehensive loss | (114.6 | ) |  | (21.2 | )
Treasury stock, at cost | (44.9 | ) |  | (44.7 | )
Total UGI Corporation stockholders’ equity | 2,692.0 |  |  | 2,659.1 |
Noncontrolling interests, principally in AmeriGas Partners | 880.4 |  |  | 1,004.1 |
Total equity | 3,572.4 |  |  | 3,663.2 |
Total liabilities and equity | $ | 10,546.6 |  |  | $ | 10,093.0 |

See accompanying Notes to Consolidated Financial Statements.
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UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)

| Year Ended September 30,
| 2015 |  | 2014 |  | 2013
Revenues |  |  |  |  |
Non-utility | $ | 5,650.4 |  |  | $ | 7,191.9 |  |  | $ | 6,255.7 |
Utility | 1,040.7 |  |  | 1,085.4 |  |  | 939.0 |
| 6,691.1 |  |  | 8,277.3 |  |  | 7,194.7 |
Costs and Expenses |  |  |  |  |
Cost of sales (excluding depreciation shown below): |  |  |  |  |
Non-utility | 3,225.7 |  |  | 4,612.8 |  |  | 3,858.4 |
Utility | 510.8 |  |  | 562.9 |  |  | 466.0 |
Operating and administrative expenses | 1,773.9 |  |  | 1,752.6 |  |  | 1,692.0 |
Utility taxes other than income taxes | 16.1 |  |  | 16.6 |  |  | 16.9 |
Depreciation | 313.2 |  |  | 305.7 |  |  | 301.4 |
Amortization | 60.9 |  |  | 57.2 |  |  | 61.7 |
Other income, net | (44.4 | ) |  | (36.1 | ) |  | (32.8 | )
| 5,856.2 |  |  | 7,271.7 |  |  | 6,363.6 |
Operating income | 834.9 |  |  | 1,005.6 |  |  | 831.1 |
Loss from equity investees | (1.2 | ) |  | (0.1 | ) |  | (0.4 | )
Interest expense | (241.9 | ) |  | (237.7 | ) |  | (240.3 | )
Income before income taxes | 591.8 |  |  | 767.8 |  |  | 590.4 |
Income taxes | (177.8 | ) |  | (235.2 | ) |  | (162.8 | )
Net income including noncontrolling interests | 414.0 |  |  | 532.6 |  |  | 427.6 |
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners | (133.0 | ) |  | (195.4 | ) |  | (149.5 | )
Net income attributable to UGI Corporation | $ | 281.0 |  |  | $ | 337.2 |  |  | $ | 278.1 |
Earnings per common share attributable to UGI Corporation stockholders: |  |  |  |  |
Basic | $ | 1.62 |  |  | $ | 1.95 |  |  | $ | 1.63 |
Diluted | $ | 1.60 |  |  | $ | 1.92 |  |  | $ | 1.60 |
Weighted-average common shares outstanding (thousands): |  |  |  |  |
Basic | 173,115 |  |  | 172,733 |  |  | 170,885 |
Diluted | 175,667 |  |  | 175,231 |  |  | 173,282 |

See accompanying Notes to Consolidated Financial Statements.
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UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of dollars)

| Year Ended September 30,
| 2015 |  | 2014 |  | 2013
Net income including noncontrolling interests | $ | 414.0 |  |  | $ | 532.6 |  |  | $ | 427.6 |
Net gains (losses) on derivative instruments (net of tax of $(8.0), $(12.2) and $(7.2), respectively) | 16.8 |  |  | 54.0 |  |  | 14.4 |
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(2.8), $2.0 and $(10.3), respectively) | 1.6 |  |  | (45.2 | ) |  | 53.5 |
Foreign currency translation adjustments (net of tax of $(1.0), $13.8 and $(6.6), respectively) | (63.5 | ) |  | (23.2 | ) |  | 28.8 |
Foreign currency (losses) gains on long-term intra-company transactions (net of tax of $(6.7), $10.6 and $(0.8), respectively) | (50.6 | ) |  | (19.8 | ) |  | 3.2 |
Benefit plans (net of tax of $1.4, $2.6 and $(3.8), respectively) | (1.2 | ) |  | (5.2 | ) |  | 5.3 |
Reclassifications of benefit plans actuarial losses and prior service costs(net of tax of $(0.8), $(0.6) and $(0.8), respectively) | 1.4 |  |  | 1.0 |  |  | 1.2 |
Other comprehensive (loss) income | (95.5 | ) |  | (38.4 | ) |  | 106.4 |
Comprehensive income including noncontrolling interests | 318.5 |  |  | 494.2 |  |  | 534.0 |
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners | (130.9 | ) |  | (186.6 | ) |  | (192.3 | )
Comprehensive income attributable to UGI Corporation | $ | 187.6 |  |  | $ | 307.6 |  |  | $ | 341.7 |

See accompanying Notes to Consolidated Financial Statements.
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)

| Year Ended September 30,
| 2015 |  | 2014 |  | 2013
CASH FLOWS FROM OPERATING ACTIVITIES |  |  |  |  |
Net income including noncontrolling interests | $ | 414.0 |  |  | $ | 532.6 |  |  | $ | 427.6 |
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: |  |  |  |  |
Depreciation and amortization | 374.1 |  |  | 362.9 |  |  | 363.1 |
Deferred income taxes, net | 13.7 |  |  | 66.7 |  |  | 48.7 |
Provision for uncollectible accounts | 31.6 |  |  | 43.5 |  |  | 30.2 |
Unrealized losses (gains) on derivative instruments | 119.1 |  |  | 18.6 |  |  | (0.2 | )
Equity-based compensation expense | 29.2 |  |  | 25.8 |  |  | 17.6 |
Other, net | (9.7 | ) |  | (38.2 | ) |  | (41.4 | )
Net change in: |  |  |  |  |
Accounts receivable and accrued utility revenues | 163.3 |  |  | 18.1 |  |  | (110.8 | )
Inventories | 181.4 |  |  | (65.1 | ) |  | 4.6 |
Utility deferred fuel costs, net of changes in unsettled derivatives | 51.8 |  |  | (17.6 | ) |  | 9.3 |
Accounts payable | (134.9 | ) |  | 3.7 |  |  | 38.7 |
Other current assets | (25.6 | ) |  | (1.2 | ) |  | 36.3 |
Other current liabilities | (44.2 | ) |  | 55.6 |  |  | (22.2 | )
Net cash provided by operating activities | 1,163.8 |  |  | 1,005.4 |  |  | 801.5 |
CASH FLOWS FROM INVESTING ACTIVITIES |  |  |  |  |
Expenditures for property, plant and equipment | (490.6 | ) |  | (456.8 | ) |  | (486.0 | )
Acquisitions of businesses, net of cash acquired | (447.5 | ) |  | (37.1 | ) |  | (78.9 | )
Increase in restricted cash | (52.8 | ) |  | (8.3 | ) |  | (5.3 | )
Other, net | 14.6 |  |  | 14.6 |  |  | 16.9 |
Net cash used by investing activities | (976.3 | ) |  | (487.6 | ) |  | (553.3 | )
CASH FLOWS FROM FINANCING ACTIVITIES |  |  |  |  |
Dividends on UGI Common Stock | (153.5 | ) |  | (136.1 | ) |  | (125.8 | )
Distributions on AmeriGas Partners publicly held Common Units | (248.9 | ) |  | (237.7 | ) |  | (226.5 | )
Issuances of debt | 660.3 |  |  | 174.5 |  |  | 227.1 |
Repayments of debt | (429.4 | ) |  | (242.6 | ) |  | (168.7 | )
Receivables Facility net borrowings (repayments) | 12.0 |  |  | (22.5 | ) |  | 30.0 |
(Decrease) increase in short-term borrowings | (31.9 | ) |  | 5.8 |  |  | 32.3 |
Issuances of UGI Common Stock | 11.9 |  |  | 10.9 |  |  | 36.4 |
Repurchases of UGI Common Stock | (34.1 | ) |  | (39.8 | ) |  | — |
Other | (3.5 | ) |  | 11.8 |  |  | 9.1 |
Net cash used by financing activities | (217.1 | ) |  | (475.7 | ) |  | (186.1 | )
Effect of exchange rate changes on cash and cash equivalents | (20.2 | ) |  | (11.9 | ) |  | 7.3 |
Cash and cash equivalents (decrease) increase | $ | (49.8 | ) |  | $ | 30.2 |  |  | $ | 69.4 |
CASH AND CASH EQUIVALENTS |  |  |  |  |
End of year | $ | 369.7 |  |  | $ | 419.5 |  |  | $ | 389.3 |
Beginning of year | 419.5 |  |  | 389.3 |  |  | 319.9 |
(Decrease) increase | $ | (49.8 | ) |  | $ | 30.2 |  |  | $ | 69.4 |
SUPPLEMENTAL CASH FLOW INFORMATION |  |  |  |  |
Cash paid for: |  |  |  |  |
Interest | $ | 227.0 |  |  | $ | 228.3 |  |  | $ | 243.6 |
Income taxes | $ | 173.1 |  |  | $ | 141.6 |  |  | $ | 60.0 |

See accompanying Notes to Consolidated Financial Statements.
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UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions of dollars, except per share amounts)

| Year Ended September 30,
| 2015 |  | 2014 |  | 2013
Common stock, without par value |  |  |  |  |
Balance, beginning of year | $ | 1,215.6 |  |  | $ | 1,208.1 |  |  | $ | 1,157.7 |
Common stock issued: |  |  |  |  |
Employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld | (22.1 | ) |  | (16.4 | ) |  | 29.7 |
Dividend reinvestment plan | — |  |  | — |  |  | 1.4 |
Excess tax benefits realized on equity-based compensation | 8.3 |  |  | 12.5 |  |  | 9.4 |
Equity-based compensation expense | 13.2 |  |  | 11.4 |  |  | 9.9 |
Loss from acquisition of noncontrolling interests through business combination | (0.4 | ) |  | — |  |  | — |
Balance, end of year | $ | 1,214.6 |  |  | $ | 1,215.6 |  |  | $ | 1,208.1 |
Retained earnings |  |  |  |  |
Balance, beginning of year | $ | 1,509.4 |  |  | $ | 1,308.3 |  |  | $ | 1,156.0 |
Net income attributable to UGI Corporation | 281.0 |  |  | 337.2 |  |  | 278.1 |
Cash dividends on common stock ($0.890, $0.791 and $0.737 per share, respectively) | (153.5 | ) |  | (136.1 | ) |  | (125.8 | )
Balance, end of year | $ | 1,636.9 |  |  | $ | 1,509.4 |  |  | $ | 1,308.3 |
Accumulated other comprehensive income (loss) |  |  |  |  |
Balance, beginning of year | $ | (21.2 | ) |  | $ | 8.4 |  |  | $ | (55.2 | )
Net gains on derivative instruments, net of tax | 16.8 |  |  | 21.6 |  |  | 9.8 |
Reclassification of net losses (gains) on derivative instruments, net of tax | 3.7 |  |  | (4.0 | ) |  | 15.3 |
Benefit plans, principally actuarial (losses) gains, net of tax | (1.2 | ) |  | (5.2 | ) |  | 5.3 |
Reclassification of benefit plans actuarial losses and prior service costs, net of tax | 1.4 |  |  | 1.0 |  |  | 1.2 |
Foreign currency (losses) gains on long-term intra-company transactions, net of tax | (50.6 | ) |  | (19.8 | ) |  | 3.2 |
Foreign currency translation adjustments, net of tax | (63.5 | ) |  | (23.2 | ) |  | 28.8 |
Balance, end of year | $ | (114.6 | ) |  | $ | (21.2 | ) |  | $ | 8.4 |
Treasury stock |  |  |  |  |
Balance, beginning of year | $ | (44.7 | ) |  | $ | (32.3 | ) |  | $ | (28.7 | )
Common stock issued: |  |  |  |  |
Employee and director plans | 40.5 |  |  | 65.8 |  |  | 35.2 |
Dividend reinvestment plan | — |  |  | — |  |  | 0.8 |
Repurchases of common stock | (34.1 | ) |  | (39.8 | ) |  | — |
Reacquired common stock - employee and director plans | (6.6 | ) |  | (38.4 | ) |  | (39.6 | )
Balance, end of year | $ | (44.9 | ) |  | $ | (44.7 | ) |  | $ | (32.3 | )
Total UGI Corporation stockholders’ equity | $ | 2,692.0 |  |  | $ | 2,659.1 |  |  | $ | 2,492.5 |
Noncontrolling interests |  |  |  |  |
Balance, beginning of year | $ | 1,004.1 |  |  | $ | 1,055.4 |  |  | $ | 1,085.6 |
Net income attributable to noncontrolling interests, principally in AmeriGas Partners | 133.0 |  |  | 195.4 |  |  | 149.5 |
Net gains on derivative instruments | — |  |  | 32.4 |  |  | 4.6 |
Reclassification of net (gains) losses on derivative instruments | (2.1 | ) |  | (41.2 | ) |  | 38.2 |
Dividends and distributions | (249.4 | ) |  | (238.0 | ) |  | (226.7 | )
Change in noncontrolling interests as a result of business combination | (5.2 | ) |  | — |  |  | — |
Other | — |  |  | 0.1 |  |  | 4.2 |
Balance, end of year | $ | 880.4 |  |  | $ | 1,004.1 |  |  | $ | 1,055.4 |
Total equity | $ | 3,572.4 |  |  | $ | 3,663.2 |  |  | $ | 3,547.9 |

See accompanying Notes to Consolidated Financial Statements.
F-11

Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Index to Notes
Note 1 — Nature of Operations
Note 2 — Summary of Significant Accounting Policies
Note 3 — Accounting Changes
Note 4 — Acquisitions
Note 5 — Short-term Borrowings
Note 6 — Long-term Debt
Note 7 — Income Taxes
Note 8 — Employee Retirement Plans
Note 9 — Utility Regulatory Assets and Liabilities and Regulatory Matters
Note 10 — Inventories
Note 11 — Property, Plant and Equipment
Note 12 — Goodwill and Intangible Assets
Note 13 — Series Preferred Stock
Note 14 — Common Stock and Equity-Based Compensation
Note 15 — Partnership Distributions
Note 16 — Commitments and Contingencies
Note 17 — Fair Value Measurements
Note 18 — Derivative Instruments and Hedging Activities
Note 19 — Accumulated Other Comprehensive Income
Note 20 — Other Income, Net
Note 21 — Quarterly Data (unaudited)
Note 22 — Segment Information
Note 1 — Nature of Operations
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; (3) own all or a portion of electricity generation facilities; and (4) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company,” “we” or “us.”
We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”), which is referred to herein as the “Operating Partnership.” AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the “Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30, 2015, the General Partner held a 1% general partner interest and 25.3% limited partner interest in AmeriGas Partners, and held an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises 69,133,098 Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances (see Note 15).
Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“UGI France”); (2) an LPG distribution business in central, northern and eastern Europe (“Flaga”); (3) an LPG distribution business in the United Kingdom (“AvantiGas”); and (4) an LPG distribution business in the Nantong region of China. We refer to our foreign LPG operations collectively as “UGI International.” On May 29, 2015, UGI France SAS (a Société par actions simplifiée) (“France SAS”) (formerly UGI Bordeaux Holding) , an indirect wholly owned subsidiary of UGI, purchased all of the outstanding shares of Totalgaz SAS (the “Totalgaz Acquisition”), a retail distributor of LPG in France. The retail LPG distribution business of Totalgaz SAS and its subsidiaries is referred to herein as “Finagaz” and
F-12

Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
is included in our UGI France reportable segment (see Notes 4 and 22). The LPG retail distribution business of UGI France prior to the Totalgaz Acquisition is also referred to herein as “Antargaz.”
Enterprises, through UGI Energy Services, LLC and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic and Northeast U.S. In addition, UGI Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. These businesses are referred to herein collectively as “Midstream & Marketing.” UGI Energy Services, LLC is referred to herein as “Energy Services.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries.
Our natural gas distribution utility business (“Gas Utility”) is conducted through our wholly owned subsidiary, UGI Utilities, Inc. (“UGI Utilities”), and its subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and 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.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission. Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”
Note 2 — Summary of Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
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.
Principles of Consolidation
The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the public’s interests in the Partnership, and outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests. We eliminate all significant intercompany accounts and transactions when we consolidate. Entities in which we do not have control but have significant influence over operating and financial policies are accounted for by the equity method. Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2015 and 2014. Investments in business entities that are not publicly traded and in which we hold less than 20% of voting rights are accounted for using the cost method. Such investments are recorded in other assets and totaled $70.8 and $77.8 at September 30, 2015 and 2014, respectively (including $17.9 and $17.4, respectively, associated with our approximate 3.5% interest in a private equity partnership that invests in renewable energy companies). Undivided interests in natural gas production assets and an electricity generation facility are consolidated on a proportionate basis.
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980 “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulator. For additional information regarding the effects of rate regulation on our utility operations, see Note 9.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Fair Value Measurements
The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, also on a nonrecurring basis. Fair value measurements performed on a recurring basis principally relate to derivative instruments and investments held in supplemental executive retirement plan grantor trusts.
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

• | Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

• | Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means.

• | Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.
Derivative Instruments
Derivative instruments are reported in the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.
Certain of our derivative instruments are designated and qualify as cash flow hedges or net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the commodity derivative instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers.
Effective October 1, 2014, UGI International determined on a prospective basis that it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Substantially all realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues, as appropriate, on the Consolidated Statements of Income.
Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, if any, are included in cash flows from operating activities on the Consolidated Statements of Cash Flows. Cash flows from net investment hedges are included in cash flows from investing activities on the Consolidated Statements of Cash Flows. Cash flows from the interest portion
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
of our cross-currency hedges are included in cash flow from operating activities while cash flows from the currency portion of such hedges are included in the cash flow from financing activities.
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 18.
Foreign Currency Translation
Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income.
Revenue Recognition
Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing records revenues when energy products are delivered or services are provided to customers. Revenues from the sale of appliances and equipment are recognized at the later of sale or installation. Revenues from repair or maintenance services are recognized upon completion of services.
UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service and commodities rendered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective.
We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in utility taxes other than income taxes on the Consolidated Statements of Income.
Accounts Receivable
Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.
LPG Delivery Expenses
Expenses associated with the delivery of LPG to customers of the Partnership and our UGI International operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as operating and administrative expenses on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and UGI International delivery vehicles is classified in depreciation on the Consolidated Statements of Income.
Income Taxes
AmeriGas Partners and the Operating Partnership are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. The Operating Partnership has subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation.
Gas Utility and Electric Utility record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. They also record a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. Investment tax credits associated with Midstream &
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Marketing’s qualifying solar energy property under the Emergency Economic Stabilization Act of 2008 are reflected in income taxes for assets placed in service after Fiscal 2011 and are amortized over the estimated useful life of the property for assets placed in service prior to Fiscal 2012.
We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. For Fiscal 2015, Fiscal 2014 and Fiscal 2013, interest income or expense recognized in income taxes on the Consolidated Statements of Income was not material.
Earnings Per Common Share
Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2015, Fiscal 2014 and Fiscal 2013:

(Thousands of shares) |  | 2015 |  | 2014 |  | 2013
Weighted-average common shares outstanding for basic computation |  | 173,115 |  |  | 172,733 |  |  | 170,885 |
Incremental shares issuable for stock options and common stock awards (a) |  | 2,552 |  |  | 2,498 |  |  | 2,397 |
Weighted-average common shares outstanding for diluted computation |  | 175,667 |  |  | 175,231 |  |  | 173,282 |

(a) | For Fiscal 2015, Fiscal 2014 and Fiscal 2013, there were 1,274 shares, 0 shares and 132 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive.

