UGI CORP /PA/ - Annual Report: 2017 (Form 10-K)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2017
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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | ||
Smaller reporting company o | Emerging growth company o | |||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
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, 2017 was $8,491,215,725.
At November 14, 2017, there were 173,152,120 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 25, 2018 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 our Risk Factors included in Item 1A herein and 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 (“LPG”), 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, environmental, 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 or 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) customer, counterparty, supplier, or vendor defaults; (12) liability for uninsured claims and for claims in excess of insurance coverage, including those for personal injury and property damage arising from explosions, terrorism, and other catastrophic events that may result from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and LPG; (13) transmission or distribution system service interruptions; (14) political, regulatory and economic conditions in the United States and in foreign countries, including the current conflicts in the Middle East, and foreign currency exchange rate fluctuations, particularly the euro; (15) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (16) changes in commodity market prices resulting in significantly higher cash collateral requirements; (17) reduced distributions from subsidiaries impacting the ability to pay dividends; (18) changes in Marcellus Shale gas production; (19) the availability, timing and success of our acquisitions, commercial initiatives and investments to grow our businesses; (20) our ability to successfully integrate acquired businesses and achieve anticipated synergies; and (21) the interruption, disruption, failure or malfunction of our information technology systems, including due to cyber attack.
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 and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business, (2) own and operate natural gas and electric distribution utilities, and (3) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production, electricity generation and energy services business. Internationally, we distribute LPG and market other energy products and services in Europe. Our subsidiaries and affiliates operate principally in the following four business segments:
• | AmeriGas Propane |
• | UGI International |
• | Midstream & Marketing |
• | UGI Utilities |
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The AmeriGas Propane segment consists of the propane distribution business of AmeriGas Partners, L.P. (“AmeriGas Partners” or the “Partnership”). In addition to distributing propane, the Partnership also sells, installs, and services propane appliances, including heating systems, and operates a residential heating, ventilation, air conditioning, plumbing, and related services business in certain counties of Pennsylvania, Delaware, and Maryland. The Partnership conducts its propane distribution business through its principal operating subsidiary, AmeriGas Propane, L.P., and 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 segment consists of LPG distribution businesses conducted by our subsidiaries and affiliates in France, Poland, Austria, Hungary, the Czech Republic, Slovakia, Switzerland, Romania, Belgium, the Netherlands, Luxembourg, the United Kingdom, Italy, Finland, Denmark, Norway and Sweden. In addition, UGI International conducts an energy marketing business in France, Belgium, the Netherlands and the United Kingdom. UGI International is the largest distributor of LPG in France, Austria, Belgium, Denmark, Luxembourg and Hungary and one of the largest distributors of LPG in Poland, the Czech Republic, Slovakia, Norway, the Netherlands and Sweden. These businesses are conducted principally through our subsidiaries, UGI France SAS, Flaga GmbH, and AvantiGas Limited.
The Midstream & Marketing segment consists of energy-related businesses conducted by our wholly-owned subsidiary, UGI Energy Services, LLC (“Energy Services”), a subsidiary of UGI Enterprises, LLC (“Enterprises”). These businesses (i) conduct energy marketing in the Mid-Atlantic region of the United States, (ii) operate and own a natural gas liquefaction, storage and vaporization facility and propane-air mixing assets, (iii) manage natural gas pipeline and storage contracts, and (iv) develop, own and operate pipelines, gathering infrastructure and gas storage facilities primarily in the Marcellus Shale region of Pennsylvania and own all or a portion of an electricity generation facility. The Midstream & Marketing segment also includes a subsidiary of Enterprises that conducts a heating, ventilation, air conditioning, refrigeration, mechanical and electrical contracting, and project management service business in portions of eastern and central Pennsylvania.
The UGI Utilities segment consists of the regulated natural gas distribution businesses (“Gas Utility”) of our subsidiary, UGI Utilities, Inc. (“UGI Utilities”), UGI Utilities’ subsidiaries, UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”), and UGI Utilities’ regulated electric distribution business in Pennsylvania (“Electric Utility”). Gas Utility serves over 635,000 customers in eastern and central Pennsylvania and more than 500 customers in portions of one Maryland county. UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” Electric Utility serves approximately 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania. 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. Electric Utility is regulated by the PUC.
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 2017, 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.
In Fiscal 2017, Energy Services’ Sunbury Pipeline, a federally-regulated 35-mile, 20-inch pipeline, was placed into service. The Sunbury Pipeline is an interstate natural gas pipeline in central Pennsylvania that serves the Panda Hummel Station combined-cycle 1,100 megawatt power generation facility near the Shamokin Dam in Snyder County, Pennsylvania. Energy Services also completed construction and placed into service the Manning LNG liquefaction plant, which is designed to produce 10,000 dekatherms of liquefied natural gas (“LNG”) per day and provide 500,000 gallons of storage and truck-loading capability.
In Fiscal 2017, Energy Services also continued development of the Steelton LNG peak shaving facility, which is designed to provide 65,000 dekatherms per day of peaking capacity and two million gallons of LNG storage and is expected to be completed in Fiscal 2018. In addition, Energy Services made progress on the PennEast Pipeline project, the development of an approximately 118-mile pipeline from Luzerne County, Pennsylvania to the Trenton-Woodbury interconnection in New Jersey. Energy Services owns a 20% interest in the PennEast Pipeline project. When completed, the PennEast Pipeline will transport approximately 1 billion cubic feet of lower cost natural gas to residential and commercial customers each day. In April 2017, the Federal Energy Regulatory Commission (“FERC”) issued a Final Environmental Impact Statement with respect to the PennEast Pipeline project
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and we expect to receive a FERC Certificate for the PennEast Pipeline project in Fiscal 2018. In October 2017, our Midstream & Marketing business also enhanced the buildout of its natural gas infrastructure assets with the acquisition of approximately 60 miles of natural gas gathering lines in northern Pennsylvania.
In Fiscal 2017, UGI International, through subsidiaries, acquired Preem Gas AB (now Kosan Gas AB), an LPG marketing and distribution company in Sweden, and Dutch energy marketer DVEP Investeringen B.V., a marketer of natural gas and electricity to small and medium enterprises in the Netherlands. In addition, in October 2017, UGI International, through a subsidiary, acquired Totalgaz Italia S.r.l. (now UniverGas Italia S.r.l.), the LPG distribution business of TotalErg S.p.A., serving customers in the northern and central regions of Italy.
UGI Utilities continued to execute on its infrastructure replacement and system betterment program, with record capital expenditures in Fiscal 2017. For example, UGI Utilities made progress toward its goal of replacing the cast iron portions of its gas mains by March 2027 and the bare steel portion of its gas mains by September 2041. UGI Utilities also implemented a new customer information management system that will unify all four of its utilities and streamline operations. Effective October 19, 2016, new base rates went into effect for UGI Gas resulting in an approximate $27.0 million increase in annual base rate revenues. In addition, in January 2017, PNG filed a request with the PUC to increase PNG’s base operating revenues for residential, commercial, and industrial customers and, in August 2017, the PUC approved a settlement that permitted PNG to increase its annual base distribution rates by $11.3 million, and the increase became effective October 20, 2017.
Corporate Information
UGI Corporation was incorporated in Pennsylvania in 1991. The Company is not subject to regulation by the PUC and it is a “holding company” under the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). PUHCA 2005 and the implementing regulations of the 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,” “us,” and “its,” are sometimes used as abbreviated references to UGI Corporation or, collectively, UGI Corporation and its consolidated subsidiaries. Similarly, the terms “AmeriGas Partners” and the “Partnership” are sometimes used as abbreviated references to AmeriGas Partners, L.P. or, collectively, AmeriGas Partners, L.P. and its subsidiaries, and the term “UGI Utilities” is sometimes used as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries. The terms “Fiscal 2018”, “Fiscal 2017”, and “Fiscal 2016” refer to the fiscal years ended September 30, 2018, September 30, 2017, and September 30, 2016, respectively.
The Company’s corporate website can be found at www.ugicorp.com. Information on our website is not intended to be incorporated into this report. The Company makes available free of charge at this website (under the “Investor Relations - Financial Reports - SEC Filings and Proxy” caption) copies of its reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, including its Annual Reports on Form 10-K, its Quarterly Reports on Form 10-Q and its Current Reports on Form 8-K. The Company’s Principles of Corporate Governance, Code of Ethics for the Chief Executive Officer and Senior Financial Officers, Code of Business Conduct and Ethics for Directors, Officers and Employees, and charters of the Corporate Governance, Audit, Compensation and Management Development, and Safety, Environmental and Regulatory Compliance Committees of the Board of Directors are also available on the Company’s website, under the captions “Investor Relations - Corporate Governance - Committees.” All of these documents are also available free of charge by writing to Treasurer, UGI Corporation, P.O. Box 858, Valley Forge, PA 19482.
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AMERIGAS PROPANE
Products, Services and Marketing
Our domestic propane distribution business is conducted through AmeriGas Partners. AmeriGas Propane is responsible for managing the Partnership. The Partnership serves over 1.8 million customers in all 50 states from approximately 1,900 propane distribution locations. In addition to distributing propane, the Partnership also sells, installs and services propane appliances, including heating systems, and operates a residential heating, ventilation, air conditioning, plumbing, and related services business in certain counties of Pennsylvania, Delaware, and Maryland. Typically, the Partnership’s propane distribution locations are in suburban and rural areas where natural gas is not readily available. Our local offices generally consist of a business office and propane storage. As part of its overall transportation and distribution infrastructure, the Partnership operates as an interstate carrier in all states throughout the continental U.S.
