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, 2014
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
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, 2014 was $5,249,082,631.
At November 18, 2014, there were 172,425,384 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 29, 2015 are incorporated by reference into Part III of this Form 10-K.
TABLE OF CONTENTS
Page | |
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FORWARD-LOOKING INFORMATION
Information contained in this Annual Report on Form 10-K may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other liquefied petroleum gases, oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax, consumer protection and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers and retain current customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) large customer, counterparty or supplier defaults; (12) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and liquefied petroleum gases (“LPG”); (13) political, regulatory and economic conditions in the United States and in foreign countries, including the current conflicts in the Middle East and those involving Russia, 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 and electrical contracting services. Our subsidiaries and affiliates operate principally in the following six business segments:
• | AmeriGas Propane |
• | UGI International - Antargaz |
• | UGI International - Flaga & Other |
• | Energy Services |
• | Electric Generation |
• | Gas Utility |
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The AmeriGas Propane segment consists of the propane distribution business of AmeriGas Partners, L.P. (“AmeriGas Partners” or the “Partnership”), which is the nation’s largest retail propane distributor. The Partnership’s sole general partner is our subsidiary, AmeriGas Propane, Inc. (“AmeriGas Propane” or the “General Partner”). The common units of AmeriGas Partners represent limited partner interests in a Delaware limited partnership and trade on the New York Stock Exchange under the symbol “APU.” We have an effective 26% ownership interest in the Partnership and the remaining interest is publicly held. See Note 1 to Consolidated Financial Statements.
The UGI International - Antargaz segment consists of the LPG distribution business of our wholly-owned subsidiary Antargaz, a French société anonyme, and our LPG distribution businesses in the Benelux countries (consisting of Belgium, the Netherlands, and Luxembourg) (collectively, “Antargaz”). Antargaz is one of the largest retail distributors of LPG in France and the Netherlands and the largest retail distributor of LPG in Belgium and Luxembourg.
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 and Denmark and one of the largest in Poland, the Czech Republic, Hungary, Slovakia, Norway, Sweden, and Finland. Flaga also distributes LPG in Romania and Switzerland. AvantiGas is an LPG distributor in the United Kingdom. ChinaGas Partners is an LPG distributor in the Nantong region of China. The UGI International - Antargaz and UGI International - 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 (formerly known as UGI Energy Services, Inc. prior to its merger with and into UGI Energy Services, LLC, effective October 1, 2013) (“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 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) 11.67 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 over 600,000 customers in eastern and central Pennsylvania and several 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 several 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 and electrical contracting service business in portions of eastern Pennsylvania and the Mid-Atlantic region of the U.S. through UGI HVAC Enterprises, Inc. (“HVAC”).
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 2014, 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 November 11, 2014, our indirect wholly-owned French subsidiary, UGI Bordeaux Holding, entered into a Share Purchase Agreement with Total Marketing Services, a subsidiary of Total, to acquire all of the outstanding shares of Totalgaz, Total’s LPG distribution business in France (the “Total Acquisition”). Totalgaz distributed over 265 million retail gallons of LPG in 2013,
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serving residential, commercial, industrial, and autogas customers. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
In the first quarter of Fiscal 2014, Energy Services placed its newly constructed 28-mile gathering pipeline and compressor station into service (Auburn II). The newly constructed pipeline transports locally produced natural gas from Energy Services’ compressor station in the Marcellus Shale region of Pennsylvania to PNG and two interstate pipelines. During Fiscal 2014, Energy Services also announced (i) a pipeline project to further expand its gathering system in the Marcellus Shale region of Pennsylvania (Auburn III), (ii) a pipeline project to transport locally produced natural gas to PNG (the Union Dale Lateral), and (iii) a joint project to develop an approximately 100-mile pipeline from Pennsylvania to New Jersey (the PennEast Pipeline Project). Energy Services also announced a project to increase the liquefaction capacity of its natural gas liquefaction, storage, and vaporization facility in Temple, Pennsylvania (the Temple Facility) in the fiscal year ending September 30, 2015 (“Fiscal 2015”).
In Fiscal 2014, Energy Services also acquired a retail natural gas marketing business from EQT Energy, LLC and expanded its industrial and commercial customer base in western Pennsylvania. See Note 4 to the Consolidated Financial Statements.
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.
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,” 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 2014” and “Fiscal 2013” refer to the fiscal years ended September 30, 2014 and September 30, 2013, 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 Daniel J. Platt, Treasurer, UGI Corporation, P.O. Box 858, Valley Forge, PA 19482.
The Company’s common stock (“Common Stock”) trades 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. All shares and per share data provided herein gives effect to this stock split, applied retroactively.
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AMERIGAS PROPANE
Products, Services and Marketing
Our domestic propane distribution business is conducted through AmeriGas Partners. AmeriGas Propane is responsible for managing the Partnership. The Partnership serves approximately 2 million customers in all 50 states from over 2,000 propane distribution locations. In addition to distributing propane, the Partnership also sells, installs and services propane appliances, including heating systems. Typically, the Partnership’s locations are in suburban and rural areas where natural gas is not readily available. Our district 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 nearly 1.4 billion gallons of propane in Fiscal 2014. Approximately 93% of the Partnership’s Fiscal 2014 sales (based on gallons sold) were to retail accounts and approximately 7% were to wholesale and supply customers. Sales to residential customers in Fiscal 2014 represented approximately 41% of retail gallons sold; commercial/industrial customers 36%; motor fuel customers 13%; and agricultural customers 6%. Transport gallons, which are large-scale deliveries to retail customers other than residential, accounted for 4% of Fiscal 2014 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 Propane Exchange (“Propane Exchange”) program. At September 30, 2014, Propane Exchange cylinders were available at nearly 49,000 retail locations throughout the U.S. Sales of our Propane Exchange cylinders to retailers are included in commercial/industrial sales. The Propane Exchange 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, and crop drying. 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 Propane Exchange 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 U.S. 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. During Fiscal 2014, over 90% of the Partnership’s propane supply was purchased under supply agreements with terms of 1 to 3 years. The availability 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. During the winter heating season of Fiscal 2014, there were wholesale supply challenges in certain regions of the U.S. due to industry-wide storage and transportation issues. These issues were exacerbated by prolonged periods of unusually cold winter weather, record volumes during the fall crop drying season that depleted propane storage inventories for the winter heating season, and an increase in demand for domestic propane overseas from the U.S.’ propane export market. The Partnership responded to these issues by instituting supply allocation measures, procuring propane from alternative supply sources, using its extensive transportation network to transport existing propane supplies to areas of the country that were most affected by the winter weather, and deploying employees from areas of the country that were less affected by the weather to those areas in need. 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 Fiscal 2015. 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 46% of the Partnership’s
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Fiscal 2014 propane supply. No other single supplier provided more than 10% of the Partnership’s total propane supply in Fiscal 2014. 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.
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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 Propane Exchange program and the National Accounts program (through which the Partnership encourages multi-location propane users to enter into a supply agreement with it rather than with many 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 2014, the Partnership’s retail propane sales totaled nearly 1.3 billion gallons. Based on the most recent annual survey by the American Petroleum Institute, 2012 domestic retail propane sales (annual sales for other than chemical uses) in the U.S. totaled approximately 7.7 billion gallons. Based on LP-GAS magazine rankings, 2012 sales volume of the ten largest propane companies (including AmeriGas Partners) represented approximately 40% of domestic retail sales.
Properties
As of September 30, 2014, the Partnership owned over 91% of its approximately 750 district 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, 2014, the Partnership operated a transportation fleet with the following assets:
Approximate Quantity & Equipment Type | % Owned | % Leased | |
1,040 | Trailers | 82% | 18% |
370 | Tractors | 23% | 77% |
410 | Railroad tank cars | 4% | 96% |
3,900 | Bobtail trucks | 44% | 56% |
465 | Rack trucks | 43% | 57% |
4,000 | Service and delivery trucks | 57% | 43% |
Other assets owned at September 30, 2014 included approximately 1.8 million stationary storage tanks with typical capacities of more than 120 gallons and approximately 4.6 million portable propane cylinders with typical capacities of 1 to 120 gallons.
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Trade Names, Trade and Service Marks
The Partnership markets propane principally under the “AmeriGas®”, “America’s Propane Company®”, “Heritage Propane®”, and “Relationships Matter®” 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 2014, 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 U.S., including former sites where we or our 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 federal and most state environmental laws.
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, and local citizens in accordance with applicable federal and state Emergency Planning and Community Right-to-Know Act requirements. The Partnership’s operations are also subject to the safety hazard communication requirements and reporting obligations set forth in federal workplace standards.
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All states in which the Partnership operates have adopted fire safety codes that regulate the storage and distribution 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 and distribution 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 and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials 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. 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, 2014, the General Partner had nearly 8,400 employees, including nearly 400 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
ANTARGAZ
Our UGI International - Antargaz LPG distribution business is conducted in France and the Benelux countries (consisting of Belgium, the Netherlands, and Luxembourg). Antargaz also operates a natural gas marketing business in France and Belgium and sold approximately 7.3 million dekatherms of natural gas during Fiscal 2014.
Products, Services and Marketing
During Fiscal 2014, Antargaz sold approximately 235 million gallons of LPG in France and approximately 44 million gallons of LPG in the Benelux countries. Antargaz is one of the largest LPG distributors in France and the Netherlands and the largest LPG distributor in Belgium and Luxembourg. Antargaz’ 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. Antargaz sells LPG in cylinders, and in small, medium and large tanks. Sales of LPG are also made to service stations to
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accommodate vehicles that run on LPG. Antargaz sells LPG in cylinders to approximately 15,000 retail outlets, such as supermarkets, individually owned stores and gas stations. Supermarket sales represented approximately 79% of butane cylinder sales volume and approximately 13% of propane cylinder sales volume in Fiscal 2014. At September 30, 2014, Antargaz had approximately 221,000 bulk customers, approximately 16,000 natural gas customers and nearly 10 million cylinders in circulation. Approximately 60% of Antargaz’ Fiscal 2014 sales (based on volumes) were cylinder and small bulk, 17% medium bulk, 20% large bulk and 3% to service stations for automobiles. Antargaz also engages in wholesale sales of LPG and provides logistic, storage and other services to third-party LPG distributors. In addition, Antargaz operates a natural gas marketing business in France and Belgium that services both commercial and residential customers. One wholesale customer represented over 10% of Antargaz’ total revenues in Fiscal 2014. No other customer represents, or is anticipated to represent, more than 10% of total revenues for Antargaz.