Cash and Cash Equivalents
All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.
Restricted Cash
Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. At September 30, 2015, restricted cash also includes $14.3 associated with a construction escrow agreement.
Inventories
At September 30, 2015, our inventories are stated at the lower of cost or net realizable value and, prior to September 30, 2015, the lower of cost or market. We determine cost using an average cost method for LPG, specific identification for appliances and the first-in, first-out (“FIFO”) method for all other inventories. During the fourth quarter of Fiscal 2015, the Company adopted new accounting guidance regarding the measurement of inventory which simplified the determination of market value. The adoption of the new guidance did not impact the valuation of our inventories (see Note 3).
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.
We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives ranging from 10 to 40 years for buildings and improvements; 6 to 40 years for storage and customer tanks and cylinders; 25 to 40 years for electricity generation facilities; 25 to 40 years for pipeline and related assets, and 3 to 12 years for vehicles, equipment and office furniture and fixtures. Costs to install Partnership and UGI France-owned tanks, net of amounts billed to customers, are capitalized and amortized over the estimated period of benefit not exceeding 10 years.
We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. The composite annual rate for depreciable property at our Gas Utility was 2.2% in Fiscal 2015, 2.3% in Fiscal 2014 and 2.3% in Fiscal 2013. The composite annual rate for depreciable property at our Electric Utility was 2.5% in Fiscal 2015, 2.5% in Fiscal 2014 and 2.4% in Fiscal 2013. When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit generally not exceeding 10 years once the installed software is ready for its intended use.
No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
Goodwill and Intangible Assets
In accordance with GAAP relating to intangible assets, we amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. No amortization expense of intangible assets is included in cost of sales in the Consolidated Statements of Income (see Note 12). Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships, certain tradenames and noncompete agreements, do not exceed 15 years. We review definite-lived intangible assets for impairment whenever events or changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset. Intangible assets with indefinite lives are not amortized but are tested annually (and more frequently if events or changes in circumstances between annual tests indicate that it is more likely than not that they are impaired) for impairment and written down to fair value, if impaired.
We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. In accordance with GAAP, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. For certain of our reporting units with goodwill, we assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount.
For our other reporting units with goodwill, we bypass the qualitative assessment and perform the first step of the two-step quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, the implied fair value of goodwill is determined in the same manner as goodwill is recognized in a business combination. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to such excess.
There were no accumulated impairment losses at September 30, 2015 and 2014, and no provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2015, Fiscal 2014 or Fiscal 2013.
Impairment of Long-Lived Assets and Cost Basis Investments
We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No material provisions for impairments were recorded during Fiscal 2015, Fiscal 2014 or Fiscal 2013.
We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary. During Fiscal 2013, we recorded a pre-tax loss of $6.3 associated with an other-than-temporary impairment of an investment in a private equity partnership. No other-than-temporary impairment losses were recognized in Fiscal 2015 or Fiscal 2014.
Deferred Debt Issuance Costs
Included in other assets on our Consolidated Balance Sheets are net deferred debt issuance costs of $36.3 and $36.7 at September 30, 2015 and 2014, respectively. We are amortizing these costs over the terms of the related debt.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Refundable Tank and Cylinder Deposits
Included in other noncurrent liabilities on our Consolidated Balance Sheets are customer paid deposits primarily on UGI France owned tanks and cylinders of $273.4 and $200.0 at September 30, 2015 and 2014, respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.
Environmental Matters
We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.
Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can reasonably be estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. 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 CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see Note 16.
Employee Retirement Plans
We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 8).
Equity-Based Compensation
All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units”), are measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as a liability or as equity on our Consolidated Balance Sheets. Equity-based compensation costs associated with the portion of Unit awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with the portion of Unit awards classified as liabilities are measured based upon their estimated fair value at the grant date and remeasured as of the end of each period.
We have calculated a tax windfall pool using the shortcut method. We record deferred tax assets for awards that we expect will result in deductions on our income tax returns based on the amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return are recorded in Common Stock (if the tax benefit exceeds the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeds the tax benefit and no tax windfall pool exists from previous awards).
For additional information on our equity-based compensation plans and related disclosures, see Note 14.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Correction of Prior Period Error in Other Comprehensive Income
During Fiscal 2015, the Company recorded a $10.7 decrease to other comprehensive income related to prior periods by reducing the amount of net deferred tax assets that had been previously recognized for (1) foreign currency adjustments related to foreign subsidiaries whose undistributed earnings are considered indefinitely reinvested, and (2) foreign currency adjustments related to intercompany loans between a U.S. domiciled entity and its foreign branch that is considered disregarded for tax purposes and for which income taxes will not be payable. ASC 740, “Income Taxes,” provides an exception to recording deferred tax attributes associated with these components of comprehensive income. Previously, the Company had incorrectly recorded deferred taxes on these foreign currency adjustments. The Company has evaluated the effects of the errors, both qualitatively and quantitatively, and concluded that they did not have a material impact on any previously issued financial statements or the full year results for Fiscal 2015.
The impact to other comprehensive income for the year ended September 30, 2015 resulting from the correction of these errors is as follows:

Reported other comprehensive loss |  | $ | (95.5 | )
Correction of error in deferred taxes related to prior periods |  | 10.7 |
Other comprehensive loss excluding impact of correction |  | $ | (84.8 | )

Note 3 — Accounting Changes
Adoption of New Accounting Standards
Measurement of Inventory. During the fourth quarter of Fiscal 2015, the Company adopted new accounting guidance regarding the measurement of inventory. The new guidance amends existing guidance and requires inventory be measured at the lower of cost or net realizable value. Net realizable value is generally defined as estimated selling prices in the ordinary course of business less reasonably predictable costs of completion, disposal and transportation. We applied this guidance prospectively and the adoption of this guidance did not impact our results of operations, cash flows or financial position for Fiscal 2015.
Business Combinations. During the fourth quarter of Fiscal 2015, the Company adopted new accounting guidance regarding accounting for measurement period adjustments associated with prior business combinations. The new guidance requires that an acquirer recognize adjustments to provisional amounts in the reporting period in which the adjustments are determined and record, in the same period’s financial statements, the effects on earnings of changes in depreciation, amortization and other income effects, if any, as a result of such adjustments. The new guidance also requires certain disclosures regarding amounts recorded in the current period that would have been recorded in previous reporting periods if such adjustments had been recognized as of the acquisition date. We applied this guidance prospectively and the adoption of this guidance did not have a material impact on our results of operations, cash flows or financial position for Fiscal 2015.
Accounting Standards Not Yet Adopted
Presentation of Deferred Taxes. In November 2015, the FASB issued Accounting Standards Update (“ASU”) No. 2015-17, "Balance Sheet Classification of Deferred Taxes." This ASU amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016 (Fiscal 2018), and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual period. Additionally, the new guidance may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We have not yet selected an adoption method and are currently evaluating the impact of adopting this guidance on our consolidated financial statements.
Debt Issuance Costs. In April 2015, the FASB issued ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance in Fiscal 2016. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Consolidation. In February 2015, the FASB issued ASU No. 2015-02, “Amendments to the Consolidation Analysis.” This ASU provides new guidance regarding whether a reporting entity should consolidate certain types of legal entities. Among other things, the new guidance modifies the evaluation of whether limited partnerships and similar entities are variable interest entities (“VIEs”) or voting interest entities, and also eliminates the presumption that a general partner should consolidate a limited partnership. The new guidance also affects the consolidation analysis of reporting entities that are involved with VIEs including those that have fee arrangements and related party relationships. The new guidance is effective for the Company beginning in Fiscal 2017. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements, if any, from the adoption of the new guidance.
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in ASC 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This standard is effective for the Company for interim and annual periods beginning October 1, 2018 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our consolidated financial statements.
Note 4 — Acquisitions
Acquisition of Totalgaz
On May 29, 2015 (the “Acquisition Date”), UGI, through its wholly owned indirect subsidiary, France SAS, completed the acquisition of all of the outstanding shares of Totalgaz SAS, a retail distributor of LPG in France, for €451.8 ($496.6) in cash (the “Totalgaz Acquisition”), including €30.0 ($33.0) for estimated Acquisition Date working capital. In November 2015, France SAS received €1.1 ($1.2) of cash as a result of the completion of the final working capital amount. The Totalgaz Acquisition was consummated pursuant to the terms of a Share Purchase Agreement dated November 11, 2014, between Total Marketing Services, a subsidiary of global energy company Total, and France SAS. The Totalgaz Acquisition nearly doubles our retail LPG distribution business in France and is consistent with our growth strategies, one of which is to grow our core business through acquisitions. The Totalgaz Acquisition was funded from existing cash balances and a portion of loan proceeds from France SAS’s May 29, 2015, issuance of a €600 term loan under its 2015 Senior Facilities Agreement (see Note 6).
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The Company has accounted for the Totalgaz Acquisition using the acquisition method. At September 30, 2015, the allocation of the purchase price is substantially complete except for the valuation of certain liabilities associated with cylinder deposits and amounts related to deferred income tax assets and liabilities. These amounts are preliminary pending the obtaining of additional information. The Company expects to obtain additional information during the measurement period under GAAP of up to one year from the Acquisition Date as necessary to determine the final allocation of the purchase price. Accordingly, the fair value estimates presented below relating to these items are subject to change.
The components of the Finagaz purchase price allocation are as follows:

Assets acquired: |
Cash | $ | 86.8 |
Accounts receivable (a) | 170.3 |
Prepaid expenses and other current assets | 11.0 |
Property, plant and equipment | 375.6 |
Intangible assets (b) | 91.3 |
Other assets | 21.4 |
Total assets acquired | $ | 756.4 |
Liabilities assumed: |
Accounts payable | 109.2 |
Other current liabilities | 103.5 |
Deferred income taxes | 115.8 |
Other noncurrent liabilities | 117.5 |
Total liabilities assumed | $ | 446.0 |
Goodwill | 186.2 |
Net consideration transferred (including working capital adjustments) | $ | 496.6 |

(a) | Approximates the gross contractual amounts of receivables acquired.

(b) | Represents $79.3 of customer relationships and $12.0 of tradenames ($8.3 of which is subject to amortization), having average amortization periods of 15 years.

We allocated the purchase price of the acquisition to identifiable intangible assets and property, plant and equipment based on estimated fair values as follows:

• | Customer relationships were valued using a multi-period, excess earnings method. Key assumptions used in this method include discount rates, growth rates and cash flow projections. These assumptions are most sensitive and susceptible to change as they require significant management judgment;

• | Tradenames were valued using the relief from royalty method, which estimates our theoretical royalty savings from ownership of the tradenames. Key assumptions used in this method include discount rates, royalty rates, growth rates and sale projections. These assumptions are most sensitive and susceptible to change as they require significant management judgment; and

• | Property, plant and equipment were valued based on estimated fair values primarily using depreciated replacement cost and market value methods.

The excess of the purchase price for the Totalgaz Acquisition over the preliminary fair values of the assets acquired and liabilities assumed has been reflected as goodwill, assigned to the UGI France reportable segment, and results principally from anticipated synergies and value creation resulting from the Company’s combined LPG businesses in France. The goodwill is not deductible for income tax purposes.
The Company recognized $16.1 of direct transaction-related costs associated with the Totalgaz Acquisition during Fiscal 2015, which costs are reflected primarily in operating and administrative expenses on the Consolidated Statements of Income. The
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
acquisition of Finagaz did not have a material impact on the Company’s revenues or net income attributable to UGI for the year ended September 30, 2015.
The following table presents unaudited pro forma revenues, net income attributable to UGI Corporation and earnings per share data for Fiscal 2015 and Fiscal 2014 as if the Totalgaz Acquisition had occurred on October 1, 2013. The unaudited pro forma consolidated information reflects the historical results of Totalgaz SAS and its subsidiaries after giving effect to adjustments directly attributable to the transaction, including depreciation, amortization, interest expense, intercompany eliminations and related income tax effects. The unaudited pro forma net income also reflects the effects of the issuance of the €600 term loan under the 2015 Senior Facilities Agreement and the associated repayment of the term loan outstanding under the 2011 Senior Facilities Agreement as if such transactions had occurred on October 1, 2013. Amounts in the table below exclude the loss associated with the early extinguishment of debt under the 2011 Senior Facilities Agreement (see Note 6):

|  | 2015 |  | 2014
Revenues |  | $ | 7,065.8 |  |  | $ | 8,999.6 |
Net income attributable to UGI Corporation |  | $ | 341.2 |  |  | $ | 385.5 |
Earnings per common share attributable to UGI Corporation shareholders: |  |  |  |
Basic |  | $ | 1.97 |  |  | $ | 2.23 |
Diluted |  | $ | 1.94 |  |  | $ | 2.20 |

The unaudited pro forma consolidated information is not necessarily indicative of the results that would have occurred had the Totalgaz Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results.
In connection with the Totalgaz Acquisition, the Company agreed with the French Competition Authority (the “FCA”) to divest certain assets and investments of Totalgaz SAS and certain assets of Antargaz located in France no later than 15 months subsequent to the Acquisition Date. Following the closing of the Totalgaz Acquisition, two competitors in the French LPG distribution market challenged the decision of the FCA. The competitors’ request for interim measures suspending the effectiveness of the agreed remedies was denied by the supreme administrative court (conseil d’etat). Proceedings on the merits are continuing. While UGI cannot predict the final outcome of these proceedings at this time, we believe the FCA and the Company have strong defenses to the claims and intend to vigorously defend against them.
Other Acquisitions
During Fiscal 2015, Flaga acquired Total’s LPG distribution business in Hungary for total cash consideration of $17.6 and AmeriGas OLP acquired several retail propane distribution businesses for $20.8 in cash.
During Fiscal 2014, Energy Services acquired a retail natural gas marketing business located principally in western Pennsylvania from EQT Energy, LLC, an affiliate of EQT Corporation, for total cash consideration of $20 and AmeriGas OLP acquired several retail propane distribution businesses for $15.7 in cash.
During Fiscal 2013, Flaga acquired BP’s LPG distribution business in Poland for total cash consideration of $36 which Flaga financed with cash proceeds from the issuance of long-term debt; AmeriGas OLP acquired two domestic retail propane distribution businesses for total cash consideration of $20; and Energy Services acquired a non-operating working interest in natural gas acreage in the Marcellus Shale region of Pennsylvania for $23 in cash.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 5 — Short-term Borrowings
Short-term borrowings comprise the following at September 30:

| 2015 |  | 2014
Credit Agreements: |  |  |
AmeriGas Propane | $ | 68.1 |  |  | $ | 109.0 |
UGI International | 0.6 |  |  | 8.0 |
UGI Utilities | 71.7 |  |  | 86.3 |
Energy Services | 30.0 |  |  | — |
Energy Services Receivables Facility | 19.5 |  |  | 7.5 |
Total short-term borrowings | $ | 189.9 |  |  | $ | 210.8 |

AmeriGas Propane
In June 2014, AmeriGas OLP entered into an Amended and Restated Credit Agreement (“AmeriGas Credit Agreement”) with a group of banks which provides for borrowings up to $525 (including a sublimit of $125 for letters of credit) and expires in June 2019. The AmeriGas Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin. Under the AmeriGas Credit Agreement, the applicable margin on base rate borrowings ranges from 0.50% to 1.50%; the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.50%; and the facility fee ranges from 0.30% to 0.45%. The aforementioned margins and facility fees are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (each as defined in the AmeriGas Credit Agreement).
The weighted-average interest rates on AmeriGas OLP borrowings under the AmeriGas Credit Agreement and a prior credit agreement at September 30, 2015 and 2014, were 2.20% and 2.16%, respectively. At September 30, 2015 and 2014, issued and outstanding letters of credit, which reduce available borrowings under these credit agreements, totaled $64.7 and $64.7, respectively.
Restrictive Covenants. The AmeriGas Credit Agreement restricts the incurrence of additional indebtedness and also restricts certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas Credit Agreement requires that AmeriGas OLP and AmeriGas Partners maintain ratios of total indebtedness to EBITDA, as defined, below certain thresholds. In addition, the Partnership must maintain a minimum ratio of EBITDA to interest expense, as defined and as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result therefrom, AmeriGas OLP is permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter.
UGI International
UGI France
On May 29, 2015, France SAS entered into a new five-year Senior Facilities Agreement with a consortium of banks (“2015 Senior Facilities Agreement”), consisting of a €600 variable-rate term loan and a €60 revolving credit facility (“2015 Senior Facilities Agreement”). The 2015 Senior Facilities Agreement revolving credit facility can be used by each of France SAS’s wholly owned subsidiaries, Antargaz and Finagaz, for up to €30 each. Borrowings under the revolving credit facility bear interest at market rates (one-, two-, three-, or six-month euribor) plus a margin. Such margin is 2.35% through March 31, 2016 and thereafter at a margin that ranges from 1.45% to 2.55% based upon France SAS’s ratio of net debt to EBITDA, as defined in the 2015 Senior Facilities Agreement. Refer to Note 6 for further discussion on the terms of the 2015 Senior Facilities Agreement.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Flaga
At September 30, 2015, Flaga had one principal working capital facility (the “Flaga Multi-Currency Working Capital Facility”) and, prior to its expiration on September 30, 2015, also had a euro-denominated working capital facility that provided for borrowings and issuances of guarantees totaling €12 (the “Euro Working Capital Facility”). The Flaga Multi-Currency Working Capital Facility comprises a €46 multi-currency working capital facility which includes an uncommitted €6 overdraft facility. There were no borrowings outstanding under the Flaga Multi-Currency Working Capital Facility at September 30, 2015, and no borrowings outstanding under either facility at September 30, 2014. Flaga also has certain in-country uncommitted overdraft facilities which it uses, from time to time, to fund short-term working capital needs. At September 30, 2015 and 2014, borrowings outstanding under these overdraft facilities totaled €0.5 ($0.6) and €6.3 ($8.0), respectively.
Borrowings under the Flaga Multi-Currency Working Capital Facility (prior to its termination in October 2015 as described below) and the Euro Working Capital Facility (prior to its expiration on September 30, 2015) generally bore interest at market rates (a daily euro-based rate or three-month euribor rates) plus margins. Issued and outstanding letters of credit, which reduce available borrowings under these agreements, totaled €19.9 ($22.2) and €32.3 ($40.8) at September 30, 2015 and 2014, respectively.
In October 2015, Flaga entered into a €100.8 Credit Facility Agreement (“Flaga Credit Facility Agreement”) with a bank. The Flaga Credit Facility Agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility, a €25 guarantee facility and a €45.8 term loan facility. The Flaga Credit Facility Agreement revolving credit facility borrowings bear interest at market rates (generally one, three or six-month euribor rates) plus margins. The margins on revolving facility borrowings, which range from 1.45% to 3.65%, are based upon the actual currency borrowed and certain consolidated equity, return on assets and debt to EBITDA ratios, as defined in the Flaga Credit Facility Agreement. Facility fees on the unused amount of the revolving credit facility are 30% of the lowest applicable margin. The Flaga Credit Facility Agreement terminates in October 2020. Concurrent with Flaga entering into the Flaga Credit Facility Agreement, the Flaga Multi-Currency Working Capital Facility was terminated.
Restrictive Covenants and Guarantees. The 2015 Senior Facilities Agreement restricts the ability of France SAS and its subsidiaries to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets. Refer to Note 6 for further discussion on the restrictions of the 2015 Senior Facilities Agreement.
Borrowings under the Flaga revolving credit facilities are guaranteed by UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending banks may accelerate repayment of the debt.
UGI Utilities
On March 27, 2015, UGI Utilities entered into an unsecured revolving credit agreement (the “2015 UGI Utilities Credit Agreement”) with a group of banks providing for borrowings up to $300 (including a $100 sublimit for letters of credit). Concurrently with entering into the 2015 UGI Utilities Credit Agreement, UGI Utilities terminated its then-existing $300 revolving credit agreement dated as of May 25, 2011. Under the 2015 UGI Utilities Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The 2015 UGI Utilities Credit Agreement is scheduled to expire in March 2020.
Issued and outstanding letters of credit, which reduce available borrowings under the 2015 UGI Utilities Credit Agreement, totaled $2.0 at September 30, 2015. At September 30, 2014, issued and outstanding letters of credit under the predecessor credit agreement totaled $2.0. The weighted average interest rate on borrowings under the 2015 UGI Utilities Credit Agreement at September 30, 2015, was 1.07%.
Restrictive Covenants. The 2015 UGI Utilities Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
Energy Services
Credit Agreement. Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $240 (including a $50 sublimit for letters of credit) which expires in June 2016. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries. Energy Services may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not exceed 2.25 to 1.00.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Borrowings under the Energy Services Credit Agreement bear interest at either (i) a rate derived from LIBOR (the “LIBO Rate”) plus 2.5% or (ii) the Alternate Base Rate plus 1.5%. The Alternate Base Rate (as defined in the Energy Services Credit Agreement) is generally the greater of (a) the Agent Bank’s prime rate, (b) the federal funds rate plus 0.50% and (c) the one-month LIBO Rate plus 1.0%. The weighted-average interest rate on Energy Services Credit Agreement borrowings at September 30, 2015 was 2.75%. The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services.
Restrictive Covenants. The Energy Services Credit Agreement restricts the ability of Energy Services to dispose of assets, effect certain consolidations or mergers, incur indebtedness and guaranty obligations, create liens, make acquisitions or investments, make certain dividend or other distributions and make any material changes to the nature of its businesses. In addition, the Energy Services Credit Agreement requires Energy Services to not exceed a ratio of Consolidated Total Indebtedness, as defined, to Consolidated EBITDA, as defined; a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense, as defined; a maximum ratio of Consolidated Total Indebtedness to Consolidated Total Capitalization, as defined, at any time when Consolidated Total Indebtedness is greater than $250; and a minimum Consolidated Net Worth, as defined, of $200.
Accounts Receivable Securitization Facility. Energy Services has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2016. The Receivables Facility, as amended, provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November to April, and up to $75 of eligible receivables during the period May to October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a major bank and, prior to October 1, 2013, a commercial paper conduit of the bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank or, prior to October 1, 2013, the commercial paper conduit, remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank or the commercial paper conduit. The Company records interest expense on amounts owed to the bank or the commercial paper conduit. Energy Services continues to service, administer and collect trade receivables on behalf of the bank.
During Fiscal 2015, Fiscal 2014 and Fiscal 2013, Energy Services transferred trade receivables totaling $1,037.8, $1,260.6 and $975.3, respectively, to ESFC. During Fiscal 2015, Fiscal 2014 and Fiscal 2013, ESFC sold an aggregate $306.5, $354.0 and $291.0, respectively, of undivided interests in its trade receivables to the bank or the commercial paper conduit. At September 30, 2015, the outstanding balance of ESFC trade receivables was $44.1 of which $19.5 was sold to the bank. At September 30, 2014, the outstanding balance of ESFC trade receivables was $46.4 of which $7.5 amount was sold to the bank. Losses on sales of receivables to the bank or the commercial paper conduit during Fiscal 2015, Fiscal 2014 and Fiscal 2013, which amounts are included in interest expense on the Consolidated Statements of Income, totaled $0.6, $0.6 and $0.7, respectively.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 6 — Long-term Debt
Long-term debt comprises the following at September 30:

| 2015 |  | 2014
AmeriGas Propane: |  |  |
AmeriGas Partners Senior Notes: |  |  |
7.00%, due May 2022 | $ | 980.8 |  |  | $ | 980.8 |
6.75%, due May 2020 | 550.0 |  |  | 550.0 |
6.50%, due May 2021 | 270.0 |  |  | 270.0 |
6.25%, due August 2019 | 450.0 |  |  | 450.0 |
HOLP Senior Secured Notes | 21.0 |  |  | 26.5 |
Other | 11.7 |  |  | 14.4 |
Total AmeriGas Propane | 2,283.5 |  |  | 2,291.7 |
UGI International: |  |  |
France SAS Senior Facilities term loan, due through April 2020 | 670.7 |  |  | — |
Antargaz Senior Facilities term loan | — |  |  | 432.0 |
Flaga term loan, due September 2018 | 59.1 |  |  | — |
Flaga term loan | — |  |  | 52.0 |
Flaga term loan, due through August 2016 | 29.8 |  |  | 50.5 |
Flaga term loan, due October 2016 | 21.4 |  |  | 24.1 |
Other | 1.8 |  |  | 6.4 |
Total UGI International | 782.8 |  |  | 565.0 |
UGI Utilities: |  |  |
Senior Notes: |  |  |
5.75%, due September 2016 | 175.0 |  |  | 175.0 |
4.98%, due March 2044 | 175.0 |  |  | 175.0 |
6.21%, due September 2036 | 100.0 |  |  | 100.0 |
Medium-Term Notes: |  |  |
5.16%, due May 2015 | — |  |  | 20.0 |
7.37%, due October 2015 | 22.0 |  |  | 22.0 |
5.64%, due December 2015 | 50.0 |  |  | 50.0 |
6.17%, due June 2017 | 20.0 |  |  | 20.0 |
7.25%, due November 2017 | 20.0 |  |  | 20.0 |
5.67%, due January 2018 | 20.0 |  |  | 20.0 |
6.50%, due August 2033 | 20.0 |  |  | 20.0 |
6.13%, due October 2034 | 20.0 |  |  | 20.0 |
Total UGI Utilities | 622.0 |  |  | 642.0 |
Other | 11.5 |  |  | 12.1 |
Total long-term debt | 3,699.8 |  |  | 3,510.8 |
Less: current maturities | (258.0 | ) |  | (77.2 | )
Total long-term debt due after one year | $ | 3,441.8 |  |  | $ | 3,433.6 |

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Scheduled principal repayments of long-term debt due in fiscal years 2016 to 2020 follow.

| 2016 |  | 2017 |  | 2018 |  | 2019 |  | 2020
AmeriGas Propane | $ | 9.2 |  |  | $ | 6.1 |  |  | $ | 5.3 |  |  | $ | 455.0 |  |  | $ | 554.3 |
UGI Utilities | 247.0 |  |  | 20.0 |  |  | 40.0 |  |  | — |  |  | — |
UGI International (a) | 30.5 |  |  | 21.8 |  |  | 126.7 |  |  | 67.2 |  |  | 536.6 |
Other | 0.7 |  |  | 0.7 |  |  | 0.8 |  |  | 0.8 |  |  | 0.9 |
Total | $ | 287.4 |  |  | $ | 48.6 |  |  | $ | 172.8 |  |  | $ | 523.0 |  |  | $ | 1,091.8 |

(a) Amounts relating to Flaga’s €26.7 ($29.8) term loan due August 2016 and €19.1 ($21.4) term loan due in October 2016, both of which were refinanced on a long-term basis in October 2015, are included in the table above (see UGI International - Flaga below).
AmeriGas Propane
In order to finance the cash portion of AmeriGas Partners’ January 2012 acquisition of Energy Transfer Partner, L.P.’s (“ETP”) retail propane distribution business (“the Heritage Acquisition”), AmeriGas Finance Corp. and AmeriGas Finance LLC, wholly owned finance subsidiaries of AmeriGas Partners (the “Issuers”), issued $550 principal amount of 6.75% Notes due May 2020 and $1,000 principal amount of 7.00% Notes due May 2022. The 6.75% Notes and the 7.00% Notes are fully and unconditionally guaranteed on a senior unsecured basis by AmeriGas Partners. The Issuers have the right to redeem the 6.75% Notes, in whole or in part, at any time on or after May 20, 2016, and to redeem the 7.00% Notes, in whole or in part, at any time on or after May 20, 2017, subject to certain restrictions. A premium applies to redemptions of the 6.75% Notes and 7.00% Notes through May 2018 and May 2020, respectively. The 6.75% Notes and the 7.00% Notes and the guarantees rank equal in right of payment with all of AmeriGas Partners’ existing Senior Notes. In connection with the Heritage Acquisition, AmeriGas Partners, AmeriGas Finance Corp., AmeriGas Finance LLC and UGI entered into a Contingent Residual Support Agreement (“CRSA”) with ETP pursuant to which ETP will provide contingent, residual support of $1,500 of debt (“Supported Debt” as defined in the CRSA).
The Partnership’s total long-term debt at September 30, 2015 and 2014, includes $21.0 and $26.5, respectively, of HOLP Senior Secured Notes including unamortized premium of $2.5 and $3.1, respectively. The face interest rates on the HOLP Notes ranged from 7.89% to 8.87% with an effective interest rate of 6.75%. The HOLP Senior Secured Notes are collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash.
Restrictive Covenants. The AmeriGas Partners Senior Notes restrict the ability of the Partnership and AmeriGas OLP to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets. Under the AmeriGas Partners Senior Notes Indentures, AmeriGas Partners is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. At September 30, 2015, these restrictions did not limit the amount of Available Cash. See Note 15 for the definition of Available Cash included in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. (“Partnership Agreement”).
The HOLP Senior Secured Notes contain restrictive covenants including the maintenance of financial covenants and limitations on the disposition of assets, changes in ownership, additional indebtedness, restrictive payments and the creation of liens. The financial covenants require AmeriGas OLP to maintain a ratio of Consolidated Funded Indebtedness to Consolidated EBITDA (as defined) below certain thresholds and to maintain a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense (as defined).
UGI International
UGI France
As previously mentioned in Note 5, on May 29, 2015, France SAS borrowed €600 ($659.6) under its Senior Facilities Agreement with a consortium of banks (the “2015 Senior Facilities Agreement”). France SAS entered into the 2015 Senior Facilities Agreement on April 30, 2015, in anticipation of its then-pending acquisition of Totalgaz, which was consummated on May 29, 2015 (see Note 4). The 2015 Senior Facilities Agreement consists of a €600 variable-rate term loan and a €60 revolving credit facility. The term loan proceeds were used (1) to fund a portion of the Totalgaz Acquisition, including related fees and expenses; (2) to make a capital
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
contribution from France SAS to its wholly owned subsidiary, AGZ Holding, to prepay €342 principal amount, plus accrued interest, outstanding under Antargaz’ 2011 Senior Facilities Agreement due March 2016 (the “2011 Senior Facilities Agreement”); (3) to settle Antargaz’ existing pay-fixed, receive-variable interest rate swaps associated with the 2011 Senior Facilities Agreement; and (4) for general corporate purposes. Principal amounts outstanding under the 2015 Senior Facilities Agreement term loan are due as follows: €60 due April 30, 2018; €60 due April 30, 2019; and €480 due April 30, 2020. As a result of prepaying the term loan outstanding under the 2011 Senior Facilities Agreement and concurrently settling the associated pay-fixed, receive-variable interest rate swaps, we recorded a pre-tax loss of $10.3 comprising a $9.0 loss on interest rate swaps and the write-off of $1.3 of debt issuance costs. These amounts are included in interest expense on the Consolidated Statements of Income.
Borrowings under the 2015 Senior Facilities Agreement €600 term loan and the €60 revolving credit facility bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate, which euribor rate has a floor of zero. The margin on such borrowings (which ranges from 1.60% to 2.70% for the term loan) are dependent upon the ratio of France SAS’s consolidated total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement. Through March 31, 2016, the margin has been set at 2.50%. France SAS has entered into pay-fixed, receive-variable interest rate swaps through April 30, 2019, to generally fix the underlying euribor rate at 0.18% (assuming such underlying euribor rate is not less than zero). At September 30, 2015, the effective interest rate on the 2015 Senior Facilities Agreement term loan was approximately 2.70%.
Flaga
In September 2015, Flaga terminated its then-existing $52 U.S. dollar-denominated variable-rate term loan due September 2016 and concurrently entered into a $59.1 U.S. dollar-denominated variable-rate term loan with the same bank. The $59.1 term loan matures in September 2018. Because the cash flows from the termination of the $52 term loan and the concurrent issuance of the $59.1 term loan were with the same bank, such cash flows have been reflected “net” in the financing activities section of the Fiscal 2015 Consolidated Statement of Cash Flows. Also in September 2015, Flaga prepaid its €13.3 ($14.9) euro-based term loan due September 2016. The $59.1 term loan bears interest at a one-month LIBOR rate plus a margin of 1.125%. Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the $59.1 term loan, by entering into a cross-currency swap arrangement with a bank. At September 30, 2015, the effective interest rate on the $59.1 term loan was 0.87%. At September 30, 2014, the effective interest rate on the $52 term loan was 1.82%.
Prior to its refinancing in October 2015, at September 30, 2015, Flaga had a €19.1 ($21.4) euro-based variable-rate term loan scheduled to mature in October 2016. The €19.1 term loan bore interest at three-month euribor rates plus a margin. The margin on such borrowings ranged from 1.175% to 2.525% and was based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined. Flaga had effectively fixed the euribor component of the interest rate on this term loan at 1.79% by entering into an interest rate swap agreement. The effective interest rates on this term loan at September 30, 2015 and 2014, were 3.40% and 3.40%, respectively.
Prior to its refinancing in October 2015, at September 30, 2015, Flaga also had a €26.7 ($29.8) euro-based variable-rate term loan scheduled to mature in August 2016, and prior to its refinancing in September 2015, also had a €13.3 euro-based variable-rate term loan due September 2016. These term loans bore interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus margins. The margins on such borrowings ranged from 1.125% to 2.275% and were based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined. Flaga had effectively fixed the euribor component of the interest rates on these term loans through September 2016 at 2.68% by entering into interest rate swap agreements. The effective interest rates on these term loans outstanding at September 30, 2015 and 2014, were 4.21% and 4.25%, respectively. Because the €26.7 term loan was refinanced on a long-term basis in October 2015, we have classified this debt as long-term on the September 30, 2015, Consolidated Balance Sheet.
As previously mentioned in Note 5, in October 2015 Flaga entered into the Flaga Credit Facility Agreement which includes, among other things, a €45.8 variable-rate term loan facility. In October 2015, Flaga used proceeds from the issuance of the €45.8 term loan to refinance the previously mentioned €19.1 ($21.4) term loan due October 2016, and the previously mentioned €26.7 ($29.8) term loan due August 2016. The €45.8 term loan matures in October 2020. The €45.8 term bears interest at three-month euribor rates, plus a margin. The margin on such borrowings ranges from 0.40% to 1.80% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined. Flaga expects to enter into pay-fixed, receive-variable interest rate swaps that will effectively fix the underlying euribor rate on the term loan borrowings.
Restrictive Covenants and Guarantees. The 2015 Senior Facilities Agreement restricts the ability of France SAS to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires France SAS and its consolidated subsidiaries to maintain a ratio of total net debt to EBITDA, each as defined in the 2015
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Senior Facilities Agreement, that shall not exceed (a) 3.75 to 1.00 from the closing date of the Totalgaz Acquisition to September 30, 2015, and (b) 3.50 to 1.00 thereafter, as determined semiannually. France SAS will generally be permitted to make restricted payments, such as dividends, if no event of default exists or would exist upon payment of such dividend.
The Flaga term loans and associated interest rate and cross-currency swap agreements are guaranteed by UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending banks may accelerate repayment of the debt.
UGI Utilities
In March 2014, UGI Utilities issued in a private placement $175 of 4.98% Senior Notes due March 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 of borrowings under UGI Utilities’ then-existing 364-day Term Loan Credit Agreement.
Restrictive Covenants. 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 requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
Restricted Net Assets
At September 30, 2015, the amount of net assets of UGI’s consolidated subsidiaries that was restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $1,700.
Note 7 — Income Taxes
Income before income taxes comprises the following:

| 2015 |  | 2014 |  | 2013
Domestic | $ | 552.3 |  |  | $ | 699.2 |  |  | $ | 494.1 |
Foreign | 39.5 |  |  | 68.6 |  |  | 96.3 |
Total income before income taxes | $ | 591.8 |  |  | $ | 767.8 |  |  | $ | 590.4 |

The provisions for income taxes consist of the following:

| 2015 |  | 2014 |  | 2013
Current expense (benefit): |  |  |  |  |
Federal | $ | 97.1 |  |  | $ | 102.4 |  |  | $ | 53.3 |
State | 32.2 |  |  | 30.7 |  |  | 25.1 |
Foreign | 36.0 |  |  | 37.0 |  |  | 37.3 |
Investment tax credit | (1.2 | ) |  | (1.6 | ) |  | (1.6 | )
Total current expense | 164.1 |  |  | 168.5 |  |  | 114.1 |
Deferred expense (benefit): |  |  |  |  |
Federal | 28.1 |  |  | 61.9 |  |  | 54.6 |
State | 2.9 |  |  | 7.8 |  |  | (0.7 | )
Foreign | (17.0 | ) |  | (2.7 | ) |  | (4.9 | )
Investment tax credit amortization | (0.3 | ) |  | (0.3 | ) |  | (0.3 | )
Total deferred expense | 13.7 |  |  | 66.7 |  |  | 48.7 |
Total income tax expense | $ | 177.8 |  |  | $ | 235.2 |  |  | $ | 162.8 |

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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Federal income taxes for Fiscal 2015, Fiscal 2014 and Fiscal 2013 are net of foreign tax credits of $63.0, $12.1 and $34.9, respectively.
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:

| 2015 |  | 2014 |  | 2013
U.S. federal statutory tax rate | 35.0 | % |  | 35.0 | % |  | 35.0 | %
Difference in tax rate due to: |  |  |  |  |
Noncontrolling interests not subject to tax | (7.9 | ) |  | (9.0 | ) |  | (8.7 | )
State income taxes, net of federal benefit | 3.3 |  |  | 3.4 |  |  | 3.4 |
Valuation allowance adjustments | 0.8 |  |  | — |  |  | (0.5 | )
Effects of foreign operations | 0.2 |  |  | 1.0 |  |  | (1.8 | )
Other, net | (1.4 | ) |  | 0.2 |  |  | 0.2 |
Effective tax rate | 30.0 | % |  | 30.6 | % |  | 27.6 | %

In December 2013, the French Parliament approved the Finance Bill for 2014 and amended the Finance Bill for 2013 (collectively, the “Finance Bills”). Among other things, the Finance Bills limit UGI France’s ability to deduct certain interest expense for income tax purposes and temporarily increases the corporate surtax rate for a period of two years. Based upon our review of the Finance Bills and interpretive guidance, provisions of the Finance Bills associated with the deductibility of certain interest expense at UGI France apply retroactively to such interest expense incurred during Fiscal 2013. In December 2013, the Company recorded additional income taxes of $5.7 to reflect the effects of the retroactive provisions of the Finance Bills and is included in effects of foreign operations in the effective tax rate table above.
Earnings of the Company’s foreign subsidiaries are generally subject to U.S. taxation upon repatriation to the U.S. and the Company’s tax provision reflects the related incremental U.S. tax except for certain foreign subsidiaries whose unremitted earnings are considered to be indefinitely reinvested. At September 30, 2015, unremitted earnings of foreign subsidiaries of approximately $50.8 were deemed to be indefinitely reinvested. No deferred tax liability has been recognized with regard to the remittance of such earnings. Because of the availability of U.S. foreign tax credits, it is likely no U.S. tax would be due if such earnings were repatriated.
Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2015, Fiscal 2014 and Fiscal 2013, the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $1.5, $2.0 and $1.5, respectively.
Deferred tax liabilities (assets) comprise the following at September 30:
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

| 2015 |  | 2014
Excess book basis over tax basis of property, plant and equipment | $ | 798.4 |  |  | $ | 675.7 |
Investment in AmeriGas Partners | 321.4 |  |  | 325.1 |
Intangible assets and goodwill | 87.1 |  |  | 53.0 |
Utility regulatory assets | 117.4 |  |  | 110.0 |
Foreign currency translation adjustment | 0.1 |  |  | — |
Other | 8.8 |  |  | 3.5 |
Gross deferred tax liabilities | 1,333.2 |  |  | 1,167.3 |
Pension plan liabilities | (59.1 | ) |  | (40.6 | )
Employee-related benefits | (57.6 | ) |  | (48.8 | )
Operating loss carryforwards | (32.5 | ) |  | (27.9 | )
Foreign tax credit carryforwards | (113.8 | ) |  | (47.8 | )
Utility regulatory liabilities | (24.0 | ) |  | (14.8 | )
Foreign currency translation adjustment | — |  |  | (14.1 | )
Derivative instruments | (11.4 | ) |  | (11.0 | )
Other | (23.4 | ) |  | (13.0 | )
Gross deferred tax assets | (321.8 | ) |  | (218.0 | )
Deferred tax assets valuation allowance | 131.3 |  |  | 59.2 |
Net deferred tax liabilities | $ | 1,142.7 |  |  | $ | 1,008.5 |