The Partnership sells propane primarily to residential, commercial/industrial, motor fuel, agricultural and wholesale customers. The Partnership distributed approximately 1.1 billion gallons of propane in Fiscal 2017. Approximately 96% of the Partnership’s Fiscal 2017 sales (based on gallons sold) were to retail accounts and approximately 4% were to wholesale and supply customers. Sales to residential customers in Fiscal 2017 represented approximately 37% of retail gallons sold; commercial/industrial customers 38%; motor fuel customers 17%; and agricultural customers 4%. Transport gallons, which are large-scale deliveries to retail customers other than residential, accounted for 4% of Fiscal 2017 retail gallons. No single customer represents, or is anticipated to represent, more than 5% of the Partnership’s consolidated revenues.
The Partnership continues to expand its AmeriGas Cylinder Exchange (“ACE”) program. At September 30, 2017, ACE cylinders were available at over 50,000 retail locations throughout the U.S. Sales of our ACE cylinders to retailers are included in commercial/industrial sales. The ACE program enables consumers to purchase or exchange propane cylinders at various retail locations such as home centers, gas stations, mass merchandisers and grocery and convenience stores. We also supply retailers with large propane tanks to enable retailers to replenish customers’ propane cylinders directly at the retailer’s location.
Residential and commercial customers use propane primarily for home heating, water heating and cooking purposes. Commercial users include hotels, restaurants, churches, warehouses, and retail stores. Industrial customers use propane to fire furnaces, as a cutting gas and in other process applications. Other industrial customers are large-scale heating accounts and local gas utility customers who use propane as a supplemental fuel to meet peak load deliverability requirements. As a motor fuel, propane is burned in internal combustion engines that power school buses and other over-the-road vehicles, forklifts, and stationary engines. Agricultural uses include tobacco curing, chicken brooding, crop drying, and orchard heating. In its wholesale operations, the Partnership principally sells propane to large industrial end-users and other propane distributors.
Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from the bobtail truck, which generally holds 2,400 to 3,000 gallons of propane, into a stationary storage tank on the customer’s premises. The Partnership owns most of these storage tanks and leases them to its customers. The capacity of these tanks ranges from approximately 120 gallons to approximately 1,200 gallons. The Partnership also delivers propane in portable cylinders, including ACE and motor fuel cylinders. Some of these deliveries are made to the customer’s location, where cylinders are either picked up or replenished in place.
During Fiscal 2017, we continued to make significant investments in technology to reduce operational costs while improving our customers’ experience. For example, (i) we rolled out the AmeriMobile distribution platform to all district locations, increasing the use of technology to more efficiently deploy our drivers in making deliveries to customers, and (ii) we continue to promote a customer service culture through the development of our on-line customer experience, which enables customers to transact with us after hours, to seek customer support through live on-line chat, and to receive delivery confirmations by text.
Propane Supply and Storage
The United States propane market has over 250 domestic and international sources of supply, including the spot market. Supplies of propane from the Partnership’s sources historically have been readily available. Volatility in the U.S. propane market stabilized in Fiscal 2017 and the propane industry experienced normal inventory levels, following record high levels reached in the fiscal year ended September 30, 2015 and Fiscal 2016. The availability and pricing of propane supply is dependent upon, among other things, the severity of winter weather, the price and availability of competing fuels such as natural gas and crude oil, and the amount and availability of exported supply and, to a much lesser extent, imported supply. In recent years, there has been an increase in overseas demand for U.S. propane exports as the U.S. continues to have low cost reliable sources of propane. We utilized our extensive distribution and logistics channels to minimize disruption to our customers due to supply chain interruptions resulting from natural disasters in Fiscal 2017, including Hurricanes Harvey and Irma and the wildfires in California.
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During Fiscal 2017, approximately 95% of the Partnership’s propane supply was purchased under supply agreements with terms of 1 to 3 years. Although no assurance can be given that supplies of propane will be readily available in the future, management currently expects to be able to secure adequate supplies during Fiscal 2018. 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. Plains Marketing, L.P. and Targa Liquids Marketing & Trade LLC supplied approximately 28% of the Partnership’s Fiscal 2017 propane supply. No other single supplier provided more than 10% of the Partnership’s total propane supply in Fiscal 2017. In certain geographic 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 make it an attractive energy source for consumers and developers of new homes. Fuel oil is also a major competitor of propane but is currently more expensive than propane as well as a less environmentally attractive energy source. Historically, however, fuel oil has been 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, LNG and compressed natural gas. Wholesale propane distribution is a highly competitive, low margin business. Propane sales to other retail distributors and large-volume, direct-shipment industrial end-users are price sensitive and frequently involve a competitive bidding process.
Retail propane industry volumes have been declining for several years and no or modest growth in total demand is foreseen in the next several years. Therefore, the Partnership’s ability to grow within the industry is dependent on its ability to acquire other retail distributors and to achieve internal growth, which includes expansion of the ACE program and the National Accounts program (through which the Partnership encourages multi-location propane users to enter into a single AmeriGas Propane supply agreement rather than agreements with multiple 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 2017, the Partnership’s retail propane sales totaled more than 1.0 billion gallons. Based on the most recent annual survey by the American Petroleum Institute, 2015 domestic retail propane sales (annual sales for other than chemical uses) in the U.S. totaled approximately 8.5 billion gallons. Based on LP-GAS magazine rankings, 2015 sales volume of the ten largest propane distribution companies (including AmeriGas Partners) represented approximately 40% of domestic retail sales.
Properties
As of September 30, 2017, the Partnership owned approximately 84% of its nearly 675 local offices throughout the country. The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 30, 2017, the Partnership operated a transportation fleet with the following assets:
Approximate Quantity & Equipment Type | % Owned | % Leased | |
940 | Trailers | 78% | 22% |
350 | Tractors | 7% | 93% |
510 | Railroad tank cars | 0 | 100% |
3,100 | Bobtail trucks | 32% | 68% |
400 | Rack trucks | 34% | 66% |
3,800 | Service and delivery trucks | 38% | 62% |
Other assets owned at September 30, 2017 included approximately 1.7 million stationary storage tanks with typical capacities of
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more than 120 gallons, approximately 4.7 million portable propane cylinders with typical capacities of 1 to 120 gallons, 21 terminals and 10 transflow units.
Trade Names, Trade and Service Marks
The Partnership markets propane and other services principally under the “AmeriGas®,” “America’s Propane Company®,” “Heritage Propane®,” “Relationships Matter®,” “Metro Lawn®” and “ServiceMark®” trade names and related service marks. The Partnership also markets propane under various other trade names throughout the United States. 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 (except its licenses with permitted transferees and on 12 months prior notice in the case of UGI), without penalty, if the General Partner is removed as general partner of the Partnership for cause. If the General Partner ceases to serve as the general partner of the Partnership other than for cause, the General Partner has the option to terminate its license agreement upon payment of a fee to AmeriGas Propane, L.P. 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 AmeriGas Propane, L.P. UGI and the General Partner each also have the right to terminate its respective license agreement in order to settle any claim of infringement, unfair competition or similar claim or if the agreement has been materially breached without appropriate cure.
Seasonality
Because many customers use propane for heating purposes, the Partnership’s retail sales volume is seasonal. During Fiscal 2017, approximately 64% of the Partnership’s retail sales volume occurred, and substantially all of the Partnership’s operating income was earned, during the peak heating season from October through March. As a result of this seasonality, sales are typically higher in the Partnership’s first and second fiscal quarters (October 1 through March 31). Cash receipts are generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the winter heating season.
Sales volume for the Partnership traditionally fluctuates from year-to-year in response to variations in weather, prices, competition, customer mix and other factors, such as conservation efforts and general economic conditions. For information on national weather statistics, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Government Regulation
The Partnership is subject to various federal, state and local environmental, health, safety and transportation laws and regulations governing the storage, distribution and transportation of propane and the operation of bulk storage propane terminals. Generally, these laws impose limitations on the discharge of pollutants, establish standards for the handling of solid and hazardous substances and require the investigation and cleanup of environmental contamination. These laws include, among others, the federal Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act (“OSHA”), the Homeland Security Act of 2002, the Emergency Planning and Community Right-to-Know Act, the Clean Water Act and comparable state statutes. We incur expenses associated with compliance with our obligations under federal and state environmental laws and regulations, and we believe that we are in material compliance with all of our obligations. We maintain various permits that are necessary to operate our facilities, some of which may be material to our operations. We continually monitor our operations with respect to potential environmental issues, including changes in legal requirements.
Hazardous Substances and Wastes
The Partnership is investigating and remediating contamination at a number of present and former operating sites in the United States, including former sites where it or its former subsidiaries operated manufactured gas plants. CERCLA and similar state laws impose joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a “hazardous substance” into the environment without regard to fault or the legality of the original conduct. Propane is not a hazardous substance within the meaning of CERCLA.
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Health and Safety
The Partnership is subject to the requirements of OSHA and comparable state laws that regulate the protection of the health and safety of our workers. These laws require the Partnership, among other things, to maintain information about materials, some of which may be hazardous or toxic, that are used, released, or produced in the course of our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and responders, commercial and industrial customers and local citizens in accordance with applicable federal and state Emergency Planning and Community Right-to-Know Act requirements. The Partnership’s operations are also subject to the safety hazard communication requirements and reporting obligations set forth in federal workplace standards.
All states in which the Partnership operates have adopted fire safety codes that regulate the storage, distribution, and use of propane. In some states, these laws are administered by state agencies, and in others they are administered on a municipal level. The Partnership conducts training programs to help ensure that its operations are in compliance with applicable governmental regulations. With respect to general operations, the Partnership is subject in all jurisdictions in which it operates to rules and procedures governing the safe handling of propane, including those established by National Fire Protection Association Pamphlets No. 54 and No. 58 and various state, local and international codes (including international fire, building and fuel gas codes). Management believes that the policies and procedures currently in effect at all of its facilities for the handling, storage, distribution and use of propane are consistent with industry standards and are in compliance, in all material respects, with applicable environmental, health and safety laws.