Sales to small bulk customers represent the largest segment of Antargaz’ 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 53% of all LPG cylinders sold in Fiscal 2014, with propane cylinders accounting for the remainder. 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
Antargaz currently has an agreement with Totalgaz (currently owned by Total France until the closing of the proposed Total Acquisition) for the supply of butane in France, with pricing based on internationally quoted market prices. Under this agreement, approximately 50% of Antargaz’ requirements for butane are guaranteed until September 2015. Requirements are fixed annually and Antargaz has developed other sources of supply. In Fiscal 2014, Antargaz purchased substantially all of its propane supply for its operations in France from SHV and TOTSA. In the Benelux countries, Antargaz purchased substantially all of its butane and propane requirements from SHV and GUNVOR during Fiscal 2014. From time to time, as needed, Antargaz also purchases propane on the international market and on the domestic spot market.
Antargaz has three primary storage facilities in operation that are located at deep sea harbor facilities, and 29 secondary storage facilities. It also manages an extensive logistics and transportation network. Access to seaborne facilities allows Antargaz 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 filled 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 Antargaz’ profitability is sensitive to changes in wholesale LPG costs, Antargaz generally seeks to pass on increases in the cost of LPG to customers. There is no assurance, however, that Antargaz 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 2014, Antargaz competed in all of its product markets in France on a national level, principally with three LPG distribution
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companies, Totalgaz (currently owned by Total France until the closing of the proposed Total 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. Antargaz also competes with supermarket chains that affiliate with LPG distributors to offer their own brands of cylinders. Antargaz has partnered with two supermarket chains in France in this market. If Antargaz is unsuccessful in expanding its services to other supermarket chains, its market share through supermarket sales may decline in France. In the Benelux countries, Antargaz 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. Antargaz seeks to increase demand for its butane and propane cylinders through marketing and product innovations. Some of Antargaz’ competitors are affiliates of its LPG suppliers. As a result, its competitors may obtain product at more competitive prices.
Because many of Antargaz’ 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 2014, approximately 66% of Antargaz’ retail sales volume occurred, and substantially all of Antargaz’ operating income was earned, during the six months from October through March. For historical information on weather statistics for Antargaz, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Government Regulation
Antargaz’ 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, Antargaz is also subject to price regulations that permit Antargaz to increase the price of LPG sold to small bulk, medium bulk, large bulk and cylinder customers (up to a defined maximum price) when Antargaz’ costs fluctuate.
Properties
Antargaz has three primary storage facilities in operation. One of these is a refrigerated facility. In addition, Antargaz is able to use 30,000 cubic meters of capacity of a storage facility, Donges, by virtue of Antargaz’ 50% ownership of Donges GIE. The table below sets forth details of Antargaz’ three primary storage facilities:
Ownership % | Antargaz Storage Capacity - Propane (m3) (1) | Antargaz Storage Capacity - Butane (m3) (1) | ||||||
GIE Norgal | 52.7 | 22,600 | 8,900 | |||||
Geogaz-Lavera | 16.7 | 17,400 | 32,500 | |||||
Cobogal | 15.0 | 1,300 | 450 | |||||
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(1) | Cubic meters (1 cubic meter is equivalent to approximately 264 gallons). |
Antargaz has 29 secondary storage facilities, 19 of which are wholly-owned. The others are partially owned through joint ventures.
Employees
At September 30, 2014, Antargaz had approximately 1,040 employees.
FLAGA & OTHER
During Fiscal 2014, our UGI International - Flaga & Other LPG distribution business was 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 2014, Flaga sold approximately 340 million gallons of LPG. Flaga is the largest distributor of LPG in Austria and
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Denmark and one of the largest distributors of LPG in Poland, the Czech Republic, Hungary, Slovakia, Norway, Sweden, and Finland. During Fiscal 2014, AvantiGas sold approximately 150 million gallons of LPG and our majority-owned partnership in China sold approximately 9 million gallons of LPG.
FLAGA
Products, Services and Marketing
During Fiscal 2014, Flaga sold approximately 340 million gallons of LPG (of which approximately 95 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 drying, power generation and irrigation. Flaga sells LPG in cylinders and in small, medium, and large bulk tanks. At September 30, 2014, Flaga had nearly 68,000 customers and 4.1 million cylinders in circulation. Approximately 24% of Flaga’s Fiscal 2014 sales (based on volumes) were cylinder and small bulk, 33% auto gas, 39% large bulk, and 4% medium bulk.
Flaga has a total of 18 sales offices throughout the countries it serves, although it does not have sales offices in Norway, Sweden or Finland, largely due to the commercial and industrial nature of Flaga’s business in those countries. Sales offices generally consist of an office location where customers can directly purchase LPG. Except for Poland, no single country represented more than 10% of Flaga’s total LPG gallons sold in Fiscal 2014. 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 11% of Flaga’s total revenues in Fiscal 2014.
LPG Supply and Storage
Flaga typically enters into an annual LPG supply agreement with TCO/Chevron. During Fiscal 2014, TCO/Chevron supplied approximately 50% of Flaga’s LPG requirements, with pricing based on internationally quoted market prices. 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. During Fiscal 2014, 8 suppliers accounted for approximately 80% of Flaga’s LPG supply.
Flaga operates 11 main storage facilities, including one in Denmark that is located at a deep sea harbor facility, two LPG import terminals in Poland, and 58 secondary storage facilities. Flaga manages a widespread logistics and transportation network including approximately 300 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
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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, 2014, Flaga had approximately 950 employees.
AVANTIGAS
Products, Services and Marketing
During Fiscal 2014, AvantiGas sold approximately 150 million gallons of LPG (of which approximately 91 million gallons were wholesale gallons). At September 30, 2014, AvantiGas had over 14,350 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 5% of Fiscal 2014 sales (based on volumes), medium bulk sales representing approximately 34% of Fiscal 2014 sales and large bulk sales representing approximately 61% of Fiscal 2014 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 one aerosol customer collectively represented over 55% of AvantiGas’ total revenues in Fiscal 2014. No other customer represents or is anticipated to represent more than 5% of total revenues for AvantiGas.
LPG Supply and Storage
AvantiGas has five-year agreements, which will terminate during the 2016 fiscal year, with Essar Energy plc’s Stanlow refinery and STASCO’s Mossmorran terminal, and a one-year agreement, which will terminate during Fiscal 2015, with Centrica plc, for the supply of an aggregate of approximately 92% of AvantiGas’ LPG requirements. Pricing for such agreements is based on internationally quoted market prices. AvantiGas purchased the remainder of its LPG requirements from other third party suppliers in Fiscal 2014.
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 2014, approximately 56% of AvantiGas’ retail sales volume occurred, and approximately 75% 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.
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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, 2014, AvantiGas had approximately 180 employees.
MIDSTREAM & MARKETING
ENERGY SERVICES
Retail Energy Marketing
Energy Services sells natural gas, liquid fuels and electricity to approximately 19,000 residential, commercial, and industrial customers at approximately 43,000 locations. Energy Services serves customers in all or portions of Pennsylvania, New Jersey, Delaware, New York, Ohio, Maryland, Massachusetts, Virginia, North Carolina and the District of Columbia. Energy Services distributes natural gas through the use of the distribution systems of 36 local gas utilities. It supplies power to customers through the use of the transmission systems 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 recent years, Energy Services expanded its energy peaking services at the Temple Facility and began selling 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 2014, 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 2014, Energy Services continued making investments in infrastructure projects to support the development of natural gas in the Marcellus Shale region of Pennsylvania. In the first quarter of Fiscal 2014, Energy Services completed a project to extend its gathering system in Wyoming County, Pennsylvania and placed its newly constructed pipeline from Wyoming County to Luzerne County, Pennsylvania (Auburn II) into service. The expansion of the gathering system provides for (i) expanded capacity through additional compression; and (ii) additional delivery options by connecting the region served by PNG and two
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interstate pipelines with Marcellus Shale producers. In Fiscal 2014, Energy Services also announced (i) plans to invest capital to further extend the gathering system, providing additional transportation capacity in the Marcellus Shale region (Auburn III); and (ii) a joint project to develop an approximately 100-mile pipeline from Luzerne County, Pennsylvania to the Trenton-Woodbury interconnection in New Jersey that will transport lower cost natural gas to residential and commercial customers (the PennEast Pipeline Project). Energy Services also commenced construction in the third quarter of Fiscal 2014 on a new pipeline project to transport locally produced natural gas to PNG (the Union Dale Lateral) and announced a project to increase the liquefaction capacity of its Temple Facility in Fiscal 2015.
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 in natural gas exploration, production and refining.
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 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. Energy Services also has market-based rate authority for power sales to wholesale customers to the extent that Energy Services purchases power in excess of its retail customer needs. Two subsidiaries of Energy Services operate natural gas storage facilities under FERC certificate approvals and offer services to wholesale customers at FERC-approved market-based rates. Energy Services is also subject to FERC reporting requirements, market manipulation rules and other FERC enforcement and regulatory powers.
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. Energy Services also is required to comply with the provisions of the Pipeline Safety Act and the regulations of the U.S. DOT with respect to the operation of natural gas gathering and transportation pipelines.
Employees
At September 30, 2014, Energy Services had approximately 205 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.
UGID also owns and operates a landfill gas-fueled generation plant near Hegins, Pennsylvania, with gross generating capacity of
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11 megawatts. The plant qualifies for renewable energy credits.
UGID also owns and operates 11.67 megawatts of solar-powered generation capacity in Pennsylvania, Maryland and New Jersey. Several other solar generation projects are in development.