At September 30, 2015, foreign net operating loss carryforwards principally relating to Flaga and certain operations of UGI France totaled $59.4 and $23.4, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $158.5 and expire through 2035. We also have operating loss carryforwards of $12.1 for certain operations of AmeriGas Propane that expire through 2034. At September 30, 2015, deferred tax assets relating to operating loss carryforwards include $13.0 for Flaga, $8.0 for UGI France, $0.6 for UGI International Holdings BV, $4.7 for AmeriGas Propane and $8.7 for certain other subsidiaries. A valuation allowance of $15.6 has been provided for deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries because, on a state reportable basis, it is more likely than not that these assets will expire unused. A valuation allowance of $11.0 was also provided for deferred tax assets related to certain operations of UGI France, Flaga and UGI International Holdings BV. Operating activities and tax deductions related to the exercise of non-qualified stock options contributed to the state net operating losses disclosed above. We first recognize the utilization of state net operating losses from operations (which exclude the impact of tax deductions for exercises of non-qualified stock options) to reduce income tax expense. Then, to the extent state net operating loss carryforwards, if realized, relate to non-qualified stock option deductions, the resulting benefits will be credited to UGI Corporation stockholders’ equity. The table of deferred tax assets and liabilities do not include $6.5 for Fiscal 2015 and $6.7 for Fiscal 2014 of deferred tax assets and associated valuation allowance for unrealized state tax benefits for equity compensation deductions.
We have foreign tax credit carryforwards of approximately $113.7 expiring through 2025 resulting from the actual and planned repatriation of UGI France’s accumulated earnings since acquisition which are includable in U.S. taxable income. Because we expect that these credits will expire unused, a valuation allowance has been provided for the entire foreign tax credit carryforward amount. The valuation allowance for all deferred tax assets increased by $72.1 in Fiscal 2015 due to increases in unusable foreign tax credits of $66.0 and foreign operating loss carryforwards of $8.0, partially offset by decreases in unusable state operating loss tax benefits of $1.9.
We conduct business and file tax returns in the U.S., numerous states, local jurisdictions and in France and certain other European countries. Our U.S. federal income tax returns are settled through the 2011 tax year, our French tax returns are settled through the 2011 tax year, our Austrian tax returns are settled through 2012 and our other European tax returns are effectively settled for various years from 2006 to 2013. State and other income tax returns in the U.S. are generally subject to examination for a period of three to five years after the filing of the respective returns.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
As of September 30, 2015, we have unrecognized income tax benefits totaling $3.2 including related accrued interest of $0.1. If these unrecognized tax benefits were subsequently recognized, $3.2 would be recorded as a benefit to income taxes on the Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. There is no material change expected in unrecognized tax benefits and related interest in the next twelve months.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

| 2015 |  | 2014 |  | 2013
Unrecognized tax benefits - beginning of year | $ | 2.4 |  |  | $ | 3.4 |  |  | $ | 2.9 |
Additions for tax positions of the current year | 0.9 |  |  | 0.7 |  |  | 0.7 |
Additions for tax positions taken in prior years | 0.5 |  |  | — |  |  | — |
Settlements with tax authorities | (0.6 | ) |  | (1.7 | ) |  | (0.2 | )
Unrecognized tax benefits - end of year | $ | 3.2 |  |  | $ | 2.4 |  |  | $ | 3.4 |

Note 8 — Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans
In the U.S., we sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). U.S. Pension Plan benefits are based on years of service, age and employee compensation.
We also provide postretirement health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, UGI France employees are covered by certain defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the UGI France plans, such amounts are not material.
The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the U.S. Pension Plan and the UGI France pension plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 2015 and 2014. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

| Pension Benefits |  | Other Postretirement Benefits
| 2015 |  | 2014 |  | 2015 |  | 2014
Change in benefit obligations: |  |  |  |  |  |  |
Benefit obligations — beginning of year | $ | 573.6 |  |  | $ | 516.5 |  |  | $ | 21.3 |  |  | $ | 19.7 |
Service cost | 10.0 |  |  | 9.4 |  |  | 0.7 |  |  | 0.5 |
Interest cost | 25.5 |  |  | 26.1 |  |  | 0.8 |  |  | 0.9 |
Actuarial loss (gain) | 14.4 |  |  | 46.8 |  |  | (2.7 | ) |  | 1.3 |
Plan amendments | (0.6 | ) |  | — |  |  | — |  |  | — |
Curtailment | (0.8 | ) |  | — |  |  | — |  |  | — |
Totalgaz acquisition | 21.3 |  |  | — |  |  | 6.8 |  |  | — |
Foreign currency | (4.4 | ) |  | (2.4 | ) |  | (0.7 | ) |  | (0.3 | )
Benefits paid | (24.3 | ) |  | (22.8 | ) |  | (0.8 | ) |  | (0.8 | )
Benefit obligations — end of year | $ | 614.7 |  |  | $ | 573.6 |  |  | $ | 25.4 |  |  | $ | 21.3 |
Change in plan assets: |  |  |  |  |  |  |
Fair value of plan assets — beginning of year | $ | 459.4 |  |  | $ | 415.3 |  |  | $ | 12.8 |  |  | $ | 11.7 |
Actual gain (loss) on plan assets | 1.1 |  |  | 47.9 |  |  | (0.1 | ) |  | 1.4 |
Foreign currency | (0.4 | ) |  | (1.2 | ) |  | — |  |  | — |
Employer contributions | 11.9 |  |  | 20.2 |  |  | 0.6 |  |  | 0.5 |
Totalgaz acquisition | 6.1 |  |  | — |  |  | — |  |  | — |
Benefits paid | (24.3 | ) |  | (22.8 | ) |  | (0.8 | ) |  | (0.8 | )
Fair value of plan assets — end of year | $ | 453.8 |  |  | $ | 459.4 |  |  | $ | 12.5 |  |  | $ | 12.8 |
Funded status of the plans — end of year | $ | (160.9 | ) |  | $ | (114.2 | ) |  | $ | (12.9 | ) |  | $ | (8.5 | )
Assets (liabilities) recorded in the balance sheet: |  |  |  |  |  |  |
Assets in excess of liabilities — included in other noncurrent assets | $ | — |  |  | $ | — |  |  | $ | 4.0 |  |  | $ | 4.0 |
Unfunded liabilities — included in other current liabilities | — |  |  | (1.1 | ) |  | — |  |  | (0.1 | )
Unfunded liabilities — included in other noncurrent liabilities | (160.9 | ) |  | (113.1 | ) |  | (16.9 | ) |  | (12.4 | )
Net amount recognized | $ | (160.9 | ) |  | $ | (114.2 | ) |  | $ | (12.9 | ) |  | $ | (8.5 | )
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): |  |  |  |  |  |  |
Prior service credit | $ | (0.6 | ) |  | $ | (0.1 | ) |  | $ | (0.1 | ) |  | $ | (0.1 | )
Net actuarial loss | 22.5 |  |  | 20.8 |  |  | 0.7 |  |  | 0.8 |
Total | $ | 21.9 |  |  | $ | 20.7 |  |  | $ | 0.6 |  |  | $ | 0.7 |
Amounts recorded in regulatory assets and liabilities (pre-tax): |  |  |  |  |  |  |
Prior service cost (credit) | $ | 1.6 |  |  | $ | 1.9 |  |  | $ | (2.9 | ) |  | $ | (3.6 | )
Net actuarial loss | 138.4 |  |  | 107.4 |  |  | 2.3 |  |  | 2.6 |
Total | $ | 140.0 |  |  | $ | 109.3 |  |  | $ | (0.6 | ) |  | $ | (1.0 | )

In Fiscal 2016, we estimate that we will amortize approximately $11.0 of net actuarial losses, primarily associated with the U.S. Pension Plan, and $0.2 of net prior service credits from UGI stockholders’ equity and regulatory assets into retiree benefit cost.
Actuarial assumptions for our U.S. plans are described below. Assumptions for the UGI France plans are based upon market conditions in France, Belgium and the Netherlands. The discount rate assumption was determined by selecting a hypothetical
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the plans’ benefit payments. The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).

| Pension Plan |  |  | Other Postretirement Benefits |
| 2015 |  | 2014 |  | 2013 |  |  | 2015 |  | 2014 |  | 2013 |
Weighted-average assumptions: |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate - benefit obligations | 4.60 | % |  | 4.60 | % |  | 5.20 | % |  |  | 4.70 | % |  | 4.60 | % |  | 5.10% - 5.40% |  |
Discount rate - benefit cost | 4.60 | % |  | 5.20 | % |  | 4.20 | % |  |  | 4.60 | % |  | 5.10% - 5.40% |  |  | 4.10% - 4.30% |  |
Expected return on plan assets | 7.75 | % |  | 7.75 | % |  | 7.75 | % |  |  | 5.00 | % |  | 5.00 | % |  | 5.00 | % |
Rate of increase in salary levels | 3.25 | % |  | 3.25 | % |  | 3.25 | % |  |  | 3.25 | % |  | 3.25 | % |  | 3.25 | % |

The ABOs for the U.S. Pension Plan were $523.7 and $499.1 as of September 30, 2015 and 2014, respectively.
Net periodic pension expense and other postretirement benefit cost includes the following components:

| Pension Benefits |  | Other Postretirement Benefits
| 2015 |  | 2014 |  | 2013 |  | 2015 |  | 2014 |  | 2013
Service cost | $ | 10.0 |  |  | $ | 9.4 |  |  | $ | 11.3 |  |  | $ | 0.7 |  |  | $ | 0.5 |  |  | $ | 0.6 |
Interest cost | 25.5 |  |  | 26.1 |  |  | 23.8 |  |  | 0.8 |  |  | 0.9 |  |  | 0.9 |
Expected return on assets | (32.2 | ) |  | (29.7 | ) |  | (27.8 | ) |  | (0.6 | ) |  | (0.6 | ) |  | (0.5 | )
Curtailment gain | (0.8 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Amortization of: |  |  |  |  |  |  |  |  |  |  |
Prior service cost (benefit) | 0.3 |  |  | 0.3 |  |  | 0.3 |  |  | (0.5 | ) |  | (0.5 | ) |  | (0.3 | )
Actuarial loss | 10.0 |  |  | 7.7 |  |  | 15.1 |  |  | 0.1 |  |  | — |  |  | 0.4 |
Net benefit cost | 12.8 |  |  | 13.8 |  |  | 22.7 |  |  | 0.5 |  |  | 0.3 |  |  | 1.1 |
Change in associated regulatory liabilities | — |  |  | — |  |  | — |  |  | 3.7 |  |  | 3.7 |  |  | 3.3 |
Net benefit cost after change in regulatory liabilities | $ | 12.8 |  |  | $ | 13.8 |  |  | $ | 22.7 |  |  | $ | 4.2 |  |  | $ | 4.0 |  |  | $ | 4.4 |

The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2015, Fiscal 2014 and Fiscal 2013, we made cash contributions to the U.S. Pension Plan of $11.1, $19.2 and $22.4 respectively. The minimum required contributions in Fiscal 2016 are not expected to be material.
UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. The required contributions to the VEBA during Fiscal 2016, if any, are not expected to be material.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Expected payments for pension and other postretirement welfare benefits are as follows:

| Pension Benefits |  | Other Postretirement Benefits
Fiscal 2016 | $ | 27.5 |  |  | $ | 1.2 |
Fiscal 2017 | $ | 28.1 |  |  | $ | 1.1 |
Fiscal 2018 | $ | 29.2 |  |  | $ | 1.1 |
Fiscal 2019 | $ | 32.3 |  |  | $ | 1.1 |
Fiscal 2020 | $ | 36.1 |  |  | $ | 1.1 |
Fiscal 2021 - 2025 | $ | 183.1 |  |  | $ | 5.5 |

The assumed domestic health care cost trend rates at September 30 are as follows:

| 2015 |  | 2014
Health care cost trend rate assumed for next year | 7.5 | % |  | 7.0 | %
Rate to which the cost trend rate is assumed to decline (ultimate trend rate) | 5.0 | % |  | 5.0 | %
Fiscal year that the rate reaches the ultimate trend rate | 2026 |  |  | 2019 |

A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 2014 other postretirement benefit cost or September 30, 2015, other postretirement benefit ABO.
We also sponsor unfunded and non-qualified supplemental executive retirement plans (“Supplemental Defined Benefit Plans”). At September 30, 2015 and 2014, the PBOs of these plans, including obligations for amounts held in grantor trusts, were $40.1 and $38.4, respectively. We recorded pre-tax costs for these plans of $2.3 in Fiscal 2015, $2.6 in Fiscal 2014 and $3.0 in Fiscal 2013. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $10.1 and $10.2 at September 30, 2015 and 2014, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $1.0 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2016. During Fiscal 2014 and Fiscal 2013, the Company made payments with respect to the Supplemental Defined Benefit Plans totaling $0.3 and $21.6, respectively, including $21.0 in Fiscal 2013 to fund self-directed grantor trusts established by the Company for participants who chose to defer their Supplemental Defined Benefit Plan payment upon retirement. There were no such payments made in Fiscal 2015. The total fair value of the grantor trust investment assets associated with the Supplemental Defined Benefit Plans, which are included in other assets on the Consolidated Balance Sheets, totaled $26.1 and $26.6 at September 30, 2015 and 2014, respectively.
U.S. Pension Plan and VEBA Assets
The assets of the U.S. Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the U.S. Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock. Assets associated with the UGI France plans are excluded from the disclosures in the tables below as such assets are not material.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows:
U.S. Pension Plan

| Actual |  | Target Asset Allocation |  | Permitted Range
| 2015 |  | 2014 |  |
Equity investments: |  |  |  |  |  |  |
Domestic | 56.2 | % |  | 55.6 | % |  | 52.5 | % |  | 40.0% - 65.0%
International | 10.2 | % |  | 11.3 | % |  | 12.5 | % |  | 7.5% - 17.5%
Total | 66.4 | % |  | 66.9 | % |  | 65.0 | % |  | 60.0% - 70.0%
Fixed income funds & cash equivalents | 33.6 | % |  | 33.1 | % |  | 35.0 | % |  | 30.0% - 40.0%
Total | 100.0 | % |  | 100.0 | % |  | 100.0 | % |  |

VEBA

| Actual |  | Target Asset Allocation |  | Permitted Range
| 2015 |  | 2014 |  |
Domestic equity investments | 67.4 | % |  | 67.9 | % |  | 65.0 | % |  | 60.0% - 70.0%
Fixed income funds & cash equivalents | 32.6 | % |  | 32.1 | % |  | 35.0 | % |  | 30.0% - 40.0%
Total | 100.0 | % |  | 100.0 | % |  | 100.0 | % |  |

Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500, actively managed mid- and small-cap mutual funds, and a self-directed portfolio of smallcap common stocks. Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 10.1% and 9.6% of U.S. Pension Plan assets at September 30, 2015 and 2014, respectively.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The fair values of U.S. Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee. The fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2, as of September 30, 2015 and 2014 are as follows:

| U.S. Pension Plan
| Level 1 |  | Level 2 |  | Level 3 |  | Total
September 30, 2015: |  |  |  |  |  |  |
Domestic equity investments: |  |  |  |  |  |  |
S&P 500 Index equity mutual funds | $ | 147.3 |  |  | $ | — |  |  | $ | — |  |  | $ | 147.3 |
Small and midcap equity mutual funds | 40.6 |  |  | — |  |  | — |  |  | 40.6 |
Smallcap common stocks | 10.7 |  |  | — |  |  | — |  |  | 10.7 |
UGI Corporation Common Stock | 43.4 |  |  | — |  |  | — |  |  | 43.4 |
Total domestic equity investments | 242.0 |  |  | — |  |  | — |  |  | 242.0 |
International index equity mutual funds | 43.9 |  |  | — |  |  | — |  |  | 43.9 |
Fixed income investments: |  |  |  |  |  |  |
Bond index mutual funds | 140.8 |  |  | — |  |  | — |  |  | 140.8 |
Cash equivalents | — |  |  | 4.1 |  |  | — |  |  | 4.1 |
Total fixed income investments | 140.8 |  |  | 4.1 |  |  | — |  |  | 144.9 |
Total | $ | 426.7 |  |  | $ | 4.1 |  |  | $ | — |  |  | $ | 430.8 |
September 30, 2014: |  |  |  |  |  |  |
Domestic equity investments: |  |  |  |  |  |  |
S&P 500 Index equity mutual funds | $ | 152.6 |  |  | $ | — |  |  | $ | — |  |  | $ | 152.6 |
Small and midcap equity mutual funds | 41.4 |  |  | — |  |  | — |  |  | 41.4 |
Smallcap common stocks | 9.3 |  |  | — |  |  | — |  |  | 9.3 |
UGI Corporation Common Stock | 42.5 |  |  | — |  |  | — |  |  | 42.5 |
Total domestic equity investments | 245.8 |  |  | — |  |  | — |  |  | 245.8 |
International index equity mutual funds | 49.9 |  |  | — |  |  | — |  |  | 49.9 |
Fixed income investments: |  |  |  |  |  |  |
Bond index mutual funds | 141.0 |  |  | — |  |  | — |  |  | 141.0 |
Cash equivalents | — |  |  | 5.7 |  |  | — |  |  | 5.7 |
Total fixed income investments | 141.0 |  |  | 5.7 |  |  | — |  |  | 146.7 |
Total | $ | 436.7 |  |  | $ | 5.7 |  |  | $ | — |  |  | $ | 442.4 |

| VEBA
| Level 1 |  | Level 2 |  | Level 3 |  | Total
September 30, 2015: |  |  |  |  |  |  |
S&P 500 Index equity mutual fund | $ | 8.4 |  |  | $ | — |  |  | $ | — |  |  | $ | 8.4 |
Bond index mutual fund | 3.8 |  |  | — |  |  | — |  |  | 3.8 |
Cash equivalents | — |  |  | 0.3 |  |  | — |  |  | 0.3 |
Total | $ | 12.2 |  |  | $ | 0.3 |  |  | $ | — |  |  | $ | 12.5 |
September 30, 2014: |  |  |  |  |  |  |
S&P 500 Index equity mutual fund | $ | 8.7 |  |  | $ | — |  |  | $ | — |  |  | $ | 8.7 |
Bond index mutual fund | 3.7 |  |  | — |  |  | — |  |  | 3.7 |
Cash equivalents | — |  |  | 0.4 |  |  | — |  |  | 0.4 |
Total | $ | 12.4 |  |  | $ | 0.4 |  |  | $ | — |  |  | $ | 12.8 |

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The expected long-term rates of return on U.S. Pension Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.
Defined Contribution Plans
We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans totaled $15.2 in Fiscal 2015, $14.7 in Fiscal 2014 and $14.0 in Fiscal 2013. The Company also sponsors certain nonqualified supplemental defined contribution executive retirement plans. These plans generally provide supplemental benefits to certain executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal Revenue Code. The Company makes payments to self-directed grantor trusts with respect to these supplemental defined contribution plans. Such payments during Fiscal 2015, Fiscal 2014 or Fiscal 2013 were not material. At September 30, 2015 and 2014, the total fair values of the grantor trust investment assets, which amounts are included in other noncurrent assets on the Consolidated Balance Sheets, was $4.2 and $3.4, respectively.
Note 9 — Utility Regulatory Assets and Liabilities and Regulatory Matters
The following regulatory assets and liabilities associated with Utilities are included in our accompanying Consolidated Balance Sheets at September 30:

| 2015 |  | 2014
Regulatory assets: |  |  |
Income taxes recoverable | $ | 115.9 |  |  | $ | 110.7 |
Underfunded pension and postretirement plans | 140.8 |  |  | 110.1 |
Environmental costs | 20.0 |  |  | 14.6 |
Deferred fuel and power costs | — |  |  | 11.8 |
Removal costs, net | 21.2 |  |  | 16.8 |
Other | 6.3 |  |  | 4.2 |
Total regulatory assets | $ | 304.2 |  |  | $ | 268.2 |
Regulatory liabilities (a): |  |  |
Postretirement benefits | $ | 20.0 |  |  | $ | 18.6 |
Environmental overcollections | — |  |  | 0.3 |
Deferred fuel and power refunds | 36.6 |  |  | 0.3 |
State tax benefits — distribution system repairs | 13.3 |  |  | 10.1 |
Other | 1.1 |  |  | 3.2 |
Total regulatory liabilities | $ | 71.0 |  |  | $ | 32.5 |