With respect to the transportation of propane by truck, the Partnership is subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act, the Hazardous Materials & Transportation Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials, including propane for purposes of these regulations, and are administered by the Pipeline and Hazardous Materials Safety Administration of the U.S. Department of Transportation (“DOT”). The Natural Gas Safety Act of 1968 required the DOT to develop and enforce minimum safety regulations for the transportation of gases by pipeline. The DOT's pipeline safety regulations apply, among other things, to a propane gas system that supplies 10 or more residential customers or two or more commercial customers from a single source and to a propane gas system any portion of which is located in a public place. The DOT’s pipeline safety regulations require operators of all gas systems to provide operator qualification standards and training and written instructions for employees and third party contractors working on covered pipelines and facilities, establish written procedures to minimize the hazards resulting from gas pipeline emergencies, and conduct and keep records of inspections and testing. Operators are subject to the Pipeline Safety Improvement Act of 2002. Management believes that the procedures currently in effect at all of the Partnership’s facilities for the handling, storage, transportation and distribution of propane are consistent with industry standards and are in compliance, in all material respects, with applicable laws and regulations.
Climate Change
There continues to be concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global warming. Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, we anticipate that this will provide us with a competitive advantage over other sources of energy, such as fuel oil and coal, to the extent new climate change regulations become effective. At the same time, increased regulation of GHG emissions, especially in the transportation sector, could impose significant additional costs on the Partnership, suppliers and customers. In recent years, there has been an increase in state initiatives aimed at regulating GHG emissions. For example, the California Environmental Protection Agency established a Cap & Trade program that requires certain covered entities, including propane distribution companies, to purchase allowances to compensate for the GHG emissions created by their business operations. The impact of new legislation and regulations will depend on a number of factors, including (i) which industry sectors would be impacted, (ii) the timing of required compliance, (iii) the overall GHG emissions cap level, (iv) the allocation of emission allowances to specific sources, and (v) the costs and opportunities associated with compliance.
Employees
The Partnership does not directly employ any persons responsible for managing or operating the Partnership. The General Partner provides these services and is reimbursed for its direct and indirect costs and expenses, including all compensation and benefit costs. At September 30, 2017, the General Partner had approximately 8,100 employees, including over 350 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.
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UGI INTERNATIONAL
UGI International, through subsidiaries and affiliates, conducts (i) an LPG distribution business in 17 countries throughout Europe (France, Poland, Austria, Hungary, the Czech Republic, Slovakia, Switzerland, Romania, Belgium, the Netherlands, Luxembourg, the United Kingdom, Italy, Finland, Denmark, Norway and Sweden), and (ii) an energy marketing business in France, Belgium, the Netherlands and the United Kingdom. UGI International is the largest distributor of LPG in France, Austria, Belgium, Denmark, Luxembourg and Hungary and one of the largest distributors of LPG in Poland, the Czech Republic, Slovakia, Norway, the Netherlands and Sweden.
Products, Services and Marketing
During Fiscal 2017, UGI International sold approximately 930 million gallons of LPG throughout Europe. UGI International’s customer base primarily consists of residential, commercial, industrial, agricultural, wholesale and autogas customers that use LPG for space heating, cooking, water heating, motor fuel, leisure activities, crop drying, irrigation, construction, power generation, manufacturing and aerosol propellant. UGI International sells LPG in cylinders and in small, medium and large bulk tanks. UGI International sells LPG in cylinders through retail outlets, such as supermarkets, individually owned stores and gas stations. Sales of LPG are also made to service stations to fuel vehicles that run on LPG. In addition to LPG sales, UGI International sold approximately 17 million dekatherms of natural gas during Fiscal 2017.
At September 30, 2017, UGI International had over 460,000 bulk LPG customers, approximately 31,500 energy marketing customers and over 18.5 million cylinders in circulation. Approximately 19% of UGI International’s Fiscal 2017 sales (based on volumes) were attributed to cylinder, 42% to small bulk, 9% to medium bulk, 16% to large bulk, 11% to wholesale and 3% to service stations for automobiles. UGI International also provides logistics, storage and other services to third-party LPG distributors. No single customer represents, or is anticipated to represent, more than 5% of total revenues for UGI International.
Sales to small bulk customers represent the largest customer segment of UGI International’s business in terms of volume, revenue and total margin. Small bulk customers are primarily residential and small business users, such as restaurants, that use LPG mainly for heating and cooking. Small bulk customers also include municipalities, which use LPG for heating certain sports facilities and swimming pools.
Medium bulk customers consist mainly of large residential housing developments, hospitals, hotels, municipalities, medium-sized industrial enterprises and poultry brooders. Large bulk customers include agricultural 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. Additionally, LPG cylinders are used to supply fuel for forklift trucks. The market demand for cylinders continues to slowly decline, due primarily to customers gradually converting to other household energy sources for cooking and heating, such as natural gas and electricity.
LPG Supply and Storage
In Fiscal 2017, UGI International centralized its European supply function. Supplies of LPG from UGI International’s sources have historically been readily available. 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 LPG supplies during Fiscal 2018.
During Fiscal 2017, UGI International contracted with more than 50 international oil and gas trading companies (including Total Raffinage France, SHV, GUNVOR, SIBUR and TCO/Chevron) and refineries (including Stanlow and Mosmorran) to meet its LPG supply requirements throughout Europe. UGI International’s LPG supply is transported via rail and sea. Agreements are generally annual term agreements with pricing based on internationally quoted market prices or the spot market. Additionally, UGI International purchased LPG on the international market and on the domestic spot market. In certain geographic areas, however, a single supplier provides more than 50% of UGI International’s requirements. Disruptions in supply in these areas could have an adverse impact on UGI International’s margins. Because UGI International’s profitability is sensitive to changes in wholesale LPG costs, UGI International generally seeks to pass on increases in the cost of LPG to its customers. There is no assurance, however, that UGI International 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.
UGI International stores LPG at various storage facilities and terminals located across Europe. UGI International has interests in 19 primary storage facilities and over 60 secondary storage facilities. It also manages an extensive logistics and transportation
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network. Access to seaborne facilities allows UGI International to diversify its LPG supplies through imports. LPG stored in primary storage facilities is transported to smaller storage facilities by rail, sea and road. At secondary storage facilities, LPG is loaded into cylinders or trucks equipped with tanks and then delivered to customers.
Competition and Seasonality
The LPG markets in Western and Northern Europe are mature, with modest declines in total demand due to competition with other fuels and other energy sources, conservation and the economic climate. In the Eastern European countries in which UGI International operates, the demand for LPG is expected to grow in certain segments. Sales volumes are affected principally by the severity of the weather and customer migration to alternative energy forms, including natural gas, electricity, heating oil and wood. High LPG prices also 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 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 European 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 addition to price, UGI International also competes for customers in its various markets based on contract terms.
UGI International competes locally as well as regionally in many of its service territories. Additionally, UGI International, particularly in France, competes with supermarket chains that affiliate with LPG distributors to offer their own brands of cylinders. UGI International seeks to increase demand for its LPG cylinders through marketing and product innovations.
Because many of UGI International’s customers use LPG for heating, sales volume is affected principally by the severity of the temperatures during the heating season months and traditionally fluctuates from year-to-year in response to variations in weather, prices and other factors, such as conservation efforts and the economic environment. Demand for LPG is higher during the colder months of the year. For historical information on weather statistics for UGI International, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Government Regulation
UGI International’s business is subject to various laws and regulations at the country and local levels, as well as at the European Union (“EU”) level, with respect to matters such as protection of the environment, the storage and handling of hazardous materials and flammable substances, data privacy and protection, competition, pricing, regulation of contract terms, anti-corruption (including the U.S. Foreign Corrupt Practices Act, Sapin II and the U.K. Bribery Act), and the safety of persons and property.
With respect to data privacy, the EU adopted the General Data Protection Regulation (“GDPR”), which will become enforceable in May of 2018. The GDPR expands the current EU data protection laws to all companies processing data of EU residents. It primarily focuses on unifying and strengthening the regulations dealing with the collection, processing, use and security of personal and sensitive data.
Properties
In addition to regional headquarter locations and sales offices throughout its service territory, UGI International also has interests in 19 primary storage facilities and over 60 secondary storage facilities.
Employees
At September 30, 2017, UGI International had approximately 2,500 employees.
MIDSTREAM & MARKETING
Retail Energy Marketing
Our retail energy marketing business is conducted through Energy Services and sells natural gas, liquid fuels and electricity to over 14,000 residential, commercial and industrial customers at approximately 37,000 locations. Energy Services serves customers in all or portions of Pennsylvania, New Jersey, Delaware, New York, Ohio, Maryland, Massachusetts, Virginia, North Carolina, South Carolina and the District of Columbia. Energy Services distributes natural gas through the use of the distribution systems of 39 local gas utilities. It supplies power to customers through the use of the transmission lines of 20 utility systems.
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Historically, a majority of Energy Services’ commodity sales have been made under fixed-price agreements, which typically contain a take-or-pay arrangement that permits customers to purchase a fixed amount of product for a fixed price during a specified period, and requires payment 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 (“NYMEX”) and Intercontinental Exchange (“ICE”), (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
Our Midstream assets, which are owned by Energy Services and its subsidiaries, comprise a natural gas liquefaction, storage and vaporization facility in Temple, Pennsylvania, and propane storage and propane-air mixing stations in Bethlehem, Reading, Hunlock Creek, and White Deer, Pennsylvania. Energy Services and its subsidiaries also operate propane storage, rail transshipment terminals and propane-air mixing stations in Steelton and Williamsport, Pennsylvania. These assets are used in Midstream & Marketing’s energy peaking business that provides supplemental energy, primarily LNG and propane-air mixtures, to gas utilities on interstate pipelines at times of high demand (generally during periods of coldest winter weather). In addition, Energy Services sells LNG to customers for use by trucks, drilling rigs, other motor vehicles and facilities located off the gas grid. Our Midstream & Marketing segment also manages natural gas pipeline and storage contracts for UGI Utilities and Frontier Natural Gas.