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. UGID is also subject to FERC reporting requirements, market manipulation rules and other FERC enforcement and regulatory powers.
Employees
At September 30, 2014, 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 over 600,000 customers in eastern and central Pennsylvania and several hundred customers in portions of one Maryland county. Gas Utility is regulated by the PUC and, with respect to its several hundred customers in Maryland, the Maryland Public Service Commission.
Service Area; Revenue Analysis
Gas Utility is authorized to distribute natural gas to over 600,000 customers in portions of 46 eastern and central Pennsylvania counties through its distribution system of approximately 12,000 miles of gas mains. Contemporary materials, such as plastic or coated steel, comprise approximately 87% of Gas Utility’s 12,000 miles of gas mains, with bare steel pipe comprising approximately 10% 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 2027 and the bare steel portion by March 2043. 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 several hundred 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 2014 was approximately 208.8 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 Canadian sources. For the transportation and storage function, Gas Utility has long-term agreements with a number of pipeline companies, including Texas Eastern Transmission Corporation, Columbia Gas Transmission, LLC, Transcontinental Gas Pipeline Company, LLC, Dominion Transmission, Inc., ANR Pipeline Company, and Tennessee Gas Pipeline Company, L.L.C.
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Gas Supply Contracts
During Fiscal 2014, Gas Utility purchased approximately 84.2 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 90% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 10% of gas purchased by Gas Utility was supplied by approximately 35 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 16 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 2014, approximately 65% of Gas Utility’s sales volume was supplied, and over 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. 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 23% of Gas Utility’s annual throughput volume for commercial and industrial customers includes customers with locations that afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. In addition, approximately 31% 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 approximately 26 of such customers with transportation contracts extending beyond Fiscal 2015. 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 2015. Supply mix is diversified, market priced, and delivered pursuant to a number of long-term and short-term firm transportation and storage arrangements, including transportation contracts held by some of Gas Utility’s larger customers.
During Fiscal 2014, 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 2014, Gas Utility connected approximately 2,000 new commercial and industrial customers. In the residential market sector, Gas Utility connected nearly 16,000 residential heating customers during Fiscal 2014. Over 12,000 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 2014.
UGI Utilities continues to monitor and participate, where appropriate, in rulemaking and individual rate and tariff proceedings
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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 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 that 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.
FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers
Gas Utility is subject to Section 4A of the Natural Gas Act and Section 222 of the Federal Power Act, which prohibit 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.
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.
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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, the Comprehensive Environmental Response, Compensation, and Liability Act, 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, 2014, Gas Utility had approximately 1,400 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 1,900 miles of lines and 13 substations. At September 30, 2014, UGI Utilities’ electric utility operations had approximately 70 employees.
In accordance with Electric Utility’s default service settlement with the PUC effective June 1, 2014 through May 31, 2017, 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.
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HVAC
We conduct our heating, ventilation, air-conditioning, refrigeration and electrical contracting service business through HVAC, which serves portions of eastern Pennsylvania and the Mid-Atlantic region, including the Philadelphia suburbs and portions of New Jersey and northern Delaware. This business serves more than 90,000 customers in residential, commercial, industrial and new construction markets. During Fiscal 2014, HVAC generated approximately $83 million in revenues and had approximately 450 employees.
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 2014, 2013 and 2012 fiscal years appears in Note 21 to Consolidated Financial Statements included in Item 8 of this Report and is incorporated herein by reference.
EMPLOYEES
At September 30, 2014, UGI and its subsidiaries had nearly 12,800 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 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 Antargaz’ 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 Antargaz). 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
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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 in 2010, which contains comprehensive financial reform legislation. That act imposes regulation on the over-the-counter derivatives market and entities that participate in that market. The act requires the Commodities Futures Trading Commission (“CFTC”), the U.S. Securities and Exchange Commission (“SEC”) and other regulators to implement the act’s provisions. Some rules and regulations under the act have been finalized but additional rules and regulations 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. Increased costs may arise from any new margin, clearing and trade-execution requirements imposed upon individual transactions, as well as from new capital, reporting, recordkeeping, compliance and business conduct requirements imposed upon our counterparties to the extent those costs are passed through to us. Position limits may be imposed that could further limit our ability to hedge risks. To the extent new rules and regulations require more collateral or margin for individual transactions, our available liquidity may be adversely affected. Additionally, new rules and regulations may restrict our ability to monetize or restructure existing derivative contracts and require us to restructure portions of our energy marketing and trading business. 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 2014, AmeriGas Propane purchased over 90% 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. 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 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.
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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 ability to increase revenues is adversely affected by the decline of the retail LPG industry.
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., with no or modest growth in total demand foreseen. Given this forecast, 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 Propane Exchange 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 could have an adverse effect on our business, financial condition and results of operations.
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, could 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
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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, expanding our LNG facility and improving our gas storage facilities. 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. Failure to obtain or comply with these permits or applicable laws 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.
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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.
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. In addition to carbon dioxide, greenhouse gases include, among others, methane, a component of natural gas. While some states have adopted laws and regulations regulating the emission of GHGs for some industry sectors, 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 June 2014, the EPA proposed the Clean Power Plan, which will provide standards and guidelines for reducing existing power plants’ GHG emissions and related pollutants by 2030. The Clean Power Plan standards and guidelines are expected to be finalized by June 2015. 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 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; |
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• | longer payment cycles; |
• | local political and economic conditions, including the current financial downturn in the euro zone; |
• | potentially adverse tax consequences, including restrictions on repatriating earnings and the threat of “double taxation”; |
• | fluctuations in currency exchange rates, which can affect demand and increase our costs; |
• | internal control and risk management practices and policies; |
• | potential violations of federal regulatory requirements, including the Foreign Corrupt Practices Act of 1977, as amended; |
• | regulatory requirements and changes in regulatory requirements, including Norwegian, Swiss and EU competition laws that may adversely affect the terms of contracts with customers, including with respect to exclusive supply rights, and stricter regulations applicable to the storage and handling of LPG; and |
• | new and inconsistently enforced LPG industry regulatory requirements, which can have an adverse effect on our competitive position. |
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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
With the exception of those matters set forth in Note 16 to Consolidated Financial Statements included in Item 8 of this Report, no material legal proceedings are pending involving the Company, any of its subsidiaries, or any of their properties, and no such proceedings are known to be contemplated by governmental authorities other than claims arising in the ordinary course of business.
ITEM 4. MINE SAFETY DISCLOSURES
None.
EXECUTIVE OFFICERS
Information regarding our executive officers is included in Part III of this Report and is incorporated in Part I by reference.
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PART II:
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Market Information
Our Common Stock is traded on the New York Stock Exchange under the symbol “UGI.” On July 29, 2014, the Company announced that its Board of Directors had approved a three-for-two split of its Common Stock. The additional shares were distributed September 5, 2014 to shareholders of record on August 22, 2014. Sales prices and dividends paid for all periods 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.
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 | ||||
2013 Fiscal Year | High | Low | ||||||
4th Quarter | $ | 28.83 | $ | 25.35 | ||||
3rd Quarter | $ | 28.07 | $ | 24.29 | ||||
2nd Quarter | $ | 25.64 | $ | 21.93 | ||||
1st Quarter | $ | 22.39 | $ | 20.10 | ||||
Dividends
Quarterly dividends on our Common Stock were paid in Fiscal 2014 and Fiscal 2013 as follows:
2014 Fiscal Year | Amount | |||
4th Quarter | $ | 0.1967 | ||
3rd Quarter | $ | 0.1883 | ||
2nd Quarter | $ | 0.1883 | ||
1st Quarter | $ | 0.1883 | ||
2013 Fiscal Year | Amount | |||
4th Quarter | $ | 0.1883 | ||
3rd Quarter | $ | 0.18 | ||
2nd Quarter | $ | 0.18 | ||
1st Quarter | $ | 0.18 | ||
Record Holders
On November 21, 2014, UGI had 6,620 holders of record of Common Stock.
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Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth information with respect to the Company’s repurchases of its Common Stock during the quarter ended September 30, 2014. The shares of UGI Corporation Common Stock presented in this table are reflected on a post-split basis.
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, 2014 to July 31, 2014 | — | $0 | — | 14.3 million | ||||
August 1, 2014 to August 31, 2014 | 433,385 | $33.60 | 433,385 | 13.9 million | ||||
September 1, 2014 to September 30, 2014 | 108,750 | $35.29 | 108,750 | 13.8 million | ||||
Total | 542,135 | 542,135 | ||||||
(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 10 million shares of UGI Corporation Common Stock over a four-year period, or 15,000,000 on a post-split basis.
