10-K
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
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:
| |
• | UGI International - UGI France |
| |
• | UGI International - Flaga & Other |
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
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.
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
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
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®”,
“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.
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.
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.
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:
|
| | | | | | | | |
| 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 |
|
_________________
| |
(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.
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.
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
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.
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.
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
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.
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
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.
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
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.
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.
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
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.
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.
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; |
| |
• | 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.
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.
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.
| |
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 | % |
|
| | | | | | | | | | | | | | | | | | | | |
| | 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.”
| |
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
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
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.
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. |
|
| | | | | | | | | | | | | | | |
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.
|
| | | | | | | | | | | | | | | |
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
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
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.
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. |
|
| | | | | | | | | | | | | | | |
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
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
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.
|
| | | | | | | | | | | | | | | |
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.
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
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
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”)).
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.
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 | | |