In Fiscal 2017, our Midstream & Marketing segment continued making investments to expand its energy peaking and LNG fuels business by completing construction and placing into service the Manning LNG liquefaction plant and making progress on the construction of the Steelton LNG peak shaving facility. The Manning LNG liquefaction plant can produce 10,000 dekatherms of LNG per day with 500,000 gallons of storage and truck-loading capability. The Steelton LNG peak shaving facility has been designed to provide 65,000 dekatherms per day of peaking capacity and two million gallons of LNG storage and is expected to be completed in Fiscal 2018.
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 north-central Pennsylvania and have a total storage capacity of 15 million dekatherms and a maximum daily withdrawal quantity of 224,000 dekatherms. In Fiscal 2017, Energy Services leased more than 85% of the firm capacity at its underground natural gas facilities to third parties.
Energy Services also operates a gathering system in the Marcellus Shale region of northeastern Pennsylvania that is capable of delivering up to 120,000 dekatherms of capacity per day to the Tennessee Gas Pipeline and 470,000 dekatherms per day to the Transcontinental Gas Pipeline.
In Fiscal 2017, our Midstream & Marketing segment also made progress on its participation in the PennEast Pipeline project to develop an approximately 118-mile pipeline from Luzerne County, Pennsylvania to the Transco pipeline interconnection in Mercer County, New Jersey. When completed, the pipeline will transport approximately 1 billion cubic feet of lower cost natural gas to residential and commercial customers each day. In April 2017, FERC issued a Final Environmental Impact Statement with respect to the PennEast Pipeline project and we expect to receive a FERC Certificate and commence construction on the project in Fiscal 2018.
On January 1, 2017, the Sunbury Pipeline, a federally-regulated 35-mile, 20-inch pipeline, was placed into service. The Sunbury Pipeline is an interstate natural gas pipeline in central Pennsylvania that serves the Panda Hummel Station combined-cycle 1,100 megawatt power generation facility near the Shamokin Dam in Snyder County, Pennsylvania.
Future planned investments are expected to cover a range of midstream asset opportunities, including interstate pipelines, local gathering systems and gas storage facilities and complementary and related investments.
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Electricity Generation Assets
Midstream & Marketing’s electricity generation assets consist 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 the Conemaugh generation station (“Conemaugh”), a 1,711-megawatt, coal-fired electricity 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 electricity generating station, and owns and operates a landfill gas-fueled generation plant near Hegins, Pennsylvania, with gross generating capacity of 11 megawatts. The plant qualifies for renewable energy credits. Additionally, UGID owns and operates 13.5 megawatts of solar-powered generation capacity in Pennsylvania, Maryland and New Jersey.
HVAC Business
Our Midstream & Marketing segment also conducts a heating, ventilation, air conditioning, mechanical & electrical contracting, and project management service business through its HVAC business unit, which serves portions of eastern and central Pennsylvania. This business serves customers in residential, commercial, industrial and new construction markets.
Competition
Our Midstream & Marketing segment competes with other midstream operators to sell gathering, compression, storage and pipeline transportation services. Our Midstream & Marketing segment competes in both the regulated and non-regulated environment against interstate and intrastate pipelines that gather, compress, process, transport and market natural gas. Our Midstream & Marketing segment 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.
Our Midstream & Marketing segment 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. Midstream & Marketing’s midstream asset business has faced an increase in competition in recent years with the consolidation of companies that have resulted in large, national competitors that can offer a suite of services across all customer segments.
Our electricity generation assets compete 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
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. In Fiscal 2017, FERC extended Energy Services’ market-based rate authority through 2019. 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 currently operate natural gas storage facilities under FERC certificate approvals and offer services to wholesale customers at FERC-approved market-based rates. Two other Energy Services subsidiaries operate natural gas pipelines that are subject to FERC regulation. UGI Mt. Bethel Pipeline Company, LLC operates a 12.5-mile, 12-inch pipeline located in Northampton County, Pennsylvania, and UGI Sunbury, LLC operates the Sunbury Pipeline, a 35-mile, 20-inch diameter pipeline located in central Pennsylvania that was placed into service on January 1, 2017. Energy Services and its subsidiaries undertake various activities to maintain compliance with the FERC Standards of Conduct with respect to pipeline operations. Energy Services is also subject to FERC reporting requirements, market manipulation rules and other FERC enforcement and regulatory powers with respect to its wholesale commodity business.
Midstream & Marketing’s midstream assets include natural gas gathering pipelines and compression in northeastern Pennsylvania that are regulated under the Pipeline Safety Improvement Act of 2002 and subject to operational oversight by both the Pipeline and Hazardous Materials Safety Administration and the PUC.
Certain of our Midstream & Marketing businesses are 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
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storage LPG terminals. These laws include, among others, the Resource Conservation and Recovery Act, CERCLA, the Clean Air Act, OSHA, the Homeland Security Act of 2002, the Emergency Planning and Community Right-to-Know Act, the Clean Water Act and comparable state statutes. CERCLA imposes joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a “hazardous substance” into the environment without regard to fault or the legality of the original conduct. With respect to the operation of natural gas gathering and transportation pipelines, Energy Services also is required to comply with the provisions of the Pipeline Safety Improvement Act of 2002 and the regulations of the U.S. DOT.
Our Midstream & Marketing’s electricity generation assets own electric generation facilities that are within the control area of PJM and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. UGID receives certain revenues collected by PJM, determined under an approved rate schedule. Like Energy Services, UGID has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates, and FERC recently extended UGID’s market-based rate authority through 2019. UGID is also subject to FERC reporting requirements, market manipulation rules and other FERC enforcement and regulatory powers.
Employees
At September 30, 2017, Midstream & Marketing had over 600 employees, including nearly 300 employees in its HVAC business and approximately 25 employees at UGID.
UGI UTILITIES
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 635,000 customers in eastern and central Pennsylvania and more than 500 customers in portions of one Maryland county. Gas Utility is regulated by the PUC and, with respect to its customers in Maryland, the Maryland Public Service Commission.
Service Area; Revenue Analysis
Gas Utility provides natural gas distribution services to over 635,000 customers in certificated portions of 44 eastern and central Pennsylvania counties through its distribution system. Contemporary materials, such as plastic or coated steel, comprise approximately 90% of Gas Utility’s 12,300 miles of gas mains, with bare steel pipe comprising approximately 8% and cast iron pipe comprising approximately 2% 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 of its gas mains by September 2041. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock Haven, Pittston, Pottsville and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility’s service area are major production centers for basic industries such as specialty metals, aluminum, glass and paper product manufacturing. Gas Utility also distributes natural gas to more than 500 customers in portions of one Maryland county.
System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2017 was approximately 243 billion cubic feet (“bcf”). System sales of gas accounted for approximately 23% of system throughput, while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for approximately 77% 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 8 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 Marcellus, Gulf Coast, Mid-Continent, and Appalachian sources. For its transportation and storage functions, Gas Utility has long-term agreements with a number of pipeline companies, including Texas Eastern Transmission, LP, Columbia Gas Transmission, LLC, Transcontinental Gas Pipeline Company, LLC, Dominion Transmission, Inc., ANR Pipeline Company and Tennessee Gas Pipeline Company, L.L.C.
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Gas Supply Contracts
During Fiscal 2017, Gas Utility purchased approximately 77.2 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. Eighty-five percent (85%) of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 15% 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 12 months. Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the months of November through March.
Seasonality
Because many of its customers use gas for heating purposes, Gas Utility’s sales are seasonal. For Fiscal 2017, approximately 60% of Gas Utility’s sales volume was supplied, and approximately 90% of Gas Utility’s operating income was earned, during the peak heating season from October through March.
Competition
Natural gas is a fuel that competes with electricity and oil and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of the equipment. Natural gas generally benefits from a competitive price advantage over oil, electricity and propane, although the price gap between natural gas and oil narrowed in recent years due to a reduction in the price of oil. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility responds to this competition with marketing and sales efforts designed to retain, expand, and grow its customer base.
In substantially all of its service territories, Gas Utility is the only regulated gas distribution utility having the right, granted by the PUC or by law, to provide gas distribution services. All of Gas Utility’s customers, including core-market customers, have the right to purchase gas supplies from entities other than natural gas distribution utility companies.
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 40% of Gas Utility’s annual throughput volume for commercial and industrial customers includes non-interruptible customers with firm rates with locations that afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. In addition, more than 20% 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 38 such customers, 34 of which have transportation contracts extending beyond Fiscal 2018. The majority of these customers are served under transportation contracts having 3- to 10-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 2018. Supply mix is diversified, market priced and delivered pursuant to a number of long-term and short-term primary firm transportation and storage arrangements, including transportation contracts held by some of Gas Utility’s larger customers.
During Fiscal 2017, Gas Utility supplied transportation service to nine electric generation facilities and installed new service to one co-generation facility. Gas Utility continues to seek new residential, commercial, and industrial customers for both firm and interruptible service. In Fiscal 2017, Gas Utility connected approximately 2,000 new commercial and industrial customers. In the residential market sector, Gas Utility added over 12,000 residential heating customers during Fiscal 2017. Approximately 65% of these customers converted to natural gas heating from other energy sources, mainly oil and electricity. New home construction 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 2017.