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ITEM 6. | SELECTED FINANCIAL DATA |
Year Ended September 30, | ||||||||||||||||||||
(Dollars in millions, except per share amounts) | 2014 | 2013 | 2012 (b) | 2011 | 2010 | |||||||||||||||
FOR THE PERIOD: | ||||||||||||||||||||
Income statement data: | ||||||||||||||||||||
Revenues | $ | 8,277.3 | $ | 7,194.7 | $ | 6,521.3 | $ | 6,090.9 | $ | 5,591.1 | ||||||||||
Net income | $ | 532.6 | $ | 427.6 | $ | 197.7 | $ | 320.0 | $ | 346.6 | ||||||||||
(Deduct net income) add net loss attributable to noncontrolling interests, principally in AmeriGas Partners | (195.4 | ) | (149.5 | ) | 12.5 | (74.6 | ) | (94.8 | ) | |||||||||||
Net income attributable to UGI Corporation | $ | 337.2 | $ | 278.1 | $ | 210.2 | $ | 245.4 | $ | 251.8 | ||||||||||
Earnings per common share attributable to UGI stockholders (a): | ||||||||||||||||||||
Basic | $ | 1.95 | $ | 1.63 | $ | 1.24 | $ | 1.46 | $ | 1.53 | ||||||||||
Diluted | $ | 1.92 | $ | 1.60 | $ | 1.24 | $ | 1.45 | $ | 1.52 | ||||||||||
Cash dividends declared per common share (a) | $ | 0.791 | $ | 0.737 | $ | 0.707 | $ | 0.68 | $ | 0.60 | ||||||||||
AT PERIOD END: | ||||||||||||||||||||
Balance sheet data: | ||||||||||||||||||||
Total assets | $ | 10,093.0 | $ | 10,008.8 | $ | 9,676.9 | $ | 6,660.9 | $ | 6,373.6 | ||||||||||
Capitalization: | ||||||||||||||||||||
Debt: | ||||||||||||||||||||
Short-term debt: | ||||||||||||||||||||
AmeriGas Propane | $ | 109.0 | $ | 116.9 | $ | 49.9 | $ | 95.5 | $ | 91.0 | ||||||||||
UGI International | 8.0 | 6.5 | 21.0 | 18.9 | 92.4 | |||||||||||||||
UGI Utilities | 86.3 | 17.5 | 9.2 | — | 17.0 | |||||||||||||||
Energy Services | 7.5 | 87.0 | 85.0 | 24.3 | — | |||||||||||||||
Long-term debt (including current maturities): | ||||||||||||||||||||
AmeriGas Propane | 2,291.7 | 2,300.1 | 2,328.0 | 933.5 | 791.4 | |||||||||||||||
UGI International | 565.0 | 654.4 | 573.9 | 571.3 | 561.1 | |||||||||||||||
UGI Utilities | 642.0 | 642.0 | 600.0 | 640.0 | 640.0 | |||||||||||||||
Other | 12.1 | 12.9 | 12.4 | 12.9 | 13.3 | |||||||||||||||
Total debt | 3,721.6 | 3,837.3 | 3,679.4 | 2,296.4 | 2,206.2 | |||||||||||||||
UGI Corporation stockholders’ equity | 2,659.1 | 2,492.5 | 2,229.8 | 1,973.5 | 1,824.0 | |||||||||||||||
Noncontrolling interests, principally in AmeriGas Partners | 1,004.1 | 1,055.4 | 1,085.6 | 213.0 | 237.4 | |||||||||||||||
Total capitalization | $ | 7,384.8 | $ | 7,385.2 | $ | 6,994.8 | $ | 4,482.9 | $ | 4,267.6 | ||||||||||
Ratio of capitalization: | ||||||||||||||||||||
Total debt | 50.4 | % | 52.0 | % | 52.6 | % | 51.2 | % | 51.7 | % | ||||||||||
UGI Corporation stockholders’ equity | 36.0 | % | 33.7 | % | 31.9 | % | 44.0 | % | 42.7 | % | ||||||||||
Noncontrolling interests, principally in AmeriGas Partners | 13.6 | % | 14.3 | % | 15.5 | % | 4.8 | % | 5.6 | % | ||||||||||
100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | |||||||||||
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Year Ended September 30, | ||||||||||||||||||||
(Dollars in millions, except per share amounts) | 2014 | 2013 | 2012 (b) | 2011 | 2010 | |||||||||||||||
NON-GAAP RECONCILATION: | ||||||||||||||||||||
Adjusted net income attributable to UGI Corporation: | ||||||||||||||||||||
Net income attributable to UGI Corporation | $ | 337.2 | $ | 278.1 | $ | 210.2 | $ | 245.4 | $ | 251.8 | ||||||||||
Net losses (gains) on Midstream & Marketing’s commodity derivative instruments not associated with current period transactions | 4.9 | (4.3 | ) | (8.9 | ) | (17.4 | ) | 8.2 | ||||||||||||
Net losses on AmeriGas Propane commodity derivative instruments entered into beginning April 1, 2014, not associated with current period transactions | 1.7 | — | — | — | — | |||||||||||||||
Retroactive impact of change in French tax law | 5.7 | — | — | — | — | |||||||||||||||
Adjusted net income attributable to UGI Corporation (c) | $ | 349.5 | $ | 273.8 | $ | 201.3 | $ | 228.0 | $ | 260.0 | ||||||||||
Adjusted earnings per common share attributable to UGI stockholders (a): | ||||||||||||||||||||
Basic (c) | $ | 2.02 | $ | 1.60 | $ | 1.19 | $ | 1.36 | $ | 1.58 | ||||||||||
Diluted (c) | $ | 1.99 | $ | 1.58 | $ | 1.18 | $ | 1.35 | $ | 1.57 | ||||||||||
(a) All per share amounts presented reflect the retroactive effects of the three-for-two common stock split distributed September 5, 2014 to shareholders of record on August 22, 2014.
(b) Reflects Heritage Propane beginning January 1, 2012. See Note 4 to Consolidated Financial Statements for further information.
(c) “Adjusted net income attributable to UGI Corporation” and “adjusted earnings per share - basic and diluted” are not measures of performance or financial condition under accounting principles generally accepted in the United States of America (“GAAP”). 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 (1) gains and losses on Midstream & Marketing’s and, beginning April 1, 2014, AmeriGas Propane’s commodity derivative instruments that are not associated with current-period transactions and (2) those items that management regards as highly unusual in nature and not expected to recur. For further discussion of these financial measures, see the Executive Overview in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) discusses our results of operations and our financial condition. MD&A should be read in conjunction with our Items 1 & 2, “Business and Properties,” our Item 1A, “Risk Factors,” and our Consolidated Financial Statements in Item 8 below including “Segment Information” included in Note 21 to Consolidated Financial Statements. On July 29, 2014, the Company announced that its Board of Directors had approved a three-for-two split of UGI Common Stock. The additional shares were distributed September 5, 2014, to shareholders of record on August 22, 2014. All references to shares and per share amounts have been retroactively adjusted to reflect the three-for-two stock split.
Executive Overview
We recorded net income attributable to UGI Corporation for Fiscal 2014 of $337.2 million, equal to $1.92 per diluted share, compared to net income attributable to UGI Corporation for Fiscal 2013 of $278.1 million, equal to $1.60 per diluted share. Net income attributable to UGI Corporation in Fiscal 2014 is net of after-tax losses of $4.9 million on commodity derivative instruments not associated with current-period transactions at Midstream & Marketing and net after-tax losses of $1.7 million on AmeriGas Propane’s commodity derivative instruments entered into beginning April 1, 2014, not associated with current period transactions. Net income attributable to UGI Corporation in Fiscal 2013 includes net after-tax gains of $4.3 million related to Midstream & Marketing commodity derivative instruments not associated with current-period transactions. These net after-tax gains and losses are included in “Corporate & Other” in the business unit summary tables below. Results in Fiscal 2014 also reflect the retroactive effect to Fiscal 2013 of a change in tax laws in France, which increased tax expense and reduced Fiscal 2014 net income by $5.7 million. Adjusted net income attributable to UGI excluding the effects of the previously mentioned commodity derivative instrument gains and losses, and the retroactive impact of the change in tax laws in France, was $349.5 million (equal to $1.99 per diluted share) in Fiscal 2014 compared to $273.8 million (equal to $1.58 per diluted share) in Fiscal 2013.
The $75.7 million increase in adjusted net income attributable to UGI in Fiscal 2014 reflects the effects of significantly colder and more volatile winter weather at Midstream & Marketing and significantly colder weather at our Gas Utility and in AmeriGas Propane’s service territory east of the Rocky Mountains. The significant increase in operating results from these domestic business units was partially offset by the effects of record warm temperatures at our European LPG business units. During Fiscal 2014, net income attributable to UGI increased $65.3 million at Midstream & Marketing, $24.5 million at Gas Utility, and $15.5 million at AmeriGas Propane. 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 in the Mid-Atlantic and Northeast U.S. that resulted in heightened natural gas price volatility due to locational basis differentials and increased the demand for, and the value of, winter peaking services. Midstream & Marketing’s Electric Generation business results also benefited from higher unit margins and higher production at its Hunlock and Conemaugh electricity generating facilities. The improved results in Fiscal 2014 at Gas Utility principally reflect the effects on core market volumes of weather that was nearly 11% colder than the prior year. The improved results at AmeriGas Propane reflect the retail volume effects of significantly colder weather in the U.S. east of the Rocky Mountains and the full-year realization of the Heritage Propane integration. The benefits of this colder weather on AmeriGas Propane retail volumes sold were offset, in part, by the unfavorable effects on retail volumes sold and distribution expenses from wholesale supply challenges in certain regions of the U.S., caused by industry-wide storage and transportation issues exacerbated by prolonged periods of unusually cold winter weather, and by significantly warmer winter weather in the western U.S. UGI International net income attributable to UGI declined $34.4 million in Fiscal 2014 principally due to the effects of much warmer than normal winter and spring temperatures at our European LPG businesses on retail volumes sold and the effects of changes in tax laws in France including the previously mentioned $5.7 million retroactive effect.
Our UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. Although the foreign currency to U.S. dollar exchange rates during Fiscal 2014 were slightly higher than in Fiscal 2013, such differences did not have a material impact on UGI International net income attributable to UGI.
We believe each of our business units has sufficient liquidity in the forms of revolving credit facilities, and with respect to Energy Services also an accounts receivable securitization facility, to fund business operations during Fiscal 2015 (see Financial Condition and Liquidity below).
Looking ahead, our results in Fiscal 2015 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. The volatility in domestic energy prices and prices for capacity and peaking services experienced in Fiscal 2014 were extreme and we do not expect such volatility to occur to a similar extent in Fiscal 2015. However, we expect that our Midstream & Marketing businesses will continue to
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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 proposed acquisition of Total’s retail LPG distribution business in France will further strengthen our position in Europe. At Gas Utility, we expect to continue to experience strong growth from conversions from oil as a result of sustained low natural gas prices. To the extent normal weather patterns return in our European LPG operations, we hope 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
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 (1) net after-tax gains and losses on commodity derivative instruments not associated with current-period transactions at Midstream & Marketing; (2) net after-tax gains and losses on commodity derivative instruments not associated with current-period transactions at AmeriGas Propane for commodity derivative instruments entered into beginning April 1, 2014; and (3) those items that management regards as highly unusual in nature and not expected to recur.