(a) Regulatory liabilities are recorded in other current and other noncurrent liabilities in the Consolidated Balance Sheets.
Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of the tax benefit on accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 65 years.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Underfunded pension and other postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and other postretirement benefits which are probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants.
Environmental costs. Environmental costs represent amounts actually spent by UGI Gas to clean up sites in Pennsylvania as well as the portion of estimated probable future environmental remediation and investigation costs principally at manufactured gas plant (“MGP”) sites that CPG and PNG expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 16). Consistent with prior ratemaking treatment, UGI Gas anticipates it will recover in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites and UGI Gas is currently amortizing such costs over a five-year period. PNG and CPG are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2015, the period over which PNG and CPG expect to recover these costs will depend upon future remediation activity.
Deferred fuel and power — costs and refunds. Gas Utility’s 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”) tariffs 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 instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized losses on such contracts at September 30, 2015 and 2014 were $3.3 and $1.4, respectively.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Prior to March 1, 2015, we did not designate these purchase contracts as NPNS under GAAP. Therefore, we recognized the fair value of these contracts on the balance sheet with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its prudently incurred DS costs. At September 30, 2015 and 2014, the fair values of Electric Utility’s electricity supply contracts were (losses) gains of $(0.5) and $0.3, respectively. These amounts are reflected in current and noncurrent derivative assets and current and noncurrent derivative liabilities on the Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above. Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet (see Note 18).
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 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 September 30, 2015 and 2014, were not material.
Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over 5 years.
Postretirement benefits. Gas Utility and Electric Utility are recovering ongoing postretirement benefit costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI Gas and Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above. In addition, this regulatory liability includes the portion of prior service credits and net actuarial gains associated with certain other postretirement benefit plans.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Environmental overcollections. This regulatory liability represents the difference between amounts recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms of a consent order agreement between CPG and the Pennsylvania Department of Environmental Protection (“DEP”) to remediate certain gas plant sites.
State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.
Other. Other regulatory assets comprise a number of items including, among others, deferred postretirement costs, deferred asset retirement costs, deferred rate case expenses and customer choice implementation costs. At September 30, 2015, UGI Utilities expects to recover these costs over periods of approximately 1 to 20 years.
UGI Utilities does not recover a rate of return on its regulatory assets.
Other Regulatory Matters
Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at five percent of the amount billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014, while UGI Gas has not had a general rate filing within the required time period to be eligible. Beginning on April 1, 2015, PNG was able to begin charging a DSIC at a rate other than zero. The impact of the DSIC charge at PNG did not have a material effect on Gas Utility results of operations.
Note 10 — Inventories
Inventories comprise the following at September 30:

| 2015 |  | 2014
Non-utility LPG and natural gas | $ | 140.7 |  |  | $ | 283.6 |
Gas Utility natural gas | 37.5 |  |  | 82.7 |
Materials, supplies and other | 61.7 |  |  | 56.7 |
Total inventories | $ | 239.9 |  |  | $ | 423.0 |

At September 30, 2015, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”) having terms of three years. 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.
As of September 30, 2015, UGI Utilities has SCAAs with Energy Services and a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with non-affiliates at September 30, 2015 and 2014, comprising 4.0 billion cubic feet (“bcf”) and 3.9 bcf of natural gas, was $9.8 and $16.8, respectively.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 11 — Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:

| 2015 |  | 2014
Utilities: |  |  |
Distribution | $ | 2,458.1 |  |  | $ | 2,294.6 |
Transmission | 90.0 |  |  | 88.2 |
General and other, including work in process | 205.4 |  |  | 185.7 |
Total Utilities | 2,753.5 |  |  | 2,568.5 |
Non-utility: |  |  |
Land | 174.9 |  |  | 170.2 |
Buildings and improvements | 391.4 |  |  | 317.4 |
Transportation equipment | 327.9 |  |  | 288.4 |
Equipment, primarily cylinders and tanks | 3,268.1 |  |  | 3,042.7 |
Electric generation | 305.7 |  |  | 273.4 |
Pipeline and related assets | 233.5 |  |  | 162.3 |
Other, including work in process | 374.1 |  |  | 353.8 |
Total non-utility | 5,075.6 |  |  | 4,608.2 |
Total property, plant and equipment | $ | 7,829.1 |  |  | $ | 7,176.7 |

Note 12 — Goodwill and Intangible Assets
Changes in the carrying amount of goodwill by reportable segment are as follows:

|  |  |  |  |  |  | UGI International |  |  |  |
| AmeriGas Propane |  | Gas Utility |  | Energy Services |  | UGI France |  | Flaga & Other |  | Corporate & Other |  | Total
Balance September 30, 2013 | $ | 1,941.0 |  |  | $ | 182.1 |  |  | $ | 2.8 |  |  | $ | 643.7 |  |  | $ | 97.1 |  |  | $ | 7.0 |  |  | $ | 2,873.7 |
Acquisitions | 6.8 |  |  | — |  |  | 2.8 |  |  | — |  |  | — |  |  | — |  |  | 9.6 |
Purchase accounting adjustments | (2.7 | ) |  | — |  |  | — |  |  | — |  |  | 0.9 |  |  | — |  |  | (1.8 | )
Foreign currency translation | — |  |  | — |  |  | — |  |  | (42.5 | ) |  | (5.6 | ) |  | — |  |  | (48.1 | )
Balance September 30, 2014 | 1,945.1 |  |  | 182.1 |  |  | 5.6 |  |  | 601.2 |  |  | 92.4 |  |  | 7.0 |  |  | 2,833.4 |
Acquisitions | 10.9 |  |  | — |  |  | — |  |  | 186.2 |  |  | 2.9 |  |  | — |  |  | 200.0 |
Dispositions | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1.0 | ) |  | (1.0 | )
Foreign currency translation | — |  |  | — |  |  | — |  |  | (66.0 | ) |  | (13.0 | ) |  | — |  |  | (79.0 | )
Balance September 30, 2015 | $ | 1,956.0 |  |  | $ | 182.1 |  |  | $ | 5.6 |  |  | $ | 721.4 |  |  | $ | 82.3 |  |  | $ | 6.0 |  |  | $ | 2,953.4 |

Intangible assets comprise the following at September 30:

| 2015 |  | 2014
Customer relationships, noncompete agreements and other | $ | 761.1 |  |  | $ | 712.0 |
Trademarks and tradenames (not subject to amortization) | 131.4 |  |  | 128.2 |
Gross carrying amount | 892.5 |  |  | 840.2 |
Accumulated amortization | (282.4 | ) |  | (263.8 | )
Intangible assets, net | $ | 610.1 |  |  | $ | 576.4 |

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Amortization expense of intangible assets was $52.0, $48.2 and $52.8 for Fiscal 2015, Fiscal 2014 and Fiscal 2013, respectively. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2016 — $51.4; Fiscal 2017 — $45.1; Fiscal 2018 — $43.5; Fiscal 2019 — $41.9; Fiscal 2020 — $40.5.
Note 13 — Series Preferred Stock
UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2015 or 2014.
UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. At September 30, 2015 and 2014, there were no shares of UGI Utilities Series Preferred Stock outstanding.
Note 14 — Common Stock and Equity-Based Compensation
Common Stock
On January 30, 2014, the Company’s Board of Directors authorized the repurchase of up to 15,000,000 shares of UGI Corporation Common Stock over a four-year period. Pursuant to such authorization, during Fiscal 2015 and Fiscal 2014, the Company purchased and placed in treasury stock 1,000,000 and 1,227,654 shares at a total cost of $34.1 and $39.8, respectively.
UGI Common Stock share activity for Fiscal 2013, Fiscal 2014 and Fiscal 2015 follows:

| Issued |  | Treasury |  | Outstanding
Balance, September 30, 2012 | 173,436,891 |  |  | (4,506,259 | ) |  | 168,930,632 |
Issued: |  |  |  |  |
Employee and director plans | 238,800 |  |  | 3,933,507 |  |  | 4,172,307 |
Dividend reinvestment plan | — |  |  | 93,253 |  |  | 93,253 |
Shares reacquired - employee and director plans | — |  |  | (1,552,905 | ) |  | (1,552,905 | )
Balance, September 30, 2013 | 173,675,691 |  |  | (2,032,404 | ) |  | 171,643,287 |
Issued: |  |  |  |  |
Employee and director plans | 94,950 |  |  | 2,928,140 |  |  | 3,023,090 |
Repurchases of Common Stock | — |  |  | (1,227,654 | ) |  | (1,227,654 | )
Shares reacquired - employee and director plans | — |  |  | (1,164,942 | ) |  | (1,164,942 | )
Balance, September 30, 2014 | 173,770,641 |  |  | (1,496,860 | ) |  | 172,273,781 |
Issued: |  |  |  |  |
Employee and director plans | 36,350 |  |  | 1,155,376 |  |  | 1,191,726 |
Repurchases of Common Stock | — |  |  | (1,000,000 | ) |  | (1,000,000 | )
Shares reacquired - employee and director plans | — |  |  | (77,004 | ) |  | (77,004 | )
Balance, September 30, 2015 | 173,806,991 |  |  | (1,418,488 | ) |  | 172,388,503 |

Equity-Based Compensation
The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, UGI Common stock-based equity instruments and AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $29.2 ($18.9 after-tax), $25.8 ($16.6 after-tax) and $17.6 ($11.4 after-tax) in Fiscal 2015, Fiscal 2014 and Fiscal 2013, respectively.
UGI Equity-Based Compensation Plans and Awards. On January 24, 2013, the Company’s shareholders approved the UGI Corporation 2013 Omnibus Incentive Compensation Plan (the “2013 OICP”). The 2013 OICP succeeds the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “2004 OECP”) for awards granted on or after January 24, 2013. The 2004 OECP will continue in effect but all future grants issued pursuant to it will be solely in the form of options to acquire Common Stock. Under the 2013 OICP, we may grant options to acquire shares of UGI Common Stock,
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”), other equity-based awards and cash to employees and non-employee directors. The exercise price for options may not be less than the fair market value on the grant date. Awards granted under the 2013 OICP may vest immediately or ratably over a period of years, and stock options can be exercised no later than ten years from the grant date. In addition, the 2013 OICP provides that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
Under the 2004 OECP, we could grant options to acquire shares of UGI Common Stock, UGI Units and other equity-based awards to employees and non-employee directors through January 23, 2013 (except with respect to the granting of stock option awards as previously mentioned). Under the 2004 OECP, the exercise price for stock options could not be less than the fair market value on the grant date. Awards granted under the 2004 OECP could vest immediately or ratably over a period of years, and stock options could be exercised no later than ten years from the date of grant. In addition, the 2004 OECP provided that the awards of UGI Units could include the crediting of dividend equivalents to participants’ accounts.
Under the 2013 OICP, awards representing up to 21,750,000 shares of UGI Common Stock may be granted. Dividend equivalents on UGI Unit awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are accumulated in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of Common Stock and cash. Substantially all UGI Unit awards granted to UGI France employees are settled in shares of Common Stock and do not accrue dividend equivalents. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions. It is currently our practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit awards. Stock options may be net exercised whereby shares equal to the option price and the grantee’s minimum applicable payroll tax withholding are withheld from the number of shares payable (“net exercise”). We record shares withheld pursuant to a net exercise as shares reacquired.
UGI Stock Option Awards. Stock option transactions under equity-based compensation plans during Fiscal 2013, Fiscal 2014 and Fiscal 2015 follow:

| Shares |  | Weighted Average Option Price |  | Total Intrinsic Value |  | Weighted Average Contract Term (Years)
Shares under option — September 30, 2012 | 12,086,658 |  |  | $ | 17.75 |  |  | $ | 41.4 |  |  | 6.1
Granted | 2,275,350 |  |  | $ | 22.38 |  |  |  |  |
Canceled | (134,754 | ) |  | $ | 20.34 |  |  |  |  |
Exercised | (4,033,302 | ) |  | $ | 16.39 |  |  | $ | 35.4 |  |  |
Shares under option — September 30, 2013 | 10,193,952 |  |  | $ | 19.28 |  |  | $ | 69.6 |  |  | 6.8
Granted | 1,665,600 |  |  | $ | 27.93 |  |  |  |  |
Canceled | (86,707 | ) |  | $ | 22.76 |  |  |  |  |
Exercised | (2,815,555 | ) |  | $ | 17.44 |  |  | $ | 37.4 |  |  |
Shares under option — September 30, 2014 | 8,957,290 |  |  | $ | 21.44 |  |  | $ | 113.3 |  |  | 7.0
Granted | 1,336,985 |  |  | $ | 37.70 |  |  |  |  |
Canceled | (85,365 | ) |  | $ | 30.45 |  |  |  |  |
Exercised | (953,533 | ) |  | $ | 19.10 |  |  | $ | 15.4 |  |  |
Shares under option — September 30, 2015 | 9,255,377 |  |  | $ | 23.97 |  |  | $ | 104.5 |  |  | 6.6
Options exercisable — September 30, 2013 | 5,871,091 |  |  | $ | 17.95 |  |  |  |  |
Options exercisable — September 30, 2014 | 5,073,347 |  |  | $ | 19.45 |  |  |  |  |
Options exercisable — September 30, 2015 | 6,050,946 |  |  | $ | 20.74 |  |  | $ | 85.4 |  |  | 5.8
Options not exercisable — September 30, 2015 | 3,204,431 |  |  | $ | 30.05 |  |  | $ | 19.1 |  |  | 8.3

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Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Cash received from stock option exercises and associated tax benefits were $16.2 and $5.8, $22.2 and $13.0, and $30.8 and $12.1 in Fiscal 2015, Fiscal 2014 and Fiscal 2013, respectively. As of September 30, 2015, there was $5.2 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 1.9 years.
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2015:

| Range of exercise prices
| Under $20.00 |  | $20.01 - $25.00 |  | $25.01 - $30.00 |  | Over $30.00
Options outstanding at September 30, 2015: |  |  |  |  |  |  |
Number of options | 2,956,873 |  |  | 3,178,416 |  |  | 1,713,903 |  |  | 1,406,185 |
Weighted average remaining contractual life (in years) | 4.9 |  |  | 6.3 |  |  | 8.1 |  |  | 9.2 |
Weighted average exercise price | $ | 18.21 |  |  | $ | 21.47 |  |  | $ | 27.46 |  |  | $ | 37.45 |
Options exercisable at September 30, 2015: |  |  |  |  |  |  |
Number of options | 2,835,673 |  |  | 2,475,420 |  |  | 634,602 |  |  | 105,251 |
Weighted average exercise price | $ | 18.15 |  |  | $ | 21.38 |  |  | $ | 27.29 |  |  | $ | 35.93 |

UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $5.47 in Fiscal 2015, $4.97 in Fiscal 2014 and $3.29 in Fiscal 2013. These amounts were determined using a Black-Scholes option pricing model which values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments and the risk-free interest rate over the expected life of the option. The expected life of option awards represents the period of time during which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on historical UGI dividend rates. The risk free interest rate is based on U.S. Treasury bonds with terms comparable to the options in effect on the date of grant.
The assumptions we used for valuing option grants during Fiscal 2015, Fiscal 2014 and Fiscal 2013 are as follows:

| 2015 |  | 2014 |  | 2013
Expected life of option | 5.75 years |  | 5.75 years |  | 5.75 years
Weighted average volatility | 19.5% |  | 24.3% |  | 24.9%
Weighted average dividend yield | 2.5% |  | 2.9% |  | 3.6%
Expected volatility | 19.1% -19.5% |  | 23.7% - 24.4% |  | 24.4% - 24.9%
Expected dividend yield | 2.5% |  | 2.7% - 2.9% |  | 3.2% - 3.7%
Risk free rate | 1.5% - 1.8% |  | 1.8% - 2.0% |  | 0.8% - 1.7%

UGI Unit Awards. UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of UGI Performance Units ultimately paid at the end of the performance period (generally three years) may be higher or lower than the target amount, or even zero, based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to (i) companies in the Standard & Poor’s Utilities Index for grants prior to January 1, 2011 and (ii) the Russell Midcap Utility Index, excluding telecommunication companies, for grants on or after January 1, 2011 (each a respective “UGI comparator group”). For grants issued on or after January 1, 2013, grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 25th percentile compared to the UGI comparator group, the employee will not be paid. At the 25th percentile, the employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70%; at the 50th percentile, 100%; and at the 90th percentile and above, 200%. For grants issued prior to January 1, 2013, grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 40th percentile compared to the UGI comparator group, the employee will not be paid. At the 40th percentile, the employee will be paid an award equal to 50% of the target award; at the 50th percentile, 100%; and at the 100th percentile, 200%. The actual amount of the award is interpolated between these percentile rankings. Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The fair value of UGI Stock Units on the grant date is equal to the market price of UGI Stock on the grant date plus the fair value of dividend equivalents if applicable. Under GAAP, UGI Performance Units are equity awards with a market-based condition which, if settled in shares, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of UGI Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award is accounted for as equity and the fair value of the award over the target, as well as all dividend equivalents, is accounted for as a liability. The expected term of the UGI Performance Unit awards is three years based on the performance period. Expected volatility is based on the historical volatility of UGI Common Stock over a three-year period. The risk-free interest rate is based on the yields on U.S. Treasury bonds at the time of grant. Volatility for all companies in the UGI comparator groups is based on historical volatility.
The following table summarizes the weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs:

| Grants Awarded in Fiscal
| 2015 |  | 2014 |  | 2013
Risk free rate | 1.1 | % |  | 0.8 | % |  | 0.4 | %
Expected life | 3 years |  |  | 3 years |  |  | 3 years |
Expected volatility | 15.9 | % |  | 20.3 | % |  | 21.1 | %
Dividend yield | 2.3 | % |  | 2.7 | % |  | 3.3 | %

The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $38.43 for Units granted in Fiscal 2015, $32.32 for Units granted in Fiscal 2014 and $25.31 for Units granted in Fiscal 2013.
The following table summarizes UGI Unit award activity for Fiscal 2015:

| Total |  | Vested |  | Non-Vested
| Number of UGI Units |  | Weighted Average Grant Date Fair Value (per Unit) |  | Number of UGI Units |  | Weighted Average Grant Date Fair Value (per Unit) |  | Number of UGI Units |  | Weighted Average Grant Date Fair Value (per Unit)
September 30, 2014 | 1,306,181 |  |  | $ | 20.58 |  |  | 781,231 |  |  | $ | 16.60 |  |  | 524,950 |  |  | $ | 26.51 |
UGI Performance Units: |  |  |  |  |  |  |  |  |  |  |
Granted | 140,923 |  |  | $ | 38.43 |  |  | 22,942 |  |  | $ | 38.51 |  |  | 117,981 |  |  | $ | 38.41 |
Forfeited | (18,144 | ) |  | $ | 30.16 |  |  | — |  |  | $ | — |  |  | (18,144 | ) |  | $ | 30.16 |
Vested | — |  |  | $ | — |  |  | 290,678 |  |  | $ | 24.60 |  |  | (290,678 | ) |  | $ | 24.60 |
Unit awards paid | (263,966 | ) |  | $ | 19.10 |  |  | (263,966 | ) |  | $ | 19.10 |  |  | — |  |  | $ | — |
UGI Stock Units: |  |  |  |  |  |  |  |  |  |  |
Granted (a) | 39,801 |  |  | $ | 37.39 |  |  | 38,101 |  |  | $ | 37.37 |  |  | 1,700 |  |  | $ | 37.75 |
Forfeited | (1,125 | ) |  | $ | 29.84 |  |  | — |  |  | $ | — |  |  | (1,125 | ) |  | $ | 29.84 |
Vested | — |  |  | $ | — |  |  | 2,250 |  |  | $ | 22.86 |  |  | (2,250 | ) |  | $ | 22.86 |
Unit awards paid | (67,419 | ) |  | $ | 17.04 |  |  | (67,419 | ) |  | $ | 17.04 |  |  | — |  |  | $ | — |
September 30, 2015 | 1,136,251 |  |  | $ | 23.78 |  |  | 803,817 |  |  | $ | 20.19 |  |  | 332,434 |  |  | $ | 32.28 |

(a) | Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2014 and Fiscal 2013 were 44,814 and 51,038, respectively.