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UGI Utilities continues to monitor and participate, where appropriate, in rulemaking and individual rate and tariff proceedings before FERC affecting the rates and the terms and conditions under which Gas Utility transports and stores natural gas. Among these proceedings are those arising out of certain FERC orders and/or pipeline filings that relate to (i) the pricing of pipeline services in a competitive energy marketplace, (ii) the flexibility of the terms and conditions of pipeline service tariffs and contracts, and (iii) pipelines’ requests to increase their base rates, or change the terms and conditions of their storage and transportation services.
UGI Utilities’ objective in negotiations with interstate pipeline and natural gas suppliers, and in proceedings before regulatory agencies, is to ensure availability of supply, transportation and storage alternatives to serve market requirements at the lowest cost possible, taking into account the need for security with guaranteed deliverability and reliability of supply. Consistent with that objective, UGI Utilities negotiates the terms of firm transportation capacity on all pipelines serving it, arranges for appropriate storage and peak-shaving resources, negotiates with producers for competitively priced gas purchases and aggressively participates in regulatory proceedings related to transportation rights and costs of service.
Gas Utility Regulation and Rates
Pennsylvania Public Utility Commission Jurisdiction and Gas Utility Rates
Gas Utility is subject to regulation by the PUC as to rates, terms and conditions of service, accounting matters, issuance of securities, contracts and other arrangements with affiliated entities, gas safety 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.
In January 2016, UGI Gas filed a request with the PUC for its first base rate increase in over 21 years. On October 14, 2016, the PUC approved a settlement that was effective October 19, 2016 and resulted in a $27.0 million increase in annual base rate revenues. The settlement permitted UGI Gas to establish new reconcilable surcharges to permit the timely recovery of the costs of universal service programs designed to assist low income customers, and costs associated with a new energy efficiency and conservation program. UGI Gas was also permitted to implement a new Technology and Economic Development Rider to provide additional flexibility in establishing the rates of smaller volume commercial and industrial customers to encourage cost-effective load growth.
On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s base operating revenues for residential, commercial, and industrial customers by $21.7 million annually. On August 31, 2017, the PUC approved a settlement that permitted PNG to increase its annual base distribution rates by $11.3 million, effective October 20, 2017. The settlement also permitted PNG to recover costs associated with a new energy efficiency and conservation program and, similar to UGI Gas, also permitted PNG to implement a new Technology and Economic Development Rider to provide additional flexibility in establishing the rates of smaller volume commercial and industrial customers to encourage cost-effective load growth.
On February 20, 2014, the PUC entered an order approving a Growth Extension Tariff (“GET Gas”) program under which UGI Gas, PNG, and CPG may invest up to $5 million per year for five years, or $75 million in the aggregate for all three utilities, to extend natural gas utility pipelines to provide service to unserved and underserved areas within their respective territories. Under the GET Gas program, customers utilizing the extended pipeline to receive natural gas will pay a monthly surcharge over a 10-year period to cover the cost of the extension. Gas Utility began connecting customers under the GET Gas program in October 2014.
In February 2012, Act 11 of 2012 (“Act 11”) became effective. Among other things, Act 11 authorized the PUC to permit electric and gas distribution companies, between base rate cases and subject to certain conditions, to recover reasonable and prudent costs incurred to repair, improve or replace eligible property through a Distribution System Improvement Charge (“DSIC”) assessed to customers. DSICs are subject to quarterly adjustment, are capped at five percent of total customer charges absent a PUC-granted exception, may only be sought if a base rate case has been filed within the last five years, and are subject to certain earnings tests. In addition, Act 11 requires affected utilities to obtain approval of long-term infrastructure improvement plans (“LTIIP”) from the PUC. Act 11 also authorized electric and gas distribution companies to utilize a fully forecasted future test year when establishing rates in base rate cases before the PUC.
The PUC approved LTIIPs for UGI Gas, PNG, and CPG in 2014, and on June 30, 2016, approved a revised LTIIP for these entities that increases the projected spend on DSIC-eligible property for the 2016-2018 period from approximately $266.3 million to $402.8 million. The PUC also approved DSIC mechanisms for PNG and CPG in September 2014 and July 2015, respectively; both PNG and CPG are collecting revenues under their respective DSICs. On March 31, 2016, PNG and CPG filed petitions with the PUC seeking to increase the cap on their DSIC rate mechanisms from five percent to ten percent of billed distribution revenues.
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On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration of an LTIIP filing in 2018.
On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism effective January 1, 2017. Revenues collected pursuant to the mechanism will be subject to refund and recoupment based on the PUC’s final resolution of certain matters set aside for hearing before an Administrative Law Judge. To commence recovery of revenue under the mechanism, UGI Gas must first place into service a threshold level of DSIC-eligible plant agreed upon in the settlement of its recent base rate case. Achievement of that threshold is likely to occur in Fiscal 2018.
The gas service tariffs for UGI Gas, PNG and CPG contain PGC rates applicable to firm retail rate schedules for customers who do not obtain natural gas supply service from an alternative supplier. These PGC rates permit recovery of substantially all of the prudently incurred costs of natural gas that UGI Gas, PNG and CPG sell to their customers. PGC rates are reviewed and approved annually by the PUC. UGI Gas, PNG and CPG may request quarterly or, under certain conditions, monthly adjustments to reflect the actual cost of gas. Quarterly adjustments become effective on one day’s notice to the PUC and are subject to review during the next annual PGC filing. Each proposed annual PGC rate is required to be filed with the PUC six months prior to its effective date. During this period, the PUC holds hearings to determine whether the proposed rate reflects a least-cost fuel procurement policy consistent with the obligation to provide safe, adequate and reliable service. After completion of these hearings, the PUC issues an order permitting the collection of gas costs at levels that meet such standard. The PGC mechanism also provides for an annual reconciliation and for the payment or collection of interest on over and under collections. UGI Gas, PNG and CPG may assign to and recover from alternative natural gas suppliers the costs of gas supply contracts and transportation capacity acquired to serve the needs of smaller volume customers who elect to receive their natural gas supply service from an alternative supplier.
On April 28, 2017, UGI Gas, PNG and CPG filed the Gas Delivery Enhancement Rider (“GDE”) with the PUC. The GDE provides a tariff mechanism to recover from certain non-choice transportation customers a portion of the costs associated with temporary mobile sources of gas supply and interstate pipeline demand charge enhancements (collectively, “GDE Charges”) that are incurred to achieve least-cost timely solutions to system reinforcement needs or for pipeline integrity management activities. GDE Charges exclude costs that are recovered through existing PGC rate mechanisms as established in each company’s annual 66 Pa.C.S. § 1307(f) PGC proceeding. On August 31, 2017, the PUC entered an order approving the GDE Rider for all three companies.
On June 23, 2016, Act 47 of 2016 was enacted. Act 47 revised the interest rates that are applied to PGC over and under collections, removed the requirement that over and under collections be assessed to customers who leave default service to obtain natural gas from an alternative supplier by way of a so-called migration rider, provided additional assurance of cost recovery for PGC costs, and granted natural gas distribution companies the right to recover the reasonable costs incurred to implement customer choice on a full and current basis through a reconcilable rate mechanism. Gas Utility implemented the interest rate revision and migration rider provisions of Act 47 in December 2016.
FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers
UGI Utilities is subject to Section 4A of the Natural Gas Act, which prohibits the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of natural gas or natural gas transportation subject to the jurisdiction of FERC, and FERC regulations that are designed to promote the transparency, efficiency, and integrity of gas markets. UGI Utilities is also subject to Section 222 of the Federal Power Act, which prohibits the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of electric energy or transmission service subject to the jurisdiction of FERC, and FERC regulations that are designed to promote the transparency, efficiency, and integrity of electric markets.
State Tax Surcharge Clauses
UGI Utilities’ gas service tariffs contain state tax surcharge clauses. The surcharges are recomputed whenever any of the tax rates included in their calculation are changed. These clauses protect UGI Utilities from the effects of increases in most of the Pennsylvania taxes to which it is subject.
Utility Franchises
UGI Utilities, PNG and CPG each hold certificates of public convenience issued by the PUC and certain “grandfather rights” predating the adoption of the Pennsylvania Public Utility Code and its predecessor statutes, which each of them believes are adequate to authorize them to carry on their business in substantially all of the territories to which they now render gas service. Under applicable Pennsylvania law, UGI Utilities, PNG and CPG also have certain rights of eminent domain as well as the right to maintain their facilities in streets and highways in their territories.
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Other Government Regulation
In addition to regulation by the PUC and FERC, Gas Utility is subject to various federal, state and local laws governing environmental matters, occupational health and safety, pipeline safety and other matters. Gas Utility is subject to the requirements of the Resource Conservation and Recovery Act, CERCLA, and comparable state statutes with respect to the release of hazardous substances on property owned or operated by Gas Utility. See Note 15 to Consolidated Financial Statements.
Employees
At September 30, 2017, Gas Utility had more than 1,560 employees.
ELECTRIC UTILITY
Electric Utility supplies electric service to approximately 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania through a system consisting of over 2,200 miles of transmission and distribution lines and 13 substations. At September 30, 2017, UGI Utilities’ electric utility operations had nearly 70 employees.
Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with the PUC. UGI Utilities’ electric utility operations are subject to regulation by the PUC as to rates, terms and conditions of service, accounting matters, issuance of securities, contracts and other arrangements with affiliated entities, electric safety 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, 2021 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, 2021. Under these rules, default service rates for most customers are adjusted quarterly. On August 16, 2017, Electric Utility filed a Petition for Approval of its initial LTIIP with the PUC for the 2018-2022 time period. Electric Utility’s projected annual investment in distribution infrastructure replacement will be approximately $7.6 million beginning in Fiscal 2018, increasing to $8.3 million by the fiscal year ending September 30, 2022.