Midstream & Marketing accounts for realized and unrealized gains and losses on commodity derivative instruments as a component of cost of sales or revenues on the Consolidated Statements of Income. Effective April 1, 2014, AmeriGas Propane determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative transactions. As a result, all unrealized gains and losses on AmeriGas Propane’s commodity derivative instruments entered into beginning April 1, 2014, are included as a component of cost of sales on the Consolidated Statements of Income. Volatility in net income attributable to UGI can occur as a result of gains and losses on commodity derivative instruments not associated with current period transactions but included in earnings in accordance with generally accepted accounting principles (“GAAP”). These gains and losses result principally from recording 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 associated with transactions forecasted to occur in a future period.
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 (1) gains and losses on Midstream & Marketing’s and, beginning April 1, 2014, AmeriGas Propane’s commodity derivative instruments that are not associated with current-period transactions and (2) those items that management regards as highly unusual in nature and not expected to recur.
(Millions of dollars, except per share amounts) | 2014 | 2013 | 2012 | |||||||||
Adjusted net income attributable to UGI Corporation: | ||||||||||||
Net income attributable to UGI Corporation | $ | 337.2 | $ | 278.1 | $ | 210.2 | ||||||
Net losses (gains) on Midstream & Marketing’s commodity derivative instruments not associated with current period transactions | 4.9 | (4.3 | ) | (8.9 | ) | |||||||
Net losses on AmeriGas Propane commodity derivative instruments entered into beginning April 1, 2014, not associated with current period transactions | 1.7 | — | — | |||||||||
Retroactive impact of change in French tax law | 5.7 | — | — | |||||||||
Adjusted net income attributable to UGI Corporation | $ | 349.5 | $ | 273.8 | $ | 201.3 | ||||||
Adjusted diluted earnings per share: | ||||||||||||
UGI Corporation earnings per share - diluted | $ | 1.92 | $ | 1.60 | $ | 1.24 | ||||||
Net losses (gains) on Midstream & Marketing’s commodity derivative instruments not associated with current period transactions | 0.03 | (0.02 | ) | (0.06 | ) | |||||||
Net losses on AmeriGas Propane commodity derivative instruments entered into beginning April 1, 2014, not associated with current period transactions | 0.01 | — | — | |||||||||
Retroactive impact of change in French tax law | 0.03 | — | — | |||||||||
Adjusted diluted earnings per share | $ | 1.99 | $ | 1.58 | $ | 1.18 | ||||||
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Results of Operations
The following analyses compare the Company’s results of operations for (1) Fiscal 2014 with Fiscal 2013 and (2) Fiscal 2013 with the fiscal year ended September 30, 2012 (“Fiscal 2012”).
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. |
(b) | Includes net after-tax gains (losses) on Midstream & Marketing’s unsettled and certain settled 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.
Highlights — Fiscal 2014 versus Fiscal 2013
• | Fiscal 2014 results reflect significantly colder and more volatile winter weather at Midstream & Marketing and significantly colder weather at Gas Utility and in AmeriGas Propane’s service territory east of the Rocky Mountains. |
• | Midstream & Marketing’s integrated assets portfolio in the Marcellus Shale in Pennsylvania provided it with the opportunity to take advantage of periods of extreme cold winter weather that resulted in heightened natural gas price volatility due to locational basis differentials and increased the demand for winter peaking services. |
• | Our UGI International operations in Europe experienced weather that was much warmer than normal which reduced retail volumes sold. |
• | Fiscal 2014 results reflect the retroactive effects of a change in tax laws in France which increased UGI International tax expense and reduced Fiscal 2014 net income by $(5.7) million (equal to $(0.03) per diluted share). |
• | Net income in Fiscal 2014 includes after-tax losses of $(6.6) million (equal to $(0.04) per diluted share) on commodity derivative instruments not associated with current-period transactions while net income in Fiscal 2013 includes after-tax gains of $4.3 million (equal to $0.02 per diluted share) on commodity derivative instruments not associated with current-period transactions. |
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AmeriGas Propane | 2014 | 2013 | Increase | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 3,712.9 | $ | 3,168.8 | $ | 544.1 | 17.2 | % | |||||||
Total margin (a) | $ | 1,605.8 | $ | 1,511.6 | $ | 94.2 | 6.2 | % | |||||||
Operating and administrative expenses | $ | 964.1 | $ | 945.1 | $ | 19.0 | 2.0 | % | |||||||
Partnership 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 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 EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements). Partnership EBITDA for Fiscal 2013 includes transition expenses of $26.5 million associated with the integration of Heritage Propane acquired in January 2012. |
(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. |
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 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
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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) | 583.2 | 592.4 | (9.2 | ) | (1.6 | )% | |||||||||
Antargaz 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 Antargaz 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 lower reflecting the effects of the significantly warmer Fiscal 2014 weather partially 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, notwithstanding the effects of the significantly warmer weather on retail volumes sold, 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 Antargaz ($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 Antargaz 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 Antargaz ($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 Antargaz and AvantiGas operating, administrative and depreciation expenses. Fiscal 2014 UGI International operating and
34
administrative costs also include $6.5 million of incremental expenses associated with the proposed acquisition of Total’s retail LPG distribution business in France.
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 – billions of cubic feet (“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’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 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. 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 $496.8 million in Fiscal 2014 compared with $407.2 million in Fiscal 2013 principally reflecting the effects of the greater retail core-market volumes sold ($50.1 million) and the effects of the higher off-system sales ($36.4 million).
Fiscal 2014 Gas Utility total margin increased $48.7 million principally reflecting higher core market total margin ($33.8 million) and greater large firm delivery service total margin ($10.8 million). The higher core market and large firm delivery service total margin reflects the effects of the previously mentioned colder weather and customer growth.
Gas Utility operating income and income before income taxes during Fiscal 2014 increased $39.7 million and $40.5 million, respectively, over Fiscal 2013. The increase in Gas Utility operating income principally reflects the $48.7 million increase in total margin partially offset by higher operating and administrative expenses. Operating and administrative expenses in Fiscal 2014 were modestly higher than the prior year principally reflecting greater Fiscal 2014 distribution system maintenance expenses ($5.3 million), higher uncollectible accounts expense ($3.0 million) and greater incentive compensation expense partially offset by lower pension expense. The increase in Gas Utility income before income taxes reflects the greater operating income ($39.7 million) and slightly lower interest expense.
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Midstream & Marketing | 2014 | 2013 | Increase | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues (a) | $ | 1,368.9 | $ | 1,037.6 | $ | 331.3 | 31.9 | % | |||||||
Total margin (b) | $ | 292.2 | $ | 164.0 | $ | 128.2 | 78.2 | % | |||||||
Operating and administrative expenses | $ | 70.6 | $ | 57.0 | $ | 13.6 | 23.9 | % | |||||||
Operating income | $ | 198.6 | $ | 90.0 | $ | 108.6 | 120.7 | % | |||||||
Income before income taxes | $ | 195.7 | $ | 86.8 | $ | 108.9 | 125.5 | % | |||||||
(a) | Amounts are net of intercompany revenues between Midstream & Marketing’s Energy Services and Electric Generation segments. |
(b) | Total margin represents total revenues less total cost of sales. Amounts exclude pre-tax (losses) gains from changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments and pre-tax (losses) gains on certain settled 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 largely 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 consolidated effective income tax rate for Fiscal 2014 was higher than Fiscal 2013. 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 Antargaz’ 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 Antargaz applies retroactively to Fiscal 2013. During the quarter ended December 31, 2013, the Company recorded additional income taxes of $5.7 million to reflect the retroactive effects of the new French tax legislation associated with the deductibility of certain interest expense.
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Fiscal 2013 Compared with Fiscal 2012
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:
2013 | 2012 | Variance - Favorable (Unfavorable) | |||||||||||||||||||
(Dollars in millions) | Amount | % of Total | Amount | % of Total | Amount | % Change | |||||||||||||||
AmeriGas Propane | $ | 47.5 | 17.1 | % | $ | 15.4 | 7.3 | % | $ | 32.1 | 208.4 | % | |||||||||
UGI International (a) | 82.7 | 29.7 | % | 65.2 | 31.0 | % | 17.5 | 26.8 | % | ||||||||||||
Gas Utility | 94.3 | 33.9 | % | 81.6 | 38.8 | % | 12.7 | 15.6 | % | ||||||||||||
Midstream & Marketing | 52.5 | 18.9 | % | 37.7 | 17.9 | % | 14.8 | 39.3 | % | ||||||||||||
Corporate & Other (a) | 1.1 | 0.4 | % | 10.3 | 5.0 | % | (9.2 | ) | N.M. | ||||||||||||
Net income attributable to UGI Corporation | $ | 278.1 | 100.0 | % | $ | 210.2 | 100.0 | % | $ | 67.9 | 32.3 | % | |||||||||
(a) | Includes net after-tax gains on Midstream & Marketing’s unsettled and certain settled commodity derivative instruments not associated with current period transactions of $4.3 million and $8.9 million in Fiscal 2013 and Fiscal 2012, respectively. |
N.M. — Variance is not meaningful.