During Fiscal 2015, Fiscal 2014 and Fiscal 2013, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

| 2015 |  | 2014 |  | 2013
UGI Performance Unit awards: |  |  |  |  |
Number of original awards granted | 294,300 |  |  | 331,038 |  |  | 328,025 |
Fiscal year granted | 2012 |  |  | 2011 |  |  | 2010 |
Payment of awards: |  |  |  |  |
Shares of UGI Common Stock issued | 188,418 |  |  | 174,168 |  |  | 97,622 |
Cash paid | $ | 13.3 |  |  | $ | 3.1 |  |  | $ | 1.6 |
UGI Stock Unit awards: |  |  |  |  |
Number of original awards granted | 67,419 |  |  | 34,639 |  |  | 54,269 |
Payment of awards: |  |  |  |  |
Shares of UGI Common Stock issued | 44,034 |  |  | 22,604 |  |  | 35,274 |
Cash paid | $ | 0.8 |  |  | $ | 0.4 |  |  | $ | 0.5 |

During Fiscal 2015, Fiscal 2014 and Fiscal 2013, we granted UGI Unit awards representing 180,724, 234,264 and 381,900 shares, respectively, having weighted-average grant date fair values per Unit of $38.20, $31.38 and $24.87, respectively.
As of September 30, 2015, there was a total of approximately $6.9 of unrecognized compensation cost associated with 1,136,251 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.7 years. The total fair values of UGI Units that vested during Fiscal 2015, Fiscal 2014 and Fiscal 2013 were $15.3, $8.7 and $6.0, respectively. As of September 30, 2015 and 2014, total liabilities of $19.9 and $18.5, respectively, associated with UGI Unit awards are reflected in employee compensation and benefits accrued and other noncurrent liabilities in the Consolidated Balance Sheets.
At September 30, 2015, 15,528,898 shares of Common Stock were available for future grants under the 2013 OICP, and up to 34,774 shares of Common Stock were available for future grants of stock options under the 2004 OECP.
AmeriGas Partners Equity-Based Compensation Plans and Awards. Under the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. (“2010 Propane Plan”), the General Partner may award to employees and non-employee directors grants of AmeriGas Partners Units (comprising “AmeriGas Stock Units” and “AmeriGas Performance Units”), options, phantom units, unit appreciation rights and other Common Unit-based awards. The total aggregate number of Common Units that may be issued under the 2010 Propane Plan is 2,800,000. The exercise price for options may not be less than the fair market value on the date of grant. Awards granted under the 2010 Propane Plan may vest immediately or ratably over a period of years, and options can be exercised no later than ten years from the grant date. In addition, the 2010 Propane Plan provides that Common Unit-based awards may also provide for the crediting of Common Unit distribution equivalents to participants’ accounts.
AmeriGas Stock Unit and AmeriGas Performance Unit awards entitle the grantee to AmeriGas Partners Common Units or cash once the service condition is met and, with respect to AmeriGas Performance Units, subject to market performance conditions, and for certain awards granted in January 2015, actual net customer acquisition and retention performance. Recipients of AmeriGas Performance Unit awards are awarded a target number of AmeriGas Performance Units. The number of AmeriGas Performance Units ultimately paid at the end of the performance period (generally three years) may be higher or lower than the target number, or it may be zero. For that portion of Performance Unit awards whose ultimate payout is based upon market-based conditions (as further described below), the number of awards ultimately paid is based upon AmeriGas Partners’ Total Unitholder Return (“TUR”) percentile rank relative to entities in a master limited partnership peer group (“Alerian MLP Group”) and, for certain AmeriGas Performance Unit awards granted beginning in January 2014, based upon AmeriGas Partners’ TUR relative to the two other publicly traded propane master limited partnerships in the Alerian MLP Group (“Propane MLP Group”). For Performance Unit awards granted in January 2015, the number of AmeriGas Performance Units ultimately paid is based upon AmeriGas Partner’s TUR percentile rank relative to entities in the Alerian MLP Group as modified by AmeriGas Partners’ performance relative to the Propane MLP Group.
With respect to AmeriGas Performance Unit awards subject to measurement compared with the Alerian MLP Group, grantees may receive from 0% to 200% of the target award granted. For grants issued before January 1, 2013, grantees of AmeriGas Performance Units will not be paid if AmeriGas Partners’ TUR is below the 40th percentile of the Alerian MLP Group. At the 40th percentile, the grantee will be paid an award equal to 50% of the target award; at the 50th percentile, 100%; at the 60th
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
percentile, 125%; at the 75th percentile, 150%; at the 90th percentile, 175%; and at the 100th percentile, 200%. The actual amount of the award is interpolated between these percentile rankings. For such grants issued on or after January 1, 2013, if AmeriGas Partners’ TUR is below the 25th percentile compared to the peer group, the grantee will not be paid. At the 25th percentile, the employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70%; at the 50th percentile, 100%; at the 60th percentile, 125%; at the 75th percentile, 162.5%; and at the 90th percentile or above, 200%. For such grants issued in January 2015, the amount ultimately paid shall be modified based upon AmeriGas Partners’ TUR ranking relative to the Propane MLP Group over the performance period (“MLP Modifier”). Such modification ranges from 70% to 130%, but in no event shall the amount ultimately paid, after such modification, exceed 200% of the target award grant.
With respect to AmeriGas Performance Unit awards granted in January 2014 subject to measurement compared with the Propane MLP Group, grantees will receive 150% of the target award if AmeriGas Partners’ TUR exceeds the TUR of all the other members in the Propane MLP Group. Otherwise there will be no payout of such AmeriGas Performance Units. If one of the other two members of the Propane MLP Group ceases to exist as a publicly traded company or declares bankruptcy (“MLP Event”) and depending upon the timing of such MLP Event, the ultimate amount of such AmeriGas Performance Unit awards to be issued pursuant to the January 2014 grant, and the amount of distribution equivalents to be paid, will depend upon AmeriGas Partners’ TUR rank relative to (1) the Alerian MLP Group for the entire performance period; (2) the Alerian MLP Group for the entire performance period and the Propane MLP Group (through the date of the MLP Event); or (3) the Propane MLP Group through the date of the MLP Event. For those performance awards granted in January 2015 that are subject to the MLP Modifier, if an MLP Event were to occur during the performance period such MLP Modifier would be based upon AmeriGas Partners’ TUR rank as determined in (1),(2) or (3) above, as appropriate.
With respect to AmeriGas Performance Unit awards granted in January 2015 whose payout is based upon net customer gain and retention performance, grantees may ultimately receive between 0% and 200% of the target award based upon the annual actual net customer gain and retention performance as adjusted for the net customer gain and retention performance over the three-year performance period.
Any Common Unit distribution equivalents earned are paid in cash. Generally, except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed by the General Partner. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
Under GAAP, AmeriGas Performance Units awards that are subject to market-based conditions are equity awards which, if settled in Common Units, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of AmeriGas Performance Units subject to market-based conditions are estimated using a Monte Carlo valuation model. The fair value associated with the target award, which will be paid in Common Units, is accounted for as equity and the fair value of the award over the target, as well as all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability. For purposes of valuing AmeriGas Performance Unit awards that are subject to market-based conditions, expected volatility is based on the historical volatility of Common Units over a three-year period. The risk-free interest rate is based on the rates on U.S. Treasury bonds at the time of grant. Volatility for all entities in the peer group is based on historical volatility. The expected term of the AmeriGas Performance Unit awards is three years based on the performance period. AmeriGas Performance Unit awards whose ultimate payout is based upon net customer acquisition and retention performance measures are recorded as expense when it is probable all or a portion of the award will be paid. The fair value associated with the target award is the market price of the Common Units on the date of grant. The fair value of the award over the target, as well as all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards subject to market-based conditions and related compensation costs:

| Grants Awarded in Fiscal Year
| 2015 |  | 2014 |  | 2013
Risk-free rate | 0.9 | % |  | 0.8 | % |  | 0.4 | %
Expected life | 3 years |  |  | 3 years |  |  | 3 years |
Expected volatility | 19.2 | % |  | 21.1 | % |  | 20.7 | %
Dividend yield | 6.8 | % |  | 7.5 | % |  | 8.2 | %

The General Partner granted awards under the 2010 Propane Plan representing 80,336, 86,458 and 65,136 Common Units in Fiscal 2015, Fiscal 2014 and Fiscal 2013, respectively, having weighted-average grant date fair values per Common Unit subject to award of $61.00, $43.34 and $42.58, respectively. At September 30, 2015, 2,416,473 Common Units were available for future award grants under the 2010 Propane Plan.
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2015:

| Total |  | Vested |  | Non-Vested
| Number of AmeriGas Partners Common Units Subject to Award |  | Weighted Average Grant Date Fair Value (per Unit) |  | Number of AmeriGas Partners Common Units Subject to Award |  | Weighted Average Grant Date Fair Value (per Unit) |  | Number of AmeriGas Partners Common Units Subject to Award |  | Weighted Average Grant Date Fair Value (per Unit)
September 30, 2014 | 200,235 |  |  | $ | 44.82 |  |  | 37,207 |  |  | $ | 44.27 |  |  | 163,028 |  |  | $ | 44.95 |
AmeriGas Performance Units: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Granted | 65,525 |  |  | $ | 64.02 |  |  | 3,290 |  |  | $ | 64.85 |  |  | 62,235 |  |  | $ | 63.97 |
Forfeited | (12,110 | ) |  | $ | 55.09 |  |  | — |  |  | $ | — |  |  | (12,110 | ) |  | $ | 55.09 |
Vested | — |  |  | $ | — |  |  | 39,516 |  |  | $ | 46.39 |  |  | (39,516 | ) |  | $ | 46.39 |
Performance criteria not met | (37,981 | ) |  | $ | 48.24 |  |  | (37,981 | ) |  | $ | 48.24 |  |  | — |  |  | $ | — |
AmeriGas Stock Units: |  |  |  |  |  |  |  |  |  |  |
Granted | 14,811 |  |  | $ | 47.65 |  |  | 8,011 |  |  | $ | 48.93 |  |  | 6,800 |  |  | $ | 46.13 |
Forfeited | (4,177 | ) |  | $ | 50.89 |  |  | — |  |  | $ | — |  |  | (4,177 | ) |  | $ | 50.89 |
Vested | — |  |  | $ | — |  |  | 30,577 |  |  | $ | 47.57 |  |  | (30,577 | ) |  | $ | 47.57 |
Awards paid | (33,720 | ) |  | $ | 47.65 |  |  | (33,720 | ) |  | $ | 47.65 |  |  | — |  |  | $ | — |
September 30, 2015 | 192,583 |  |  | $ | 49.70 |  |  | 46,900 |  |  | $ | 44.97 |  |  | 145,683 |  |  | $ | 51.22 |

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
During Fiscal 2015, Fiscal 2014 and Fiscal 2013, the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows:

| 2015 |  | 2014 |  | 2013
AmeriGas Performance Unit awards: |  |  |  |  |
Number of Common Units subject to original awards granted | 55,750 |  |  | 41,251 |  |  | 48,150 |
Fiscal year granted | 2012 |  |  | 2011 |  |  | 2010 |
Payment of awards: |  |  |  |  |
AmeriGas Partners Common Units issued | — |  |  | — |  |  | — |
Cash paid | $ | — |  |  | $ | — |  |  | $ | — |
AmeriGas Stock Unit awards: |  |  |  |  |
Number of Common Units subject to original awards granted | 42,532 |  |  | 72,023 |  |  | 35,934 |
Payment of awards: |  |  |  |  |
AmeriGas Partners Common Units issued | 21,509 |  |  | 40,842 |  |  | 23,192 |
Cash paid | $ | 0.8 |  |  | $ | 1.4 |  |  | $ | 0.6 |

As of September 30, 2015, there was a total of approximately $2.7 of unrecognized compensation cost associated with 192,583 Common Units subject to award that is expected to be recognized over a weighted-average period of 1.6 years. The total fair values of Common Unit-based awards that vested during Fiscal 2015, Fiscal 2014 and Fiscal 2013 were $2.6, $4.1 and $2.8, respectively. As of September 30, 2015 and 2014, total liabilities of $3.3 and $1.5 associated with Common Unit-based awards are reflected in employee compensation and benefits accrued and other noncurrent liabilities in the Consolidated Balance Sheets. It is the Partnership’s practice to issue new AmeriGas Partners Common Units for the portion of any Common Unit-based awards paid in AmeriGas Partners Common Units.
Note 15 — Partnership Distributions
The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash (as defined in the Partnership Agreement) for such quarter. Available Cash generally means:

1. | all cash on hand at the end of such quarter,

2. | plus all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter,

3. | less the amount of cash reserves established by the General Partner in its reasonable discretion.

The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the next four quarters.
Distributions of Available Cash are made 98% to limited partners and 2% to the General Partner (representing a 1% General Partner interest in AmeriGas Partners and 1.01% interest in AmeriGas OLP) until Available Cash exceeds the Minimum Quarterly Distribution of $0.55 and the First Target Distribution of $0.055 per Common Unit (or a total of $0.605 per Common Unit). When Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner will receive a greater percentage of the total Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common Unit to limited partners exceeds $0.605.
During Fiscal 2015, Fiscal 2014 and Fiscal 2013, the Partnership made quarterly distributions to Common Unitholders in excess of $0.605 per limited partner unit. As a result, the General Partner has received a greater percentage of the total Partnership distribution than its aggregate 2% general partner interest in AmeriGas OLP and AmeriGas Partners. During Fiscal 2015, Fiscal 2014 and Fiscal 2013, the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $39.3, $32.4 and $27.4, respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2015, Fiscal 2014 and Fiscal 2013 of $30.4, $23.9 and $19.3, respectively.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 16 — Commitments and Contingencies
Commitments
We lease various buildings and other facilities and vehicles, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $86.1 in Fiscal 2015, $79.7 in Fiscal 2014 and $82.5 in Fiscal 2013.
Minimum future payments under operating leases with non-affiliates that have initial or remaining noncancelable terms in excess of one year are as follows:

| 2016 |  | 2017 |  | 2018 |  | 2019 |  | 2020 |  | After 2020
AmeriGas Propane | $ | 55.3 |  |  | $ | 46.3 |  |  | $ | 41.1 |  |  | $ | 35.4 |  |  | $ | 33.7 |  |  | $ | 88.7 |
UGI Utilities | 6.4 |  |  | 4.8 |  |  | 3.9 |  |  | 1.6 |  |  | 0.6 |  |  | 0.5 |
UGI International | 9.8 |  |  | 2.7 |  |  | 1.3 |  |  | 0.6 |  |  | 0.3 |  |  | 0.4 |
Other | 1.9 |  |  | 1.6 |  |  | 0.9 |  |  | 0.5 |  |  | 0.4 |  |  | — |
Total | $ | 73.4 |  |  | $ | 55.4 |  |  | $ | 47.2 |  |  | $ | 38.1 |  |  | $ | 35.0 |  |  | $ | 89.6 |

Our businesses enter into contracts of varying lengths and terms to meet their supply, pipeline transportation, storage, capacity and energy needs. Gas Utility currently has gas supply agreements with producers and marketers with terms not exceeding 16 months. Gas Utility also has agreements for firm pipeline transportation and natural gas storage services, which Gas Utility may terminate at various dates through Fiscal 2030. Gas Utility’s costs associated with transportation and storage capacity agreements are included in its annual PGC filings with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices. Electric Utility purchases its electricity needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2016. Midstream & Marketing enters into fixed-price contracts with suppliers to purchase natural gas and electricity to meet its sales commitments. Generally, these contracts have terms of less than two years. The Partnership enters into fixed-price and variable-price contracts to purchase a portion of its supply requirements. These contracts currently have terms that do not exceed three years. UGI International enters into fixed-price and variable-priced contracts to purchase a portion of its supply requirements that currently do not exceed three years.
The following table presents contractual obligations with non-affiliates under Gas Utility, Electric Utility, Midstream & Marketing, AmeriGas Propane and UGI International supply, storage and service contracts existing at September 30, 2015:

| 2016 |  | 2017 |  | 2018 |  | 2019 |  | 2020 |  | After 2020
UGI Utilities supply, storage and transportation contracts | $ | 122.0 |  |  | $ | 59.6 |  |  | $ | 37.4 |  |  | $ | 27.3 |  |  | $ | 16.2 |  |  | $ | 60.5 |
Midstream & Marketing supply contracts | 165.9 |  |  | 83.2 |  |  | 51.0 |  |  | 30.0 |  |  | 2.6 |  |  | — |
AmeriGas Propane supply contracts | 53.5 |  |  | 4.8 |  |  | — |  |  | — |  |  | — |  |  | — |
UGI International supply contracts | 452.1 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Total | $ | 793.5 |  |  | $ | 147.6 |  |  | $ | 88.4 |  |  | $ | 57.3 |  |  | $ | 18.8 |  |  | $ | 60.5 |

The Partnership and UGI International also enter into other contracts to purchase LPG to meet supply requirements. Generally, these contracts are one- to three-year agreements subject to annual price and quantity adjustments.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Contingencies
Environmental Matters
UGI Utilities
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the DEP requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which 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 $1.8 and $1.1, respectively, in any calendar year. The CPG-COA 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 September 30, 2015 and 2014, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $13.8 and $10.7, respectively. We have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable.
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.
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (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 and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2015, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.
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.
Other Matters
Purported Class Action Lawsuits. Between May and October 2014, more than 35 purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI Corporation and a competitor by certain of their direct and indirect customers. The class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade its common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws. The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes. On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Division of the United States District Court for the Western District of Missouri. In July 2015, the Court dismissed all claims brought by direct customers and all claims other than those for injunctive relief brought by indirect customers. The direct customers have filed an appeal with the United States Court of Appeals for the Eighth Circuit. The indirect customers have filed an amended complaint claiming injunctive relief and state law claims under Wisconsin, Maine,
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
and Vermont law. We are unable to reasonably estimate the impact, if any, arising from such litigation. We believe we have strong defenses to the claims and intend to vigorously defend against them.
In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial position, results of operations or cash flows.
Note 17 — Fair Value Measurements
The following table presents, on a gross basis, our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2, as of September 30, 2015 and 2014:

| Asset (Liability)
| Level 1 |  | Level 2 |  | Level 3 |  | Total
September 30, 2015: |  |  |  |  |  |  |
Derivative instruments: |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |
Commodity contracts | $ | 17.4 |  |  | $ | 11.6 |  |  | $ | — |  |  | $ | 29.0 |
Foreign currency contracts | $ | — |  |  | $ | 29.1 |  |  | $ | — |  |  | $ | 29.1 |
Cross-currency swaps | $ | — |  |  | $ | 0.4 |  |  | $ | — |  |  | $ | 0.4 |
Interest rate contracts | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Liabilities: |  |  |  |  |  |  |
Commodity contracts | $ | (70.0 | ) |  | $ | (99.0 | ) |  | $ | — |  |  | $ | (169.0 | )
Foreign currency contracts | $ | — |  |  | $ | (0.1 | ) |  | $ | — |  |  | $ | (0.1 | )
Interest rate contracts | $ | — |  |  | $ | (10.8 | ) |  | $ | — |  |  | $ | (10.8 | )
Non-qualified supplemental postretirement grantor trust investments (a) | $ | 30.3 |  |  | $ | — |  |  | $ | — |  |  | $ | 30.3 |
September 30, 2014 |  |  |  |  |  |  |
Derivative instruments: |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |
Commodity contracts | $ | 10.6 |  |  | $ | 19.8 |  |  | $ | — |  |  | $ | 30.4 |
Foreign currency contracts | $ | — |  |  | $ | 12.8 |  |  | $ | — |  |  | $ | 12.8 |
Cross-currency swaps | $ | — |  |  | $ | 2.1 |  |  | $ | — |  |  | $ | 2.1 |
Interest rate contracts | $ | — |  |  | $ | 0.1 |  |  | $ | — |  |  | $ | 0.1 |
Liabilities: |  |  |  |  |  |  |
Commodity contracts | $ | (21.2 | ) |  | $ | (32.9 | ) |  | $ | — |  |  | $ | (54.1 | )
Foreign currency contracts | $ | — |  |  | $ | (0.1 | ) |  | $ | — |  |  | $ | (0.1 | )
Interest rate contracts | $ | — |  |  | $ | (21.0 | ) |  | $ | — |  |  | $ | (21.0 | )
Non-qualified supplemental postretirement grantor trust investments (a) | $ | 30.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 30.0 |

(a) | Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 8).