FERC has jurisdiction over the rates and terms and conditions of service of electric transmission facilities used for wholesale or retail choice transactions. Electric Utility owns electric transmission facilities that are within the control area of PJM and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. PJM is a regional transmission organization that regulates and coordinates generation supply and the wholesale delivery of electricity. Electric Utility receives certain revenues collected by PJM, determined under a formulary rate schedule that is adjusted in June of each year to reflect annual changes in Electric Utility’s electric transmission revenue requirements, when its transmission facilities are used by third parties. FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy. Electric Utility has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates.
Under provisions of the Energy Policy Act of 2005 (“EPACT 2005”), Electric Utility is subject to certain electric reliability standards established by FERC and administered by an Electric Reliability Organization (“ERO”). Electric Utility anticipates that substantially all the costs of complying with the ERO standards will be recoverable through its PJM formulary electric transmission rate schedule.
EPACT 2005 also granted FERC authority to impose substantial civil penalties for the violation of any regulations, orders or provisions under the Federal Power Act and Natural Gas Act and clarified FERC’s authority over certain utility or holding company mergers or acquisitions of electric utilities or electric transmitting utility property valued at $10 million or more.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income and identifiable assets attributable to each of UGI’s reportable business segments, and to the geographic areas in which we operate, for the 2017, 2016 and 2015 fiscal years appears in Note 21 to Consolidated Financial Statements included in Item 8 of this Report and is incorporated herein by reference.
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EMPLOYEES
At September 30, 2017, UGI and its subsidiaries had approximately 13,000 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.
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, and Enterprises (including UGI International). 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, local regulations, 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.
Supplier defaults may have a negative effect on our operating results.
When the Company’s subsidiaries enter into fixed-price sales contracts with customers, they typically enter 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 2017, AmeriGas Propane purchased over 88% of its propane needs from twenty suppliers. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, our earnings could be affected. Additionally, in certain geographic areas, a single supplier may provide more than 50% of AmeriGas Propane’s propane requirements. Disruptions in supply in these geographic areas could also have an adverse impact on our earnings. Our international businesses are similarly dependent upon their suppliers. For example, during Fiscal 2017, UGI International’s business in the United Kingdom purchased over 90% of its propane needs from two suppliers. There is no assurance that our international businesses will be able to continue to acquire sufficient supplies of LPG to meet demand at prices or within time periods that would allow them to remain competitive.
Our ability to grow our businesses will be adversely affected if we are not successful in making acquisitions or integrating the acquisitions we have made.
One of our strategies is to grow through acquisitions in the U.S. and in international markets. We may choose to finance future acquisitions with debt, equity, cash or a combination of the three. We can give no assurances that we will find attractive acquisition candidates in the future, that we will be able to acquire such candidates on economically acceptable terms, that we will be able to finance acquisitions on economically acceptable terms, that any acquisitions will not be dilutive to earnings or that any additional debt incurred to finance an acquisition will not affect our ability to pay dividends.
In addition, the restructuring of the energy markets in the U.S. and internationally, including the privatization of government-owned utilities and the sale of utility-owned assets, is creating opportunities for, and competition from, well-capitalized competitors, which may affect our ability to achieve our business strategy.
To the extent we are successful in making acquisitions, such acquisitions involve a number of risks. These risks include, but are not limited to, the assumption of material liabilities, environmental 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.
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Regulators may not approve the rates we request and existing rates may be challenged, which may adversely affect our results of operations.
In our UGI Utilities segment, 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. Additionally, environmental contamination could result in future legal proceedings. There can be no assurance that our insurance coverage will be adequate to protect us from all material expenses related to pending and future claims or that such levels of insurance would 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.
Increased regulation of GHG emissions, such as propane and methane, could impose significant additional costs on us, our suppliers and our customers. Some states have adopted laws and regulations regulating the emission of GHGs for some industry sectors. For example, the California Environmental Protection Agency established a Cap & Trade program that requires certain covered entities, including propane companies, to purchase allowances to compensate for the GHG emissions created by their business operations. 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, which include certain facilities of our natural gas distribution business. These subject facilities have been required to monitor emissions since January 2011 and to submit detailed annual reports beginning in March 2012. In October 2015, the EPA promulgated the Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (the “Clean Power Plan”), which provides standards and guidelines for reducing existing power plants’ GHG emissions and related pollutants by 2030. However, in October 2017, the EPA announced its proposal to repeal the Clean Power Plan in its entirety on the grounds that it exceeds the EPA’s delegated authority under the Clean Air Act. 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 and energy marketing 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; |
• | longer payment cycles; |
• | local political and economic conditions; |
• | potentially adverse tax consequences, including restrictions on repatriating earnings, potential increases to corporate income taxes 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, and European Union regulatory requirements; |
• | 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 |
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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. |
Changes in data privacy and protection laws and regulations, particularly in Europe, or any failure to comply which such laws and regulations, could adversely affect our business and financial results.
There has been increased public attention regarding the use of personal information and data transfer, accompanied by legislation and regulations intended to strengthen data protection, information security and consumer and personal privacy. The law in these areas continues to develop and the changing nature of privacy laws in the U.S., the European Union and elsewhere could impact our processing of personal and sensitive information of our employees, vendors and customers. The European Union adopted a comprehensive General Data Privacy Regulation (the “GDPR”) in May 2016 that will replace the current EU Data Protection Directive and related country-specific legislation. The GDPR will become fully effective in May 2018.
The GDPR requires companies to satisfy new requirements regarding the handling of personal and sensitive data, including its use, protection and the ability of persons whose data is stored to correct or delete such data about themselves. Failure to comply with GDPR requirements could result in penalties of up to 4% of worldwide revenue. The GDPR and other similar laws and regulations, as well as any associated inquiries or investigations or any other government actions, may be costly to comply with, result in negative publicity, increase our operating costs, require significant management time and attention, and subject us to remedies that may harm our business, including fines or demands or orders that we modify or cease existing business practices.
Expanding our midstream asset business by constructing new facilities subjects us to risks.
We seek to grow our midstream asset business by constructing new pipelines and gathering systems. These construction projects involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. These projects may not be completed on schedule, or at all, or at the anticipated costs. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. We may construct facilities to capture anticipated future growth in production and demand in an area in which anticipated growth and demand does not materialize. As a result, there is the risk that new and expanded facilities may not be able to attract enough customers to achieve our expected investment returns, which could have a material adverse effect on our business, financial condition and results of operations.
Decreases in the demand for our energy products and services because of warmer-than-normal heating season weather or unfavorable weather may adversely affect our results of operations.
Because many of our customers rely on our energy products and services to heat their homes and businesses, our results of operations are adversely affected by warmer-than-normal heating season weather. Weather conditions have a significant impact on the demand for our energy products and services for both heating and agricultural purposes. Accordingly, the volume of our energy products sold is at its highest during the peak heating season of October through March and is directly affected by the severity of the winter weather. For example, historically, approximately 60% to 70% of AmeriGas Partners’ annual retail propane volume, 60% to 70% of the annual retail LPG volume of UGI International’s operations in France, 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.
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.
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
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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 potential to increase revenues may be affected by the decline of the retail propane industry and our ability to retain and grow our customer base.
The retail LPG distribution industry in the U.S. and each of the Western European countries in which we operate is mature and has been declining over the past several years, with no or modest growth in total demand foreseen in the next several years. Accordingly, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability to grow within the LPG industry is dependent on our ability to acquire other retail distributors and to achieve internal growth, which includes expansion of the domestic ACE and National Accounts programs in the U.S., as well as the success of our sales and marketing programs designed to attract and retain customers. A failure to retain and grow our customer base would have an adverse effect on our results.
UGI Utilities’ transmission and distribution systems may not operate as planned, which may increase expenses or decrease UGI Utilities’ revenues and, thus, have an adverse effect on our financial results.
Our ability to manage operational risk with respect to UGI Utilities’ transmission and distribution systems is critical to our financial results. The business also faces several risks, including the breakdown or failure of or damage to equipment or processes (especially due to severe weather or natural disasters), accidents and other factors. Operation of UGI Utilities’ transmission and distribution systems below our expectations may result in lost revenues or increased expenses, including higher maintenance costs.
The risk of terrorism may adversely affect the economy and the price and availability of LPG, other refined fuels and natural gas.
Terrorist attacks and political unrest may adversely impact the price and availability of LPG (including propane), other refined fuels, and natural gas, as well as our results of operations, our ability to raise capital, and our future growth. The impact that the foregoing may have on our industries in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil or natural gas supplies and markets (the sources of LPG), cause price volatility in the cost of propane, fuel oil, and natural gas, and our infrastructure facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to transport LPG and other refined fuels if our means of supply transportation, such as rail or pipeline, become damaged as a result of an attack. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. We have opted to purchase insurance coverage for terrorist acts within our property and casualty insurance programs, but we can give no assurance that our insurance coverage would be adequate to fully compensate us for any losses to our business or property resulting from terrorist acts.
If we are unable to protect our information technology systems against service interruption, misappropriation of data, or breaches of security resulting from cyber security attacks or other events, or we encounter other unforeseen difficulties in the operation of our information technology systems, our operations could be disrupted, our business and reputation may suffer, and our internal controls could be adversely affected.