Highlights — Fiscal 2013 versus Fiscal 2012
• | Net income increased significantly in Fiscal 2013 due primarily to a return to more normal winter weather patterns and cooler spring temperatures. |
• | Fiscal 2013 results include the full-year effects of AmeriGas Partners’ January 2012 acquisition of Heritage Propane and the benefits from the integrations of Heritage Propane and Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden acquired in October 2011 (the “Shell Transaction”). |
• | Fiscal 2013 results include Heritage Propane transition expenses of $26.5 million (after-tax impact to UGI of $(4.4) million equal to $(0.03) per diluted share). Fiscal 2012 results include combined Heritage Propane and Shell pre-tax acquisition and transition expenses totaling approximately $53 million (after-tax impact to UGI of $(13.3) million equal to $(0.08) per diluted share). |
• | Fiscal 2013 LPG unit margins at AmeriGas Propane and UGI International were higher principally reflecting the benefit of lower average LPG commodity costs. |
• | Midstream & Marketing’s Energy Services business benefited from the colder weather including higher income from winter peaking and capacity management activities. Additionally, Midstream & Marketing’s Electric Generation business results improved on higher generation volumes and higher average unit margins. |
• | Gas Utility continued to experience record numbers of customer conversions to natural gas from alternative fuels. |
• | AmeriGas Propane’s Fiscal 2012 results include a $2.2 million after-tax loss ( impact of $0.01 per diluted share) on extinguishments of debt. |
• | Net income in Fiscal 2013 includes after-tax gain of $4.3 million (equal to $0.02 per diluted share) on commodity derivative instruments not associated with current-period transactions compared with after-tax gains of $8.9 million (impact of $0.06 per diluted share) on commodity derivative instruments not associated with current-period transactions in Fiscal 2012. |
37
AmeriGas Propane | 2013 | 2012 | Increase | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 3,168.8 | $ | 2,921.5 | $ | 247.3 | 8.5 | % | |||||||
Total margin (a) | $ | 1,511.6 | $ | 1,199.1 | $ | 312.5 | 26.1 | % | |||||||
Operating and administrative expenses | $ | 945.1 | $ | 888.4 | $ | 56.7 | 6.4 | % | |||||||
Partnership EBITDA (b) | $ | 596.5 | $ | 322.1 | $ | 274.4 | 85.2 | % | |||||||
Operating income | $ | 394.4 | $ | 168.7 | $ | 225.7 | 133.8 | % | |||||||
Retail gallons sold (millions) | 1,245.2 | 1,017.5 | 227.7 | 22.4 | % | ||||||||||
Degree days – % (warmer) than normal (c) | (4.9 | )% | (18.6 | )% | — | — | |||||||||
(a) | Total margin represents total revenues less total cost of sales. |
(b) | Partnership 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 EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements). Partnership EBITDA for Fiscal 2012 includes pre-tax losses of $13.3 million associated with extinguishments of debt. Partnership EBITDA and operating income for Fiscal 2013 and Fiscal 2012 also include acquisition and transition expenses of $26.5 million and $46.2 million, respectively, associated with Heritage Propane. |
(c) | 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. |
Results for Fiscal 2013 reflect the full-year operations of Heritage Propane acquired in January 2012. Based upon heating degree-day data, temperatures in the Partnership's service territories during Fiscal 2013 averaged approximately 4.9% warmer than normal but 16.2% colder than in Fiscal 2012. Retail gallons sold increased 227.7 million gallons (22.4%) principally reflecting the full-year impact of the Heritage Propane operations and the colder Fiscal 2013 weather.
Retail propane revenues increased $241.6 million during Fiscal 2013 reflecting the higher retail volumes sold ($567.6 million) partially offset by a decline in average retail selling prices ($326.0 million) resulting from lower propane product costs. Wholesale propane revenues declined $33.7 million principally reflecting lower average wholesale propane selling prices ($28.6 million) and lower wholesale volumes sold ($5.1 million). Average daily wholesale propane commodity prices during Fiscal 2013 at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 19% lower than such prices during Fiscal 2012. Total revenues from fee income and other ancillary sales and services in Fiscal 2013 were $39.4 million higher than in Fiscal 2012 principally reflecting the full-year effects of Heritage Propane. Total propane cost of sales decreased $76.5 million principally reflecting the effects of the previously mentioned lower propane commodity prices on retail propane cost of sales ($376.3 million) and lower wholesale propane cost of sales ($36.8 million) substantially offset by the effects of the greater retail volumes sold ($336.6 million). Cost of sales associated with ancillary sales and services increased $11.3 million principally reflecting the full-year effects of Heritage Propane.
Total margin increased $312.5 million in Fiscal 2013 principally reflecting higher total propane margin ($284.4 million) and greater total margin from fee income and ancillary sales and services ($28.1 million). These increases principally reflect the incremental full-year effects of Heritage Propane, the colder Fiscal 2013 weather and, with respect to total propane margin, slightly higher average unit margins reflecting in large part the lower propane product costs.
Partnership EBITDA in Fiscal 2013 increased $274.4 million principally reflecting the higher total margin ($312.5 million) and the absence of the $13.3 million loss on extinguishments of debt recorded in Fiscal 2012 partially offset by higher Partnership operating and administrative expenses ($56.7 million) primarily attributable to the full-year effects of Heritage Propane operations. Operating and administrative expenses in Fiscal 2013 include $26.5 million of transition expenses associated with the integration of Heritage Propane while operating and administrative expenses in Fiscal 2012 include Heritage Propane acquisition and transition-related expenses of $46.2 million. AmeriGas Propane operating income increased $225.7 million in Fiscal 2013 principally reflecting the higher total margin ($312.5 million) partially offset by the previously mentioned greater operating and administrative expenses ($56.7 million) and increased depreciation and amortization expense ($37.8 million) reflecting in large part the full-year effects of Heritage Propane.
38
UGI International | 2013 | 2012 | Increase | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 2,179.2 | $ | 1,946.1 | $ | 233.1 | 12.0 | % | |||||||
Total margin (a) | $ | 680.8 | $ | 620.3 | $ | 60.5 | 9.8 | % | |||||||
Operating and administrative expenses | $ | 454.4 | $ | 435.9 | $ | 18.5 | 4.2 | % | |||||||
Operating income | $ | 147.0 | $ | 111.9 | $ | 35.1 | 31.4 | % | |||||||
Income before income taxes | $ | 116.2 | $ | 80.7 | $ | 35.5 | 44.0 | % | |||||||
Retail gallons sold (millions) (b) | 592.4 | 576.5 | 15.9 | 2.8 | % | ||||||||||
Antargaz degree days – % colder (warmer) than normal (c) | 3.7 | % | (7.1 | )% | — | — | |||||||||
Flaga degree days – % colder (warmer) than normal (c) | 0.9 | % | (6.4 | )% | — | — | |||||||||
(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 Antargaz and Flaga service territories. |
Based upon heating degree day data, temperatures in our European LPG territories in Fiscal 2013 were colder than normal and colder than the prior year. Although Fiscal 2013 wholesale commodity prices for propane and butane based upon index prices in northwest Europe averaged only slightly lower than in Fiscal 2012, such LPG prices generally declined during the Fiscal 2013 peak heating season while LPG prices generally increased during the Fiscal 2012 peak heating season. Retail LPG gallons sold in Fiscal 2013 were higher than Fiscal 2012 principally reflecting the effects of significantly colder weather across all of our European operations partially offset by the effects of a decline in economic activity mainly on commercial and industrial customers in certain of our European markets.
Our UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. The functional currency of a significant portion of our UGI International results is the euro. During Fiscal 2013 and Fiscal 2012, the average unweighted translation rate was approximately $1.31 and $1.30 per euro, respectively. The difference in rates did not have a material impact on net income attributable to UGI.
UGI International revenues increased $233.1 million principally reflecting the effects on LPG revenues of greater low-margin wholesale sales, the increase in LPG retail volumes sold and, to a lesser extent, greater average retail prices. The increase in revenues also reflects higher revenues from natural gas marketing activities in France. Cost of sales increased to $1,498.4 million in Fiscal 2013 from $1,325.8 million in Fiscal 2012 principally reflecting the effects of the greater wholesale and retail LPG volumes sold. The higher UGI International cost of sales also reflects increased cost of sales associated with natural gas marketing activities in France.
Total UGI International margin increased $60.5 million during Fiscal 2013 principally reflecting higher retail LPG unit margins and volumes at Antargaz and, to a much lesser extent, higher total LPG margin at AvantiGas and Flaga.
UGI International operating income and income before income taxes increased $35.1 million and $35.5 million, respectively, principally reflecting the higher total margin ($60.5 million) partially offset by modestly higher operating and administrative expenses. Operating and administrative expenses in Fiscal 2013 principally reflect higher delivery, selling, and incentive compensation and benefits costs principally at Antargaz. Fiscal 2013 UGI International operating and administrative costs include approximately $4.0 million of acquisition and transition costs associated with Flaga’s September 2013 acquisition of BP’s LPG distribution business in Poland, while Fiscal 2012 UGI International operating and administrative expenses include acquisition and transition costs of approximately $7.0 million associated with the LPG businesses acquired from Shell in October 2011. UGI International net income in Fiscal 2013 as a percentage of UGI International’s earnings before income taxes was lower than the prior year as the Fiscal 2012 UGI International effective income tax rate reflects, in part, the effects of a greater proportion of UGI International tax benefits relative to pre-tax income and the realization of $4.7 million of previously unrecognized foreign tax credits.
39
Gas Utility | 2013 | 2012 | Increase | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 839.0 | $ | 785.4 | $ | 53.6 | 6.8 | % | |||||||
Total margin (a) | $ | 431.8 | $ | 382.9 | $ | 48.9 | 12.8 | % | |||||||
Operating and administrative expenses | $ | 176.2 | $ | 156.0 | $ | 20.2 | 12.9 | % | |||||||
Operating income | $ | 196.5 | $ | 174.1 | $ | 22.4 | 12.9 | % | |||||||
Income before income taxes | $ | 159.1 | $ | 134.0 | $ | 25.1 | 18.7 | % | |||||||
System throughput – bcf - | |||||||||||||||
Core market | 70.6 | 59.2 | 11.4 | 19.3 | % | ||||||||||
Total | 192.1 | 177.6 | 14.5 | 8.2 | % | ||||||||||
Degree days – % (warmer) than normal (b) | (0.5 | )% | (16.3 | )% | — | — | |||||||||
(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 the Gas Utility service territory in Fiscal 2013 based upon heating degree days were 0.5% warmer than normal but 18.2% colder than Fiscal 2012. Total distribution system throughput increased principally reflecting significantly higher throughput to core market customers and, to a lesser extent, greater net volumes associated with lower margin firm and interruptible delivery service customers. Gas Utility system throughput to core market customers was above last year principally reflecting the effects of the significantly colder weather and, to a much lesser extent, customer growth, principally conversions from oil prompted by sustained lower natural gas prices relative to heating oil prices.