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The fair values of our Level 1 exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The remainder of our derivative instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 which are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. 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. At September 30, 2015, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,699.8 and $3,803.1, respectively. At September 30, 2014, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,510.8 and $3,686.1, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2).
Financial instruments other than derivative instruments, such as our short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit our credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative instruments, see Note 18. Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value.
Note 18 — 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, (2) interest rate risk and (3) foreign currency exchange 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. For information on the accounting for our derivative instruments, see Note 2.
Commodity Price Risk
In order to manage market price risk associated with the Partnership’s fixed-price programs, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units and our UGI International operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. The Partnership from time to time enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. At September 30, 2015 and 2014, total volumes associated with LPG commodity derivative instruments totaled 516.3 million gallons and 344.5 million gallons, respectively. The maximum period over which we are economically hedging our exposure to LPG commodity price risk is 39 months.
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 September 30, 2015 and 2014, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 18.9 million dekatherms and 16.9 million dekatherms,
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
respectively. At September 30, 2015, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 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 Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to customers through the PGC recovery mechanism (see Note 9).
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. For such contracts entered into by Electric Utility prior to March 1, 2015, Electric Utility chose not to elect the NPNS exception under GAAP, related to these derivatives instruments and the fair values of these contracts are reflected in current and noncurrent derivative instrument assets and liabilities in the accompanying Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Consolidated Balance Sheets in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 9). Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet. At September 30, 2015 and 2014, the volumes of Electric Utility’s forward electricity purchase contracts were 331.0 million kilowatt hours and 237.0 million kilowatt hours, respectively. At September 30, 2015, the maximum period over which these contracts extend is 8 months.
In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 9). At September 30, 2015 and 2014, the total volumes associated with FTRs and NYISO capacity contracts totaled 359.1 million kilowatt hours and 232.1 million kilowatt hours, respectively. At September 30, 2015, the maximum period over which we are economically hedging electricity congestion and locational basis differences is 8 months.
In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures contracts, Intercontinental Exchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over the counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas or propane. Because it could no longer assert the NPNS exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation, beginning in the second quarter of Fiscal 2014 Energy Services began recording these contracts at fair value with changes in fair value reflected in cost of sales.
At September 30, 2015 and 2014, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 110.2 million dekatherms and 113.7 million dekatherms, respectively. At September 30, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk is 39 months. At September 30, 2015 and 2014, total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 474.3 million kilowatt hours and 297.9 million kilowatt hours, and 394.4 million kilowatt hours and 206.6 million kilowatt hours, respectively. At September 30, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity commodity price risk (excluding Electric Utility) is 39 months for electricity call contracts and 24 months for electricity put contracts. At September 30, 2015, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 1.9 million dekatherms and 2.0 million gallons, respectively. At September 30, 2014, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 3.9 million dekatherms and 1.3 million gallons, respectively.
At September 30, 2015, there were no amounts remaining in AOCI related to commodity derivative hedges.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Interest Rate Risk
UGI France’s and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on their variable-rate term loans through the respective scheduled maturity dates. As of September 30, 2015 and 2014, the total notional amounts of variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) were €645.8 and €401.1, respectively.
Our domestic businesses’ long-term debt is typically 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”). At September 30, 2015, the total notional amount of unsettled IRPAs was $250. At September 30, 2014, we had no unsettled IRPAs. Our September 30, 2015, unsettled IRPA contracts hedge forecasted interest payments expected to occur over ten- and thirty-year periods beginning in Fiscal 2016.
We account for interest rate swaps and IRPAs as cash flow hedges. At September 30, 2015, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $2.5.
Foreign Currency Exchange Rate Risk
In order to reduce volatility, UGI France hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases during the heating-season months of October through March through the use of forward foreign currency exchange contracts. At September 30, 2015 and 2014, we were hedging a total of $227.9 and $219.8 of U.S. dollar-denominated LPG purchases, respectively. At September 30, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with U.S. dollar-denominated purchases of LPG is 30 months. From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At September 30, 2015 and 2014, we had no euro-denominated net investment hedges.
We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At September 30, 2015, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $16.0.
Cross-Currency Swaps
From time to time, Flaga enters into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with foreign currency and interest rate risk. These cross-currency hedges include initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also include interest rate swaps of a fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We designate these cross-currency swaps as cash flow hedges. At September 30, 2015 and 2014, cross-currency swaps were hedging foreign currency risk associated with interest and principal payments on $59.1 and $52.0 of Flaga U.S. dollar-denominated debt, respectively.
At September 30, 2015, the amount of net gains associated with this cross-currency swaps expected to be reclassified into earnings over the next twelve months is not material.
Derivative Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2015 and 2014, restricted cash in brokerage accounts totaled $54.9 and $16.6, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
counterparties failed to perform according to the terms of their contracts was not material at September 30, 2015. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At September 30, 2015, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
Offsetting Derivative Assets and Liabilities
Derivative assets and liabilities are presented net by counterparty on our Consolidated Balance Sheets if the right of offset exists. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. 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 are subject to conditional rights of offset through counterparty nonperformance, insolvency, or other conditions.
In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on our Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Fair Value of Derivative Instruments
The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of September 30, 2015 and 2014:

| 2015 |  | 2014
Derivative assets: |  |  |
Derivatives designated as hedging instruments: |  |  |
Commodity contracts | $ | — |  |  | $ | 2.8 |
Foreign currency contracts | 29.1 |  |  | 12.8 |
Cross-currency contracts | 0.4 |  |  | 2.1 |
Interest rate contracts | — |  |  | 0.1 |
| 29.5 |  |  | 17.8 |
Derivatives subject to PGC and DS mechanisms: |  |  |
Commodity contracts | 1.3 |  |  | 1.7 |
Derivatives not designated as hedging instruments: |  |  |
Commodity contracts | 27.7 |  |  | 25.9 |
Total derivative assets - gross | 58.5 |  |  | 45.4 |
Gross amounts offset in the balance sheet | (18.9 | ) |  | (18.4 | )
Total derivative assets - net | $ | 39.6 |  |  | $ | 27.0 |
Derivative liabilities: |  |  |
Derivatives designated as hedging instruments: |  |  |
Commodity contracts | $ | — |  |  | $ | (5.3 | )
Foreign currency contracts | (0.1 | ) |  | (0.1 | )
Cross-currency contracts | — |  |  | — |
Interest rate contracts | (10.8 | ) |  | (21.0 | )
| (10.9 | ) |  | (26.4 | )
Derivatives subject to PGC and DS mechanisms: |  |  |
Commodity contracts | (5.6 | ) |  | (2.2 | )
Derivatives not designated as hedging instruments: |  |  |
Commodity contracts | (163.4 | ) |  | (46.6 | )
Total derivative liabilities - gross | (179.9 | ) |  | (75.2 | )
Gross amounts offset in the balance sheet | 18.9 |  |  | 18.4 |
Cash collateral pledged | 8.0 |  |  | — |
Total derivative liabilities - net | $ | (153.0 | ) |  | $ | (56.8 | )

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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Effect of Derivative Instruments
The following tables provide information on the effects of derivative instruments in the Consolidated Statements of Income and changes in AOCI and noncontrolling interests for Fiscal 2015, Fiscal 2014 and Fiscal 2013:

| Gain or (Loss) Recognized in AOCI and Noncontrolling Interests |  | Gain or (Loss) Reclassified from AOCI and Noncontrolling Interests into Income |  | Location of Gain or (Loss) Reclassified from AOCI and Noncontrolling Interests into Income
| 2015 |  | 2014 |  | 2013 |  | 2015 |  | 2014 |  | 2013 |
Cash Flow Hedges: |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts | $ | — |  |  | $ | 50.8 |  |  | $ | 8.3 |  |  | $ | (2.2 | ) |  | $ | 67.0 |  |  | $ | (49.5 | ) |  | Cost of sales
Foreign currency contracts | 26.0 |  |  | 15.3 |  |  | (8.3 | ) |  | 9.7 |  |  | (3.7 | ) |  | (0.1 | ) |  | Cost of sales
Cross-currency contracts | 5.4 |  |  | 3.1 |  |  | (1.2 | ) |  | 8.5 |  |  | (0.1 | ) |  | — |  |  | Interest expense
Interest rate contracts | (6.6 | ) |  | (3.1 | ) |  | 22.9 |  |  | (20.4 | ) |  | (15.9 | ) |  | (14.2 | ) |  | Interest expense /other income, net
Total | $ | 24.8 |  |  | $ | 66.1 |  |  | $ | 21.7 |  |  | $ | (4.4 | ) |  | $ | 47.3 |  |  | $ | (63.8 | ) |  |

| Gain or (Loss) Recognized in Income | Location of Gain or (Loss) Recognized in Income |
| 2015 |  | 2014 |  | 2013
Derivatives Not Designated as Hedging Instruments: |  |  |  |  |  |  |
Commodity contracts | $ | (375.8 | ) |  | $ | (36.3 | ) |  | $ | 9.3 |  | Cost of sales |
Commodity contracts | 0.3 |  |  | — |  |  | — |  | Revenues |
Commodity contracts | (0.8 | ) |  | — |  |  | — |  | Operating and administrative expenses / other income, net |
Foreign currency contracts | — |  |  | — |  |  | (0.4 | ) | Other income, net |
Total | $ | (376.3 | ) |  | $ | (36.3 | ) |  | $ | 8.9 |  |  |

The amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material for Fiscal 2015, Fiscal 2014 and Fiscal 2013.
In May 2015, the Company prepaid term loans outstanding under the 2011 Senior Facilities Agreement. In conjunction with the prepayment, the Company also settled its associated pay-fixed, receive-variable interest rate swaps, and discontinued cash flow hedge accounting treatment for such swaps. During Fiscal 2015, the Company recorded a pre-tax loss of $9.0 associated with the discontinuance of cash flow hedge accounting for the swaps, which amount is included in interest expense on the Consolidated Statements of Income (see Note 6).
We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts that provide for the purchase and delivery, or sale, of energy products, 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, certain of these contracts qualify for NPNS 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.
Note 19 — Accumulated Other Comprehensive Income
Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and intracompany transaction adjustments.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Changes in AOCI during Fiscal 2015 and Fiscal 2014 are as follows:

| Postretirement Benefit Plans |  | Derivative Instruments |  | Foreign Currency (a) |  | Total
AOCI - September 30, 2013 | $ | (16.4 | ) |  | $ | (26.9 | ) |  | $ | 51.7 |  |  | $ | 8.4 |
Other comprehensive (loss) income before reclassification adjustments (after-tax) | (5.2 | ) |  | 54.0 |  |  | (43.0 | ) |  | 5.8 |
Amounts reclassified from AOCI and noncontrolling interests: |  |  |  |  |  |  |
Reclassification adjustments (pre-tax) | 1.6 |  |  | (47.2 | ) |  | — |  |  | (45.6 | )
Reclassification adjustments tax (expense) benefit | (0.6 | ) |  | 2.0 |  |  | — |  |  | 1.4 |
Reclassification adjustments (after-tax) | 1.0 |  |  | (45.2 | ) |  | — |  |  | (44.2 | )
Other comprehensive (loss) income | (4.2 | ) |  | 8.8 |  |  | (43.0 | ) |  | (38.4 | )
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners | — |  |  | 8.8 |  |  | — |  |  | 8.8 |
Other comprehensive (loss) income attributable to UGI | (4.2 | ) |  | 17.6 |  |  | (43.0 | ) |  | (29.6 | )
AOCI - September 30, 2014 | $ | (20.6 | ) |  | $ | (9.3 | ) |  | $ | 8.7 |  |  | $ | (21.2 | )
Other comprehensive (loss) income before reclassification adjustments (after-tax) | (1.2 | ) |  | 16.8 |  |  | (114.1 | ) |  | (98.5 | )
Amounts reclassified from AOCI and noncontrolling interests: |  |  |  |  |  |  |
Reclassification adjustments (pre-tax) | 2.2 |  |  | 4.4 |  |  | — |  |  | 6.6 |
Reclassification adjustments tax (expense) | (0.8 | ) |  | (2.8 | ) |  | — |  |  | (3.6 | )
Reclassification adjustments (after-tax) | 1.4 |  |  | 1.6 |  |  | — |  |  | 3.0 |
Other comprehensive income (loss) | 0.2 |  |  | 18.4 |  |  | (114.1 | ) |  | (95.5 | )
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners | — |  |  | 2.1 |  |  | — |  |  | 2.1 |
Other comprehensive income (loss) attributable to UGI | 0.2 |  |  | 20.5 |  |  | (114.1 | ) |  | (93.4 | )
AOCI - September 30, 2015 | $ | (20.4 | ) |  | $ | 11.2 |  |  | $ | (105.4 | ) |  | $ | (114.6 | )

(a) | See Note 2 relating to correction of prior period error in comprehensive income.

For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 18.
Note 20 — Other Income, Net
Other income, net, comprises the following:

| 2015 |  | 2014 |  | 2013
Interest and interest-related income | $ | 0.8 |  |  | $ | 3.6 |  |  | $ | 2.2 |
Utility non-tariff service income | 4.8 |  |  | 2.7 |  |  | 2.8 |
Finance charges | 12.7 |  |  | 17.5 |  |  | 21.4 |
Gains on sales of fixed assets | 11.1 |  |  | 5.4 |  |  | 1.4 |
Loss on private equity partnership investment | — |  |  | — |  |  | (6.3 | )
Other, net | 15.0 |  |  | 6.9 |  |  | 11.3 |
Total other income, net | $ | 44.4 |  |  | $ | 36.1 |  |  | $ | 32.8 |

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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 21 — Quarterly Data (unaudited)
The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) which we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate because of the seasonal nature of our businesses.

| December 31, |  | March 31, |  | June 30, |  | September 30,
| 2014 | 2013(a) |  | 2015 | 2014 |  | 2015(b) | 2014 |  | 2015 | 2014
Revenues | $ | 2,004.6 |  | $ | 2,315.9 |  |  | $ | 2,455.6 |  | $ | 3,163.3 |  |  | $ | 1,148.1 |  | $ | 1,486.7 |  |  | $ | 1,082.8 |  | $ | 1,311.4 |
Operating income (loss) | $ | 83.3 |  | $ | 363.7 |  |  | $ | 702.1 |  | $ | 588.6 |  |  | $ | 56.1 |  | $ | 62.7 |  |  | $ | (6.6 | ) | $ | (9.4 | )
Net income (loss) including noncontrolling interests | $ | 0.2 |  | $ | 217.5 |  |  | $ | 482.2 |  | $ | 387.8 |  |  | $ | (15.9 | ) | $ | (12.7 | ) |  | $ | (52.5 | ) | $ | (60.0 | )
Net income (loss) attributable to UGI Corporation | $ | 34.1 |  | $ | 122.0 |  |  | $ | 246.5 |  | $ | 214.4 |  |  | $ | 9.6 |  | $ | 20.6 |  |  | $ | (9.2 | ) | $ | (19.8 | )
Earnings (loss) per common share attributable to UGI Corporation stockholders: |  |  |  |  |  |  |  |  |  |  |
Basic | $ | 0.20 |  | $ | 0.71 |  |  | $ | 1.42 |  | $ | 1.24 |  |  | $ | 0.06 |  | $ | 0.12 |  |  | $ | (0.05 | ) | $ | (0.11 | )
Diluted | $ | 0.19 |  | $ | 0.70 |  |  | $ | 1.40 |  | $ | 1.22 |  |  | $ | 0.05 |  | $ | 0.12 |  |  | $ | (0.05 | ) | $ | (0.11 | )

(a) | Includes income tax expense of $5.7 to reflect the retroactive effects to Fiscal 2013 of new tax legislation in France regarding the deductibility of certain interest expense which decreased net income attributable to UGI Corporation by $5.7 or $0.03 per diluted share (see Note 7).

(b) | Includes loss on early extinguishment of debt at Antargaz which decreased net income attributable to UGI Corporation by $4.6 or $0.03 per diluted share (see Note 6)

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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 22 — Segment Information
Our operations comprise six reportable segments generally based upon products sold, geographic location and regulatory environment. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising UGI France (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) Gas Utility; (5) Energy Services; and (6) Electric Generation. We refer to both international segments together as “UGI International” and Energy Services and Electric Generation together as “Midstream & Marketing.”
AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers in all 50 states. UGI France derives its revenues principally from the distribution of LPG to retail customers in France and, to a lesser extent, the sale of LPG to retail customers in Belgium, the Netherlands and Luxembourg, and the marketing of natural gas in France and Belgium. Flaga & Other revenues are derived principally from the distribution of LPG to customers in northern, central and eastern Europe and the United Kingdom. Gas Utility’s revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Energy Services revenues are derived from the sale of natural gas and, to a lesser extent, electricity, LPG and fuel oil as well as revenues and fees from storage, pipeline transportation, natural gas production and other energy services provided to customers located primarily in the Mid-Atlantic region of the United States. Electric Generation revenues are derived principally from the sale of electricity through PJM, a regional electricity transmission organization in the eastern U.S.
The accounting policies of our reportable segments are the same as those described in Note 2. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization as adjusted for net gains and losses on commodity derivative instruments not associated with current-period transactions (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies.
We evaluate the performance of our other reportable segments principally based upon their income before income taxes as adjusted for gains and losses on commodity derivative instruments not associated with current-period transactions. Net gains and losses on commodity derivative instruments not associated with current-period transactions are reflected in Corporate & Other because the Company’s chief operating decision maker does not consider such items when evaluating the financial performance of our reportable segments.
No single customer represents more than ten percent of our consolidated revenues. In addition, all of our reportable segments’ revenues, other than those of UGI International, are derived from sources within the United States, and all of our reportable segments’ long-lived assets, other than those of UGI International, are located in the United States.