In the ordinary course of business, we rely on information technology systems, including the Internet and third-party hosted services, to support a variety of business processes and activities and to store sensitive data, including (i) intellectual property, (ii) our proprietary business information and that of our suppliers and business partners, (iii) personally identifiable information of our customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. In addition, we rely on our information technology systems to process financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal, and tax requirements. Despite our security measures, our information technology systems may be vulnerable to attacks by hackers or breached due to employee error, malfeasance, sabotage, or other disruptions. A loss of our information technology systems, or temporary interruptions in the operation of our information technology systems, misappropriation of data, and breaches of security could have a material adverse effect on our business, financial condition, results of operations, and reputation. In addition, a cyber security attack could provide a cyber intruder with the ability to control or alter our pipeline operations. Such an act could result in critical pipeline failures.
Moreover, the efficient execution of the Company’s businesses is dependent upon the proper functioning of its internal systems, such as the information technology systems that support the Company’s underlying 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
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information technology systems. While we have purchased cyber security insurance, there are no assurances that the coverage would be adequate in relation to any incurred losses.
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 but, except in France, is generally more expensive than propane on a Btu equivalent basis for space heating, water heating and cooking. Notwithstanding cost, the convenience and efficiency of electricity make it an attractive energy source for consumers and developers of new homes. 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. Fuel oil is also a major competitor of propane but is currently more expensive than propane as well as a less environmentally attractive energy source. Historically, however, fuel oil has been 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.
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 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 UGI Utilities segment as our “regulated segment,” there are many governmental regulations that have an impact on all of our businesses. Currently, we are subject to extensive and changing international, federal, state, and local safety, health, transportation, tax, and environmental laws and regulations governing the storage, distribution, and transportation of our energy products. Moreover, existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company that may affect our businesses in ways that we cannot predict.
New regulations, or a change in the interpretation of existing regulations, could result in increased expenditures. In addition, for many of our operations, we are required to obtain permits from regulatory authorities and, in some cases, such regulatory permits could subject our operations to additional regulations and standards of conduct. Failure to obtain or comply with these permits or applicable regulations and standards of conduct could result in civil and criminal fines or the cessation of the operations in violation. Governmental regulations and policies in the U.S. and Europe may provide for subsidies or incentives to customers who use alternative fuels instead of carbon fuels. These subsidies and incentives may result in reduced demand for our energy products and services.
We are investigating and remediating contamination at a number of present and former operating sites in the U.S., including former sites where we or our former subsidiaries operated manufactured gas plants. We have also received claims from third parties that allege that we are responsible for costs to clean up properties where we or our former subsidiaries operated a manufactured gas plant or conducted other operations. Costs we incur to remediate sites outside of Pennsylvania cannot currently be recovered in PUC rate proceedings, and insurance may not cover all or even part of these costs. Our actual costs to clean up these sites may exceed our current estimates due to factors beyond our control, such as:
• | the discovery of presently unknown conditions; |
• | changes in environmental laws and regulations; |
• | judicial rejection of our legal defenses to 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
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income.
We also may be unable to timely respond to changes within the energy and utility sectors that may result from regulatory initiatives to further increase competition within our industry. Such regulatory initiatives may create opportunities for additional competitors to enter our markets and, as a result, we may be unable to maintain our revenues or continue to pursue our current business strategy.
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 LPG supply costs. LPG is a commodity, and, as such, its unit price is subject to volatile fluctuations in response to changes in supply or other market conditions. We have no control over these market conditions. Consequently, the unit price of the LPG that our subsidiaries and other marketers purchase can change rapidly over a short period of time. Most of our domestic LPG product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major U.S. storage points such as Mont Belvieu, Texas or Conway, Kansas. Most of our international LPG supply contracts are based on internationally quoted market prices. Because our subsidiaries’ profitability is sensitive to changes in wholesale propane supply costs, it will be adversely affected if we cannot pass on increases in the cost of propane to our customers. Due to competitive pricing in the industry, our subsidiaries may not fully be able to pass on product cost increases to our customers when product costs rise, or when our competitors do not raise their product prices in a timely manner. Finally, market volatility may cause our subsidiaries to sell LPG at less than the price at which they purchased it, which would adversely affect our operating results.
Economic recession, volatility in the stock market and the low interest rate environment may negatively impact our pension liability.
Economic recession, volatility in the stock market and the low interest rate environment have had a significant impact on our pension liability and funded status. Declines in the stock or bond market and valuation of stocks or bonds, combined with continued low interest rates, could further impact our pension liability and funded status and increase the amount of required contributions to our pension plans.
The adoption of financial reform legislation by the United States Congress and related regulations may have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.
Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Act”) in 2010, which contains comprehensive financial reform legislation. Our businesses are subject to Title VII of the Act, which imposes rules aimed at anti-market manipulation, and includes regulation on the over-the-counter derivatives market and entities that participate in that market. The Act requires the Commodity Futures Trading Commission (“CFTC”), the U.S. Securities and Exchange Commission (“SEC”) and other regulators to implement the Act’s provisions. Most rules and regulations required to be issued by the CFTC under the Act have been finalized, but there are some additional rules and regulations that have yet to be adopted. It is possible that the rules and regulations under the Act may increase our cost of using derivative instruments to hedge risks associated with our business or may reduce the availability of such instruments to protect against risks we encounter. While costs imposed directly on us due to regulatory requirements for derivatives under the Act, such as reporting recordkeeping and electing the end-user exception from mandatory clearing, are relatively minor, increased costs may arise from clearing, trade execution, margin, capital, reporting, recordkeeping, compliance and business conduct requirements imposed upon our counterparties to the extent those costs are passed through to us. Position limits also may be imposed that could further limit our ability to hedge risks and may impose compliance and reporting obligations on us. To the extent new rules and regulations impose on our bank counterparties more collateral or margin for individual transactions, our available liquidity also may be adversely affected. Accordingly, our business and operating results may be adversely affected if, as a result of the Act and the rules and regulations promulgated under the Act, we are forced to reduce or modify our current use of derivatives.
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Volatility in credit and capital markets may restrict our ability to grow, increase the likelihood of defaults by our customers and counterparties and adversely affect our operating results.
The volatility in credit and capital markets may create additional risks to our businesses in the future. We are exposed to financial market risk (including refinancing risk) resulting from, among other things, changes in interest rates and conditions in the credit and capital markets. Developments in the credit markets during the past few years increase our possible exposure to the liquidity, default and credit risks of our suppliers and vendors, counterparties associated with derivative financial instruments and our customers. Although we believe that current financial market conditions, if they were to continue for the foreseeable future, will not have a significant impact on our ability to fund our existing operations, such market conditions could restrict our ability to grow through acquisitions, limit the scope of major capital projects if access to credit and capital markets is limited, or adversely affect our operating results.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
With the exception of those matters set forth in Note 15 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.” 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.
2017 Fiscal Year | High | Low | ||||||
4th Quarter | $ | 51.11 | $ | 46.59 | ||||
3rd Quarter | $ | 52.00 | $ | 45.91 | ||||
2nd Quarter | $ | 50.38 | $ | 45.03 | ||||
1st Quarter | $ | 46.66 | $ | 41.79 | ||||
2016 Fiscal Year | High | Low | ||||||
4th Quarter | $ | 48.13 | $ | 43.83 | ||||
3rd Quarter | $ | 45.25 | $ | 39.20 | ||||
2nd Quarter | $ | 40.85 | $ | 31.59 | ||||
1st Quarter | $ | 37.51 | $ | 31.51 | ||||
Dividends
Quarterly dividends per common share on our Common Stock were paid in Fiscal 2017 and Fiscal 2016 as follows:
2017 Fiscal Year | Amount | |||
4th Quarter | $ | 0.2500 | ||
3rd Quarter | $ | 0.2375 | ||
2nd Quarter | $ | 0.2375 | ||
1st Quarter | $ | 0.2375 | ||
2016 Fiscal Year | Amount | |||
4th Quarter | $ | 0.2375 | ||
3rd Quarter | $ | 0.2275 | ||
2nd Quarter | $ | 0.2275 | ||
1st Quarter | $ | 0.2275 | ||
Record Holders
On November 14, 2017, UGI had 6,095 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, 2017.
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, 2017 to July 31, 2017 | 0 | - | 0 | 10.9 million | ||||
August 1, 2017 to August 31, 2017 | 300,000 | $48.61 | 300,000 | 10.6 million | ||||
September 1, 2017 to September 30, 2017 | 0 | - | 0 | 10.6 million | ||||
Total | 300,000 | $48.61 | 300,000 | 10.6 million | ||||
(1) Shares of UGI Corporation Common Stock are repurchased through a share repurchase program announced by the Company on January 30, 2014. The Board of Directors authorized the repurchase of up to 15 million shares of UGI Corporation Common Stock over a four-year period.