Gas Utility revenues increased $53.6 million during Fiscal 2013 principally reflecting higher revenues from core market customers ($52.8 million) and higher large firm delivery service revenues ($9.2 million) partially offset by lower off-system sales revenues ($8.6 million). The increase in core market revenues principally reflects the effects of higher retail core-market volumes on PGC revenues ($60.4 million) and greater core market delivery service revenues partially offset by the effects of lower average PGC rates on retail core-market revenues ($50.6 million).Gas Utility's cost of sales was $407.2 million in Fiscal 2013 compared with $402.5 million in Fiscal 2012 principally reflecting the effects on cost of sales of the greater retail core-market volumes ($60.4 million) substantially offset by the effects of lower average PGC rates ($50.6 million) and the lower off-system sales.
Gas Utility total margin increased $48.9 million in Fiscal 2013 principally reflecting higher core market margin ($38.1 million) and higher large firm delivery service total margin ($9.6 million). The higher core market margin reflects the effects of the greater core market volumes.
The increase in Gas Utility operating income during Fiscal 2013 principally reflects the increase in total margin ($48.9 million) partially offset by higher operating and administrative expenses ($20.2 million) including, among other things, higher pension and benefits expenses ($10.7 million), higher uncollectible accounts expenses ($2.8 million) on higher core market volumes, and greater injuries and damages and distribution system expenses ($4.5 million). The greater income before income taxes in Fiscal 2013 reflects the higher operating income ($22.4 million) and slightly lower interest expense on lower long-term debt outstanding.
40
Midstream & Marketing | 2013 | 2012 | Increase | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues (a) | $ | 1,037.6 | $ | 853.9 | $ | 183.7 | 21.5 | % | |||||||
Total margin (b) | $ | 164.0 | $ | 130.4 | $ | 33.6 | 25.8 | % | |||||||
Operating and administrative expenses | $ | 57.0 | $ | 53.9 | $ | 3.1 | 5.8 | % | |||||||
Operating income | $ | 90.0 | $ | 64.3 | $ | 25.7 | 40.0 | % | |||||||
Income before income taxes | $ | 86.8 | $ | 59.5 | $ | 27.3 | 45.9 | % | |||||||
(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 pre-tax gains from changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments and pre-tax gains on certain settled commodity derivative instruments not associated with current period transactions of $7.4 million and $15.1 million in Fiscal 2013 and Fiscal 2012, respectively. |
Midstream & Marketing total revenues increased $183.7 million in Fiscal 2013 principally reflecting, among other things, higher natural gas revenues ($145.1 million) from higher wholesale volumes sold and higher average selling prices for natural gas, and higher Electric Generation total revenues ($30.7 million) principally the result of higher electricity volumes and prices.
Midstream & Marketing Fiscal 2013 total margin was $33.6 million higher than Fiscal 2012 reflecting higher Electric Generation total margin ($15.6 million), higher natural gas marketing total margin ($14.2 million), and greater peaking and capacity management total margin ($13.4 million) due to the colder weather and greater natural gas price volatility. These increases were partially offset by lower retail power total margin principally reflecting lower average unit margins. Total margin from natural gas marketing activities in Fiscal 2013 principally reflects the benefits of higher average unit margins. Natural gas marketing average unit margins in Fiscal 2013 benefited from higher-margin incremental sales resulting from the colder weather while average unit margins in Fiscal 2012 were negatively impacted by significantly warmer than normal weather. The greater total margin from Electric Generation principally reflects the impact of higher electricity production from our Hunlock natural gas-fired electricity generating station and greater volumes sold from the Conemaugh generating station. In Fiscal 2012 the Hunlock generating station was running at less than full capacity due to an accident at one unit and flood damage at another unit sustained late in Fiscal 2011. Unit margins from Electric Generation were higher in Fiscal 2013 reflecting higher electricity spot market prices, the effects of lower per unit fuel costs at the Hunlock generating station, and higher capacity revenues from the Hunlock and Conemaugh generating stations.
Midstream & Marketing operating income in Fiscal 2013 was $25.7 million higher than Fiscal 2012 reflecting the previously mentioned increase in total margin ($33.6 million) partially offset by higher operating, administrative and depreciation expenses.
The higher operating and administrative expenses ($3.1 million) include greater Energy Services operating expenses ($2.6 million) due in large part to expenses associated with peaking LNG liquefaction and storage facilities and incremental expenses associated with our non-operating working interest in natural gas acreage in the Marcellus Shale region in northern Pennsylvania acquired in January 2013. The increase in depreciation expenses ($4.9 million) principally reflects greater depreciation associated with the full-year operation of LNG facilities and the Hunlock generating station. The increase in Midstream & Marketing income before income taxes reflects the greater operating income and lower interest expense.
Interest Expense. Our consolidated interest expense was $19.9 million higher in Fiscal 2013 primarily reflecting higher AmeriGas Propane interest expense ($25.0 million), principally full-year interest on debt issued to fund the cash portion of the January 12, 2012, acquisition of Heritage Propane, partially offset by slightly lower UGI Utilities interest expense ($2.9 million) on slightly lower long-term debt outstanding and lower Midstream & Marketing interest expense.
Income Taxes. Income taxes as a percentage of pretax earnings was lower in Fiscal 2013 reflecting, in part, the effects of a higher percentage of income associated with noncontrolling interests not subject to tax, principally AmeriGas Partners, and the realization of previously unrecognized state deferred tax benefits while income taxes in Fiscal 2012 were reduced by $4.7 million as a result of the realization of previously unrecognized foreign tax credits.
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Financial Condition and Liquidity
We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities and, in the case of Midstream & Marketing, also from a receivables purchase 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 receivables purchase 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, excluding cash in commodity futures brokerage accounts that is restricted from withdrawal, totaled $419.5 million at September 30, 2014, compared with $389.3 million at September 30, 2013. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30, 2014 and 2013, UGI had $245.9 million and $192.5 million, respectively, of cash and cash equivalents. 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, 2014, 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 (see Note 15 to the Consolidated Financial Statements). The aggregate amounts of such incentive distributions in Fiscal 2014, Fiscal 2013 and Fiscal 2012 were $23.9 million, $19.3 million and $13.0 million, respectively.
During Fiscal 2014, Fiscal 2013 and Fiscal 2012, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:
Year Ended September 30, | 2014 | 2013 | 2012 | |||||||||
(Millions of dollars) | ||||||||||||
AmeriGas Propane | $ | 92.0 | $ | 96.2 | $ | 78.6 | ||||||
UGI Utilities | 77.4 | 59.0 | 70.6 | |||||||||
UGI International | 11.2 | 22.3 | 14.9 | |||||||||
Midstream & Marketing | — | — | 55.0 | |||||||||
Total | $ | 180.6 | $ | 177.5 | $ | 219.1 | ||||||
Dividends in Fiscal 2012 from Midstream & Marketing were used to fund a portion of the October 2011 Shell Transaction (see Note 4 to Consolidated Financial Statements).
UGI Common Stock Split
On July 29, 2014, UGI's Board of Directors approved a 3-for-2 common stock split. The additional shares were distributed September 5, 2014, to shareholders of record on August 22, 2014. Basic and diluted earnings per share and dividends declared per share for all periods presented have been retroactively adjusted to reflect the stock split.
Dividends and Distributions
On July 29, 2014, UGI's Board of Directors approved an approximate 10.6% increase in the quarterly dividend rate on UGI Common Stock to $0.2175 per share or $0.87 per share on an annual basis. The new quarterly dividend was effective with the dividend payable on October 1, 2014, to shareholders of record on September 15, 2014. Previously, on April 29, 2014, UGI’s Board of Directors approved an approximate 4.4% increase in the quarterly dividend rate on UGI Common Stock to $0.1967 per share or $0.7867 per share on an annual basis. This quarterly dividend rate was effective with the dividend paid on July 1, 2014, to shareholders of record on June 16, 2014.
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On April 28, 2014, the General Partner’s Board of Directors approved an increase in the quarterly distribution rate on AmeriGas Partners Common Units to $0.88 per Common Unit, equal to an annual rate of $3.52 per Common Unit. This quarterly distribution rate was effective with the distribution paid on May 19, 2014, to unitholders of record on May 9, 2014.
Long-term Debt and Credit Facilities
The Company’s debt outstanding at September 30, 2014, totaled $3,721.6 million (including current maturities of long-term debt of $77.2 million and short-term borrowings of $210.8 million) compared to debt outstanding at September 30, 2013, of $3,837.3 million (including current maturities of long-term debt of $67.2 million and short-term borrowings of $227.9 million). Total debt outstanding at September 30, 2014, consists of (1) $2,400.7 million of Partnership debt; (2) $573.0 million of UGI International debt; (3) $728.3 million of UGI Utilities’ debt; (4) $7.5 million of Energy Services debt; and (5) $12.1 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, 2014, includes $2,250.8 million of AmeriGas Partners’ Senior Notes, $40.9 million of other long-term debt and $109.0 million of AmeriGas OLP short-term borrowings.
UGI International. UGI International’s total debt at September 30, 2014, includes $432.0 million (€342.0 million) outstanding under Antargaz’ Senior Facilities term loan, $52.0 million under Flaga’s U.S. dollar-denominated term loan and a combined $74.6 million (€59.1 million) outstanding under Flaga’s euro-denominated term loans. Total UGI International debt outstanding at September 30, 2014, also includes (1) $8.0 million (€6.3 million) of Flaga short-term borrowings, and (2) $6.4 million (€5.1 million) of other long-term debt.
Antargaz. Antargaz has a variable-rate term loan agreement with a consortium of banks (“Senior Facilities Agreement”). At September 30, 2014, the Senior Facilities Agreement consists of (1) a €342 million variable-rate term loan and (2) a €40 million credit facility. Scheduled maturities under the term loan are €34.2 million due May 2015 and €307.8 million due March 2016. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of approximately 3.71% through the date of the term loan’s final maturity in March 2016. At September 30, 2014, the effective interest rate on Antargaz’ term loan was 4.79%.