|  |  |  |  |  |  |  |  | Midstream & Marketing |  | UGI International |  |
| Total |  | Elim- inations |  | AmeriGas Propane |  | Gas Utility |  | Energy Services |  | Electric Generation |  | UGI France |  | Flaga & Other |  | Corporate & Other (b)
2015 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues | $ | 6,691.1 |  |  | $ | (232.6 | ) | (c) | $ | 2,885.3 |  |  | $ | 933.1 |  |  | $ | 1,041.8 |  |  | $ | 75.9 |  |  | $ | 1,122.2 |  |  | $ | 686.3 |  |  | $ | 179.1 |
Cost of sales | $ | 3,736.5 |  |  | $ | (228.8 | ) | (c) | $ | 1,340.0 |  |  | $ | 448.6 |  |  | $ | 800.9 |  |  | $ | 32.2 |  |  | $ | 628.0 |  |  | $ | 492.0 |  |  | $ | 223.6 |
Operating income (loss) | $ | 834.9 |  |  | $ | (0.9 | ) |  | $ | 427.6 |  |  | $ | 226.5 |  |  | $ | 171.8 |  |  | $ | 13.0 |  |  | $ | 75.9 |  |  | $ | 36.9 |  |  | $ | (115.9 | )
Loss from equity investees | (1.2 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1.2 | ) |  | — |  |  | — |
Interest expense | (241.9 | ) |  | — |  |  | (162.8 | ) |  | (39.1 | ) |  | (2.1 | ) |  | — |  |  | (31.6 | ) | (d) | (3.6 | ) |  | (2.7 | )
Income (loss) before income taxes | $ | 591.8 |  |  | $ | (0.9 | ) |  | $ | 264.8 |  |  | $ | 187.4 |  |  | $ | 169.7 |  |  | $ | 13.0 |  |  | $ | 43.1 |  |  | $ | 33.3 |  |  | $ | (118.6 | )
Net income (loss) attributable to UGI | $ | 281.0 |  |  | $ | (0.6 | ) |  | $ | 61.0 |  |  | $ | 115.8 |  |  | $ | 99.3 |  |  | $ | 9.6 |  |  | $ | 27.5 |  |  | $ | 25.2 |  |  | $ | (56.8 | )
Depreciation and amortization | $ | 374.1 |  |  | $ | — |  |  | $ | 194.9 |  |  | $ | 59.0 |  |  | $ | 14.6 |  |  | $ | 12.5 |  |  | $ | 63.7 |  |  | $ | 23.2 |  |  | $ | 6.2 |
Noncontrolling interests’ net income (loss) | $ | 133.0 |  |  | $ | — |  |  | $ | 167.9 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (0.1 | ) |  | $ | (34.8 | )
Partnership Adjusted EBITDA (a) |  |  |  |  | $ | 619.2 |  |  |  |  |  |  |  |  |  |  |  |  |

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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

|  |  |  |  |  |  |  |  | Midstream & Marketing |  | UGI International |  |
| Total |  | Elim- inations |  | AmeriGas Propane |  | Gas Utility |  | Energy Services |  | Electric Generation |  | UGI France |  | Flaga & Other |  | Corporate & Other (b)
Total assets | $ | 10,546.6 |  |  | $ | (90.4 | ) |  | $ | 4,150.0 |  |  | $ | 2,362.4 |  |  | $ | 664.3 |  |  | $ | 282.0 |  |  | $ | 2,340.4 |  |  | $ | 529.1 |  |  | $ | 308.8 |
Short-term borrowings | $ | 189.9 |  |  | $ | — |  |  | $ | 68.1 |  |  | $ | 71.7 |  |  | $ | 49.5 |  |  | $ | — |  |  | $ | 0.1 |  |  | $ | 0.5 |  |  | $ | — |
Capital expenditures | $ | 475.4 |  |  | $ | — |  |  | $ | 102.0 |  |  | $ | 189.7 |  |  | $ | 71.5 |  |  | $ | 16.7 |  |  | $ | 65.0 |  |  | $ | 22.5 |  |  | $ | 8.0 |
Investments in equity investees | $ | 16.2 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 6.4 |  |  | $ | — |  |  | $ | 6.0 |  |  | $ | 3.8 |  |  | $ | — |
Goodwill | $ | 2,953.4 |  |  | $ | — |  |  | $ | 1,956.0 |  |  | $ | 182.1 |  |  | $ | 5.6 |  |  | $ | — |  |  | $ | 721.4 |  |  | $ | 82.3 |  |  | $ | 6.0 |
2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues | $ | 8,277.3 |  |  | $ | (321.3 | ) | (c) | $ | 3,712.9 |  |  | $ | 977.3 |  |  | $ | 1,305.5 |  |  | $ | 85.1 |  |  | $ | 1,295.5 |  |  | $ | 1,026.9 |  |  | $ | 195.4 |
Cost of sales | $ | 5,175.7 |  |  | $ | (317.7 | ) | (c) | $ | 2,107.1 |  |  | $ | 496.8 |  |  | $ | 1,058.8 |  |  | $ | 39.6 |  |  | $ | 848.1 |  |  | $ | 809.9 |  |  | $ | 133.1 |
Operating income (loss) | $ | 1,005.6 |  |  | $ | 0.2 |  |  | $ | 472.0 |  |  | $ | 236.2 |  |  | $ | 180.5 |  |  | $ | 18.1 |  |  | $ | 79.1 |  |  | $ | 38.4 |  |  | $ | (18.9 | )
Loss from equity investees | (0.1 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (0.1 | ) |  | — |  |  | — |
Interest expense | (237.7 | ) |  | — |  |  | (165.6 | ) |  | (36.6 | ) |  | (2.9 | ) |  | — |  |  | (25.1 | ) |  | (4.9 | ) |  | (2.6 | )
Income (loss) before income taxes | 767.8 |  |  | 0.2 |  |  | 306.4 |  |  | 199.6 |  |  | 177.6 |  |  | 18.1 |  |  | 53.9 |  |  | 33.5 |  |  | (21.5 | )
Net income (loss) attributable to UGI | $ | 337.2 |  |  | $ | — |  |  | $ | 63.0 |  |  | $ | 118.8 |  |  | $ | 105.2 |  |  | $ | 12.6 |  |  | $ | 20.6 |  |  | $ | 27.7 |  |  | $ | (10.7 | )
Depreciation and amortization | $ | 362.9 |  |  | $ | — |  |  | $ | 197.2 |  |  | $ | 54.8 |  |  | $ | 12.3 |  |  | $ | 10.7 |  |  | $ | 54.5 |  |  | $ | 27.1 |  |  | $ | 6.3 |
Noncontrolling interests’ net income (loss) | $ | 195.4 |  |  | $ | — |  |  | $ | 195.8 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (0.4 | ) |  | $ | — |  |  | $ | — |
Partnership Adjusted EBITDA (a) |  |  |  |  |  | $ | 664.8 |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets | $ | 10,093.0 |  |  | $ | (86.5 | ) |  | $ | 4,377.0 |  |  | $ | 2,214.1 |  |  | $ | 569.0 |  |  | $ | 277.7 |  |  | $ | 1,659.1 |  |  | $ | 643.6 |  |  | $ | 439.0 |
Short-term borrowings | $ | 210.8 |  |  | $ | — |  |  | $ | 109.0 |  |  | $ | 86.3 |  |  | $ | 7.5 |  |  | $ | — |  |  | $ | — |  |  | $ | 8.0 |  |  | $ | — |
Capital expenditures | $ | 436.4 |  |  | $ | — |  |  | $ | 113.9 |  |  | $ | 156.4 |  |  | $ | 67.8 |  |  | $ | 15.6 |  |  | $ | 50.2 |  |  | $ | 23.0 |  |  | $ | 9.5 |
Investments in equity investees | $ | 0.6 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 0.6 |  |  | $ | — |
Goodwill | $ | 2,833.4 |  |  | $ | — |  |  | $ | 1,945.1 |  |  | $ | 182.1 |  |  | $ | 5.6 |  |  | $ | — |  |  | $ | 601.2 |  |  | $ | 92.4 |  |  | $ | 7.0 |
2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues | $ | 7,194.7 |  |  | $ | (223.8 | ) | (c) | $ | 3,168.8 |  |  | $ | 839.0 |  |  | $ | 969.4 |  |  | $ | 71.4 |  |  | $ | 1,322.6 |  |  | $ | 856.6 |  |  | $ | 190.7 |
Cost of sales | $ | 4,324.4 |  |  | $ | (217.5 | ) | (c) | $ | 1,657.2 |  |  | $ | 407.2 |  |  | $ | 836.9 |  |  | $ | 39.9 |  |  | $ | 845.0 |  |  | $ | 653.4 |  |  | $ | 102.3 |
Operating income | $ | 831.1 |  |  | $ | (1.1 | ) |  | $ | 394.4 |  |  | $ | 196.5 |  |  | $ | 82.5 |  |  | $ | 7.5 |  |  | $ | 111.4 |  |  | $ | 35.6 |  |  | $ | 4.3 |
Loss from equity investees | (0.4 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (0.4 | ) |  | — |  |  | — |
Interest expense | (240.3 | ) |  | — |  |  | (166.6 | ) |  | (37.4 | ) |  | (3.2 | ) |  | — |  |  | (25.3 | ) |  | (5.1 | ) |  | (2.7 | )
Income before income taxes | $ | 590.4 |  |  | $ | (1.1 | ) |  | $ | 227.8 |  |  | $ | 159.1 |  |  | $ | 79.3 |  |  | $ | 7.5 |  |  | $ | 85.7 |  |  | $ | 30.5 |  |  | $ | 1.6 |
Net income attributable to UGI | $ | 278.1 |  |  | $ | (0.6 | ) |  | $ | 47.5 |  |  | $ | 94.3 |  |  | $ | 46.3 |  |  | $ | 6.2 |  |  | $ | 57.2 |  |  | $ | 25.5 |  |  | $ | 1.7 |
Depreciation and amortization | $ | 363.1 |  |  | $ | — |  |  | $ | 205.9 |  |  | $ | 51.7 |  |  | $ | 7.6 |  |  | $ | 10.0 |  |  | $ | 57.6 |  |  | $ | 24.1 |  |  | $ | 6.2 |
Noncontrolling interests’ net income (loss) | $ | 149.5 |  |  | $ | — |  |  | $ | 149.6 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (0.2 | ) |  | $ | 0.1 |  |  | $ | — |
Partnership Adjusted EBITDA (a) |  |  |  |  | $ | 596.5 |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets | $ | 10,008.8 |  |  | $ | (100.3 | ) |  | $ | 4,429.3 |  |  | $ | 2,069.0 |  |  | $ | 501.2 |  |  | $ | 269.7 |  |  | $ | 1,784.4 |  |  | $ | 667.1 |  |  | $ | 388.4 |
Short-term borrowings | $ | 227.9 |  |  | $ | — |  |  | $ | 116.9 |  |  | $ | 17.5 |  |  | $ | 87.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 6.5 |  |  | $ | — |
Capital expenditures | $ | 488.0 |  |  | $ | (1.1 | ) |  | $ | 111.1 |  |  | $ | 144.4 |  |  | $ | 133.8 |  |  | $ | 22.6 |  |  | $ | 53.4 |  |  | $ | 17.4 |  |  | $ | 6.4 |
Investments in equity investees | $ | 0.3 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 0.3 |  |  | $ | — |
Goodwill | $ | 2,873.7 |  |  | $ | — |  |  | $ | 1,941.0 |  |  | $ | 182.1 |  |  | $ | 2.8 |  |  | $ | — |  |  | $ | 643.7 |  |  | $ | 97.1 |  |  | $ | 7.0 |

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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

(a) | The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income:

|  | 2015 |  | 2014 |  | 2013
Partnership Adjusted EBITDA |  | $ | 619.2 |  |  | $ | 664.8 |  |  | $ | 596.5 |
Depreciation and amortization |  | (194.9 | ) |  | (197.2 | ) |  | (205.9 | )
Noncontrolling interests (i) |  | 3.3 |  |  | 4.4 |  |  | 3.8 |
Operating income |  | $ | 427.6 |  |  | $ | 472.0 |  |  | $ | 394.4 |

(i) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

(b) | Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $(119.1), $(18.0) and $7.4 in Fiscal 2015, Fiscal 2014 and Fiscal 2013, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC. Through March 2014, Corporate & Other also had an intercompany loan. The intercompany loan interest is removed in the segment presentation.

(c) | Represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.

(d) | Includes pre-tax loss of $10.3 associated with an early extinguishment of debt (see Note 6).

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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
BALANCE SHEETS
(Millions of dollars)

| September 30,
| 2015 |  | 2014
ASSETS |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 1.9 |  |  | $ | 0.8 |
Accounts receivable - related parties | 3.3 |  |  | 3.9 |
Deferred income taxes | 0.4 |  |  | 0.4 |
Prepaid expenses and other current assets | 4.3 |  |  | 0.3 |
Total current assets | 9.9 |  |  | 5.4 |
Investments in subsidiaries | 2,689.7 |  |  | 2,663.9 |
Other assets | 58.7 |  |  | 55.5 |
Total assets | $ | 2,758.3 |  |  | $ | 2,724.8 |
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY |  |  |
Current liabilities: |  |  |
Accounts and notes payable | $ | 10.9 |  |  | $ | 11.8 |
Accrued liabilities | 5.0 |  |  | 6.0 |
Total current liabilities | 15.9 |  |  | 17.8 |
Noncurrent liabilities | 50.4 |  |  | 47.9 |
Commitments and contingencies (Note 1) |  |  |
Common stockholders’ equity: |  |  |
Common Stock, without par value (authorized - 450,000,000 shares; issued - 173,806,991 and 173,770,641 shares, respectively) | 1,214.6 |  |  | 1,215.6 |
Retained earnings | 1,636.9 |  |  | 1,509.4 |
Accumulated other comprehensive loss | (114.6 | ) |  | (21.2 | )
Treasury stock, at cost | (44.9 | ) |  | (44.7 | )
Total common stockholders’ equity | 2,692.0 |  |  | 2,659.1 |
Total liabilities and common stockholders’ equity | $ | 2,758.3 |  |  | $ | 2,724.8 |

Note 1 — Commitments and Contingencies:
In addition to the guarantees of Flaga’s debt as described in Notes 5 and 6 to Consolidated Financial Statements, at September 30, 2015, UGI Corporation had agreed to indemnify the issuers of $71.1 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $500.0 of obligations to suppliers and customers of Energy Services and subsidiaries of which $445.3 of such obligations were outstanding as of September 30, 2015. UGI Corporation has guaranteed the floating to fixed rate interest rate swaps at Flaga, which obligations totaled $1.2 at September 30, 2015.
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UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)

| Year Ended September 30,
| 2015 |  | 2014 |  | 2013
Revenues | $ | — |  |  | $ | — |  |  | $ | — |
Costs and expenses: |  |  |  |  |
Operating and administrative expenses | 48.7 |  |  | 44.5 |  |  | 36.9 |
Other income, net (a) | (48.5 | ) |  | (44.2 | ) |  | (36.7 | )
| 0.2 |  |  | 0.3 |  |  | 0.2 |
Operating loss | (0.2 | ) |  | (0.3 | ) |  | (0.2 | )
Intercompany interest income | 0.1 |  |  | 0.2 |  |  | 0.2 |
Loss before income taxes | (0.1 | ) |  | (0.1 | ) |  | — |
Income tax expense | 1.9 |  |  | 2.4 |  |  | 3.1 |
Loss before equity in income of unconsolidated subsidiaries | (2.0 | ) |  | (2.5 | ) |  | (3.1 | )
Equity in income of unconsolidated subsidiaries | 283.0 |  |  | 339.7 |  |  | 281.2 |
Net income attributable to UGI Corporation | $ | 281.0 |  |  | $ | 337.2 |  |  | $ | 278.1 |
Other comprehensive income (loss) | 0.1 |  |  | (0.7 | ) |  | 1.1 |
Equity in other comprehensive (loss) income of unconsolidated subsidiaries | (93.5 | ) |  | (28.9 | ) |  | 62.5 |
Comprehensive income attributable to UGI Corporation | $ | 187.6 |  |  | $ | 307.6 |  |  | $ | 341.7 |
Earnings per common share: |  |  |  |  |
Basic | $ | 1.62 |  |  | $ | 1.95 |  |  | $ | 1.63 |
Diluted | $ | 1.60 |  |  | $ | 1.92 |  |  | $ | 1.60 |
Average common shares outstanding (thousands): |  |  |  |  |
Basic | 173,115 |  |  | 172,733 |  |  | 170,885 |
Diluted | 175,667 |  |  | 175,231 |  |  | 173,282 |

(a) | UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers the relative percentage of such items for each subsidiary 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 its subsidiaries. These billed expenses are classified as “Other income, net” in the Statements of Income above.

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UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(Millions of dollars)

| Year Ended September 30,
| 2015 |  | 2014 |  | 2013
NET CASH PROVIDED BY OPERATING ACTIVITIES (a) | $ | 277.2 |  |  | $ | 199.7 |  |  | $ | 139.4 |
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |  |
Net investments in unconsolidated subsidiaries | (104.8 | ) |  | (47.3 | ) |  | (59.1 | )
Net cash used by investing activities | (104.8 | ) |  | (47.3 | ) |  | (59.1 | )
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |  |  |
Payment of dividends on Common Stock | (153.5 | ) |  | (136.1 | ) |  | (125.8 | )
Purchases of UGI Common Stock | (34.1 | ) |  | (39.8 | ) |  | — |
Issuances of Common Stock | 16.8 |  |  | 23.4 |  |  | 44.5 |
Other | (0.5 | ) |  | — |  |  | — |
Net cash used by financing activities | (171.3 | ) |  | (152.5 | ) |  | (81.3 | )
Cash and cash equivalents increase (decrease) | $ | 1.1 |  |  | $ | (0.1 | ) |  | $ | (1.0 | )
Cash and cash equivalents: |  |  |  |  |
End of year | $ | 1.9 |  |  | $ | 0.8 |  |  | $ | 0.9 |
Beginning of year | 0.8 |  |  | 0.9 |  |  | 1.9 |
Increase (decrease) | $ | 1.1 |  |  | $ | (0.1 | ) |  | $ | (1.0 | )

(a) | Includes dividends received from unconsolidated subsidiaries of $271.6, $186.4 and $155.2 for the years ended September 30, 2015, 2014 and 2013, respectively.

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UGI CORPORATION AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)

| Balance at beginning of year |  | Charged (credited) to costs and expenses |  | Other |  | Balance at end of year |
Year Ended September 30, 2015 |  |  |  |  |  |  |  |
Reserves deducted from assets in the consolidated balance sheet: |  |  |  |  |  |  |  |
Allowance for doubtful accounts | $ | 39.1 |  |  | $ | 31.6 |  |  | $ | (39.6 | ) | (1) | $ | 29.7 |  |
|  |  |  |  | (1.4 | ) | (2) |  |
Other reserves: |  |  |  |  |  |  |  |
Deferred tax assets valuation allowance | $ | 59.2 |  |  | $ | 5.1 |  |  | $ | 66.1 |  | (3) | $ | 131.3 |  |
|  |  |  |  | (2.6 | ) | (4) |  |
|  |  |  |  | 3.5 |  | (5) |  |
Year Ended September 30, 2014 |  |  |  |  |  |  |  |
Reserves deducted from assets in the consolidated balance sheet: |  |  |  |  |  |  |  |
Allowance for doubtful accounts | $ | 39.5 |  |  | $ | 43.5 |  |  | $ | (43.0 | ) | (1) | $ | 39.1 |  |
|  |  |  |  | (0.9 | ) | (2) |  |
Other reserves: |  |  |  |  |  |  |  |
Deferred tax assets valuation allowance | $ | 97.6 |  |  | $ | 0.4 |  |  | (34.0 | ) | (3) | $ | 59.2 |  |
|  |  |  |  | (4.8 | ) | (4) |  |
Year Ended September 30, 2013 |  |  |  |  |  |  |  |
Reserves deducted from assets in the consolidated balance sheet: |  |  |  |  |  |  |  |
Allowance for doubtful accounts | $ | 36.1 |  |  | $ | 30.2 |  |  | $ | (27.4 | ) | (1) | $ | 39.5 |  |
|  |  |  |  | 0.6 |  | (2) |  |
Other reserves: |  |  |  |  |  |  |  |
Deferred tax assets valuation allowance | $ | 77.0 |  |  | $ | (5.7 | ) |  | $ | 26.3 |  | (3) | $ | 97.6 |  |

(1) | Uncollectible accounts written off, net of recoveries.

(2) | Effects of currency exchange.

(3) | Foreign tax credit valuation allowance adjustment.

(4) | Decrease in unusable foreign operating loss carryforwards.

(5) | Acquisitions

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EXHIBIT INDEX

Exhibit No. | Description
10.26 | Description of oral compensation arrangements for Messrs. Walsh, Hall, and Oliver and Ms. Gaudiosi.
10.28 | Summary of Director Compensation as of October 1, 2015.
21 | Subsidiaries of the Registrant
23.1 | Consent of Ernst & Young LLP
23.2 | Consent of PricewaterhouseCoopers LLP
31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2015 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-K for the fiscal year ended September 30, 2015 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-K for the fiscal year ended September 30, 2015, 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