Flaga. Flaga has a $52.0 million U.S. dollar-denominated three-year loan that expires in September 2016. The $52.0 million loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin. Flaga has effectively fixed the euribor component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the $52.0 million loan, by entering into a cross-currency swap arrangement with a bank. At September 30, 2014, the effective interest rate on the $52.0 million loan was 1.82%.
Flaga also has a €40 million ($50.5 million) euro-based term loan agreement under which €26.7 million matures in August 2016 and €13.3 million matures in September 2016, and a €19.1 million ($24.1 million) euro-based variable rate term loan that matures in October 2016. The €40 million term loans bear interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus margins, and the €19.1 million term loan bears interest at three-month euribor rates plus a margin. Flaga has effectively fixed the euribor components of the interest rates on these term loans through the dates of their expiration by entering into interest rate swap agreements. At September 30, 2014, the effective interest rates on the €40 million and €19.1 million term loans were 4.25% and 3.40%, respectively.
UGI Utilities. UGI Utilities’ total debt at September 30, 2014, includes long-term debt comprising $450.0 million of Senior Notes, $192.0 million of Medium-Term Notes, and $86.3 million of short-term borrowings.
In March 2014, UGI Utilities issued in a private placement $175 million of 4.98% Senior Notes due March 2044 (“4.98% Senior Notes”). The 4.98% Senior Notes were issued pursuant to a Note Purchase Agreement dated October 30, 2013, between UGI Utilities and certain note purchasers. The 4.98% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the 4.98% Senior Notes were used to repay $175 million of borrowings under UGI Utilities’ 364-day Term Loan Credit Agreement.
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
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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 2014, Fiscal 2013 and Fiscal 2012, Antargaz generally funded its operating cash flow needs without using its revolving credit facility and AvantiGas has funded its operating cash flow needs from cash on hand. Borrowings under the credit facilities and under the Energy Services Receivables Facility are classified as short-term debt on the Consolidated Balance Sheets.
AmeriGas Partners. In June 2014, AmeriGas OLP entered into an Amended and Restated Credit Agreement (“AmeriGas Credit Agreement”) with a group of banks which provides for borrowings up to $525 million (including a sublimit of $125 million for letters of credit). The AmeriGas Credit Agreement amends and restates AmeriGas OLP’s prior credit agreement entered into with a group of banks in June 2011, as amended from time to time. Among other things, the AmeriGas Credit Agreement reduces the applicable margin on base rate and Eurodollar borrowings and reduces the facility fee. The aforementioned margins and facility fees are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (as defined) which amount excludes, among other things, unrealized gains and losses on economic hedge transactions. The AmeriGas Credit Agreement expires in June 2019.
UGI International. Under its Senior Facilities Agreement, Antargaz has a €40 million credit facility that expires in March 2016 (“Antargaz Credit Facility”). Flaga has two principal working capital facilities (the “Flaga Credit Agreements”) comprising (1) a €46 million multi-currency working capital facility that includes an uncommitted €6 million overdraft facility (the “Flaga Multi-Currency Working Capital Facility”) and (2) a euro-denominated working capital facility that provides for borrowings and issuances of guarantees totaling €12 million (the “Euro Facility”). The Company intends to extend both the Flaga Multi-Currency Working Capital Facility and the Euro Facility prior to their expiration in December 2014.
UGI Utilities. UGI Utilities has a revolving credit agreement (the “UGI Utilities Credit Agreement”) with a group of banks providing for borrowings of up to $300 million (including a $100 million sublimit for letters of credit) that expires in October 2015.
Midstream & Marketing. Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $240 million (including a $50 million sublimit for letters of credit) that expires in June 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, 2014 and 2013, 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, 2014 | |||||||||||
AmeriGas Credit Agreement | $525.0 | $109.0 | $64.7 | $351.3 | 2.16 | % | |||||
Antargaz Credit Facility | €40.0 | €0.0 | €0.0 | €40.0 | N.A. | ||||||
Flaga Credit Agreements | €58.0 | €0.0 | €32.3 | €25.7 | N.A. | ||||||
UGI Utilities Credit Agreement | $300.0 | $86.3 | $2.0 | $211.7 | 1.03 | % | |||||
Energy Services Credit Agreement | $240.0 | $0.0 | $0.0 | $240.0 | N.A. | ||||||
September 30, 2013 | |||||||||||
AmeriGas Credit Agreement | $525.0 | $116.9 | $53.7 | $354.4 | 2.69 | % | |||||
Antargaz Credit Facility | €40.0 | €0.0 | €0.0 | €40.0 | N.A. | ||||||
Flaga Credit Agreements | €58.0 | €0.2 | €28.6 | €29.2 | 4.21 | % | |||||
UGI Utilities Credit Agreement | $300.0 | $17.5 | $2.0 | $280.5 | 1.18 | % | |||||
Energy Services Credit Agreement | $240.0 | $57.0 | $0.0 | $183.0 | 2.91 | % | |||||
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The average daily and peak short-term borrowings under the Company’s principal credit agreements during Fiscal 2014 and Fiscal 2013 are as follows:
2014 | 2013 | |||||||
(Millions of dollars or euros) | Average | Peak | Average | Peak | ||||
AmeriGas Credit Agreement | $156.6 | $320.0 | $103.8 | $200.5 | ||||
Flaga Credit Agreements | €1.1 | €3.6 | €4.3 | €11.9 | ||||
UGI Utilities Credit Agreement | $29.9 | $86.3 | $25.6 | $79.0 | ||||
Energy Services Credit Agreement | $41.4 | $114.0 | $44.5 | $85.0 | ||||
Energy Services has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2015. The Receivables Facility, as amended, provides Energy Services with the ability to borrow up to $150 million of eligible receivables during the period November through May, and up to $75 million of eligible receivables during the period June through October . Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank.
At September 30, 2014, the outstanding balance of ESFC trade receivables was $46.4 million and there was $7.5 million that was sold to the bank and reflected as short-term borrowings on the Consolidated Balance Sheets. At September 30, 2013, the outstanding balance of ESFC trade receivables was $55.0 million of which $30.0 million was sold to a commercial paper conduit of the bank. During Fiscal 2014 and Fiscal 2013, peak sales of receivables were $70.0 million and $46.5 million, respectively, and average daily amounts sold were $15.7 million and $10.4 million, respectively.
Cash Flows
Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the fourth and first fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest.
Operating Activities:
Year Ended September 30, | 2014 | 2013 | 2012 | |||||||||
(Millions of dollars) | ||||||||||||
Net cash provided by operating activities | $ | 1,005.4 | $ | 801.5 | $ | 707.7 | ||||||
Year-to-year variations in cash flow from operations can be significantly affected by changes in operating working capital especially during periods of significant changes in energy commodity prices. Cash flow from operating activities before changes in operating working capital was $1,011.9 million in Fiscal 2014, $845.6 million in Fiscal 2013 and $629.0 million in Fiscal 2012. The year-over-year increases in cash flow from operating activities before changes in operating working capital largely reflect the year-over-year increases in the Company’s operating results. Changes in operating working capital (used) provided operating cash flow of $(6.5) million in Fiscal 2014, $(44.1) million in Fiscal 2013 and $78.7 million in Fiscal 2012. The lower cash required to fund changes in working capital in Fiscal 2014 compared with Fiscal 2013 reflects, in large part, the greater net cash flow from changes in accounts receivable resulting from the significantly warmer weather at UGI International partially offset by cash used to fund Fiscal 2014 increases in propane inventories at AmeriGas Propane and natural gas inventories at Antargaz. The higher cash from changes in working capital in Fiscal 2012 reflects the timing of the acquisition of Heritage Propane on cash receipts from Heritage Propane customers.
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Investing Activities:
Year Ended September 30, | 2014 | 2013 | 2012 | |||||||||
(Millions of dollars) | ||||||||||||
Net cash used by investing activities | $ | (487.6 | ) | $ | (553.3 | ) | $ | (1,904.5 | ) | |||
Investing activity cash flow is principally affected by cash expenditures for property, plant and equipment; cash paid for acquisitions of businesses; changes in restricted cash balances and net cash proceeds from sales of property, plant and equipment. Cash paid for acquisitions in Fiscal 2014 includes the acquisition by Midstream & Marketing of the retail natural gas marketing business of EQT Energy, LLC, and several Partnership acquisitions. Cash paid for acquisitions in Fiscal 2013 largely includes Flaga’s acquisition of BP’s LPG distribution business in Poland; Midstream & Marketing’s acquisition of a non-operating working interest in natural gas acreage in the Marcellus Shale region of Pennsylvania; and several Partnership acquisitions. Cash paid for acquisitions in Fiscal 2012 principally reflects the January 2012 acquisition of Heritage Propane and the October 2011 acquisition of certain of Shell’s European LPG businesses. Cash expenditures for property, plant and equipment totaled $456.8 million in Fiscal 2014, $486.0 million in Fiscal 2013 and $339.4 million in Fiscal 2012. Cash from changes in restricted cash in futures brokerage accounts (used) provided cash of $(8.3) million in Fiscal 2014, $(5.3) million in Fiscal 2013 and $14.2 million in Fiscal 2012. The amount of restricted cash required in such accounts is generally the result of changes in underlying commodity prices. Other cash from investing activities includes, among other things, cash from the sale of excess properties of the Partnership subsequent to the Heritage Propane acquisition.
Financing Activities:
Year Ended September 30, | 2014 | 2013 | 2012 | |||||||||
(Millions of dollars) | ||||||||||||
Net cash (used) provided by financing activities | $ | (475.7 | ) | $ | (186.1 | ) | $ | 1,278.5 | ||||
Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; short-term borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units; and issuances or repurchases of UGI and AmeriGas Partners equity instruments.
The increases in dividends on UGI Common Stock and distributions on AmeriGas Partners’ publicly held Common Units during the thre