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ITEM 6. | SELECTED FINANCIAL DATA |
Year Ended September 30, | ||||||||||||||||||||
(Millions of dollars, except per share amounts) | 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
FOR THE PERIOD: | ||||||||||||||||||||
Income statement data: | ||||||||||||||||||||
Revenues | $ | 6,120.7 | $ | 5,685.7 | $ | 6,691.1 | $ | 8,277.3 | $ | 7,194.7 | ||||||||||
Net income including noncontrolling interests | $ | 523.8 | $ | 488.8 | $ | 414.0 | $ | 532.6 | $ | 427.6 | ||||||||||
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners | (87.2 | ) | (124.1 | ) | (133.0 | ) | (195.4 | ) | (149.5 | ) | ||||||||||
Net income attributable to UGI Corporation | $ | 436.6 | $ | 364.7 | $ | 281.0 | $ | 337.2 | $ | 278.1 | ||||||||||
Earnings per common share attributable to UGI stockholders: | ||||||||||||||||||||
Basic | $ | 2.51 | $ | 2.11 | $ | 1.62 | $ | 1.95 | $ | 1.63 | ||||||||||
Diluted | $ | 2.46 | $ | 2.08 | $ | 1.60 | $ | 1.92 | $ | 1.60 | ||||||||||
Cash dividends declared per common share | $ | 0.975 | $ | 0.930 | $ | 0.890 | $ | 0.791 | $ | 0.737 | ||||||||||
AT PERIOD END: | ||||||||||||||||||||
Balance sheet data: | ||||||||||||||||||||
Total assets | $ | 11,582.2 | $ | 10,847.2 | $ | 10,514.2 | $ | 10,062.7 | $ | 9,972.8 | ||||||||||
Capitalization: | ||||||||||||||||||||
Debt: | ||||||||||||||||||||
Short-term debt: | ||||||||||||||||||||
AmeriGas Propane | $ | 140.0 | $ | 153.2 | $ | 68.1 | $ | 109.0 | $ | 116.9 | ||||||||||
UGI International | 17.9 | 0.5 | 0.6 | 8.0 | 6.5 | |||||||||||||||
Midstream & Marketing | 39.0 | 25.5 | 49.5 | 7.5 | 87.0 | |||||||||||||||
UGI Utilities | 170.0 | 112.5 | 71.7 | 86.3 | 17.5 | |||||||||||||||
Long-term debt (including current maturities): | ||||||||||||||||||||
AmeriGas Propane | 2,572.3 | 2,333.6 | 2,261.9 | 2,266.1 | 2,270.4 | |||||||||||||||
UGI International | 838.8 | 779.6 | 774.2 | 562.8 | 650.3 | |||||||||||||||
UGI Utilities | 751.1 | 671.5 | 619.8 | 639.5 | 639.8 | |||||||||||||||
Other | 9.9 | 10.8 | 11.5 | 12.1 | 12.9 | |||||||||||||||
Total debt | 4,539.0 | 4,087.2 | 3,857.3 | 3,691.3 | 3,801.3 | |||||||||||||||
UGI Corporation stockholders’ equity | 3,163.3 | 2,844.1 | 2,685.2 | 2,659.1 | 2,492.5 | |||||||||||||||
Noncontrolling interests, principally in AmeriGas Partners | 577.6 | 750.9 | 880.4 | 1,004.1 | 1,055.4 | |||||||||||||||
Total capitalization | $ | 8,279.9 | $ | 7,682.2 | $ | 7,422.9 | $ | 7,354.5 | $ | 7,349.2 | ||||||||||
Ratio of capitalization: | ||||||||||||||||||||
Total debt | 54.8 | % | 53.2 | % | 52.0 | % | 50.2 | % | 51.7 | % | ||||||||||
UGI Corporation stockholders’ equity | 38.2 | % | 37.0 | % | 36.2 | % | 36.2 | % | 33.9 | % | ||||||||||
Noncontrolling interests, principally in AmeriGas Partners | 7.0 | % | 9.8 | % | 11.8 | % | 13.6 | % | 14.4 | % | ||||||||||
100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | |||||||||||
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Year Ended September 30, | ||||||||||||||||||||
(Millions of dollars, except per share amounts) | 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
Non-GAAP Reconciliation: | ||||||||||||||||||||
Adjusted net income attributable to UGI Corporation: | ||||||||||||||||||||
Net income attributable to UGI Corporation | $ | 436.6 | $ | 364.7 | $ | 281.0 | $ | 337.2 | $ | 278.1 | ||||||||||
Net (gains) losses on commodity derivative instruments not associated with current-period transactions (net of tax of $31.9, $13.5, $(30.9), $(4.5) and $3.1, respectively) (a) (b) | (51.2 | ) | (29.9 | ) | 53.3 | 6.6 | (4.3 | ) | ||||||||||||
Unrealized losses on foreign currency derivative instruments (net of tax of $(9.9), $0, $0, $0 and $0) (a) | 13.9 | — | — | — | — | |||||||||||||||
Loss on extinguishments of debt (net of tax of $(6.1), $(5.0), $0, $0 and $0, respectively) (a) | 9.6 | 7.9 | — | — | — | |||||||||||||||
Integration and acquisition expenses associated with Finagaz acquired on May 29, 2015 (net of tax of $(13.7), $(10.6), $(7.7), $(2.2) and $0, respectively) (a) | 26.2 | 17.3 | 14.9 | 4.3 | — | |||||||||||||||
Impact from change in French tax rate | (29.0 | ) | — | — | — | — | ||||||||||||||
Costs associated with extinguishment of debt (net of tax of $0, $0, $(5.7), $0 and $0, respectively) (a) (c) | — | — | 4.6 | — | — | |||||||||||||||
Impact of retroactive change in French tax law | — | — | — | 5.7 | — | |||||||||||||||
Integration expenses associated with the retail propane businesses of Energy Transfer Partners, L.P. (“Heritage Propane”) acquired by the Partnership on January 12, 2012 (net of tax of $0, $0, $0, $0 and $(2.8), respectively) (a) | — | — | — | — | 4.4 | |||||||||||||||
Adjusted net income attributable to UGI Corporation (d) | $ | 406.1 | $ | 360.0 | $ | 353.8 | $ | 353.8 | $ | 278.2 | ||||||||||
Adjusted diluted earnings per share: | ||||||||||||||||||||
UGI Corporation earnings per share - diluted | $ | 2.46 | $ | 2.08 | $ | 1.60 | $ | 1.92 | $ | 1.60 | ||||||||||
Net (gains) losses on commodity derivative instruments not associated with current-period transactions (b) | (0.29 | ) | (0.17 | ) | 0.30 | 0.04 | (0.02 | ) | ||||||||||||
Unrealized losses on foreign currency derivative instruments | 0.08 | — | — | — | — | |||||||||||||||
Loss on extinguishments of debt | 0.05 | 0.04 | — | — | — | |||||||||||||||
Integration and acquisition expenses associated with Finagaz acquired on May 29, 2015 | 0.15 | 0.10 | 0.08 | 0.03 | — | |||||||||||||||
Impact from change in French tax rate | (0.16 | ) | — | — | — | — | ||||||||||||||
Costs associated with extinguishment of debt | — | — | 0.03 | — | — | |||||||||||||||
Impact of retroactive change in French tax law | — | — | — | 0.03 | — | |||||||||||||||
Integration expenses associated with the retail propane businesses of Heritage Propane acquired by the Partnership on January 12, 2012 | — | — | — | — | 0.03 | |||||||||||||||
Adjusted diluted earnings per share (d) | $ | 2.29 | $ | 2.05 | $ | 2.01 | $ | 2.02 | $ | 1.61 | ||||||||||
(a) | Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates. |
(b) | Includes the effects of rounding. |
(c) | Costs associated with extinguishment of debt in Fiscal 2015 are included in “Interest expense” on the Consolidated Statements of Income. |
(d) | Management uses "adjusted net income attributable to UGI" and "adjusted diluted earnings per share," both of which are non-GAAP financial measures, when evaluating UGI's overall performance. Adjusted net income attributable to UGI is net income attributable to UGI after excluding net after-tax gains and losses on commodity and certain foreign currency derivative |
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instruments not associated with current-period transactions (principally comprising changes in unrealized gains and losses on such derivative instruments), losses on extinguishments of debt, Finagaz and Heritage Propane integration and acquisition expenses and the impact from changes in French tax rate and tax law.
Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide meaningful information to investors about UGI’s performance because they eliminate the impact of gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions and other significant discrete items that can affect the comparison of period-over-period results.
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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.
Because most of our businesses sell or distribute energy products used in large part for heating purposes, our results are significantly influenced by temperatures in our service territories, particularly during the heating-season months of October through March. As a result, our earnings, after adjusting for the effects of gains and losses on derivative instruments not associated with current period transactions as further discussed below, are significantly higher in our first and second fiscal quarters.
UGI management uses “adjusted net income attributable to UGI Corporation” and “adjusted diluted earnings per share,” both of which are non-GAAP financial measures, when evaluating UGI’s overall performance. Management believes that these non-GAAP measures provide meaningful information to investors. Adjusted net income attributable to UGI Corporation excludes (1) net after-tax gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions and (2) other significant discrete items that management believes affect the comparison of period-over-period results (as such items are further described below). UGI does not designate its commodity and certain foreign currency derivative instruments as hedges under U.S. generally accepted accounting principles (“GAAP”). Volatility in net income attributable to UGI Corporation as determined in accordance with GAAP can occur as a result of gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions. These gains and losses result principally from recording changes in unrealized gains and losses on these derivative instruments. GAAP net income includes after-tax gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions. However, because these derivative instruments economically hedge anticipated future purchases or sales of energy commodities or, in the case of certain foreign currency derivatives, reduce volatility in anticipated future earnings associated with our foreign operations, we expect that such gains and losses will be largely offset by gains or losses on anticipated future energy commodity transactions or mitigate the volatility in anticipated future earnings. For further information, see Note 21 to Consolidated Financial Statements, and “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share” below.
Executive Overview
Net Income Attributable to UGI Corporation by Business Unit (GAAP)
2017 | 2016 | 2015 | |||||||||||||||||||
(Dollars in millions) | Amount | % of Total | Amount | % of Total | Amount | % of Total | |||||||||||||||
AmeriGas Propane | $ | 44.6 | 10.2 | % | $ | 43.2 | 11.8 | % | $ | 61.0 | 21.7 | % | |||||||||
UGI International | 158.6 | 36.3 | % | 111.6 | 30.6 | % | 52.7 | 18.8 | % | ||||||||||||
Midstream & Marketing | 86.9 | 19.9 | % | 87.1 | 23.9 | % | 107.5 | 38.3 | % | ||||||||||||
UGI Utilities | 116.0 | 26.6 | % | 97.4 | 26.7 | % | 121.1 | 43.1 | % | ||||||||||||
Corporate & Other (1) | 30.5 | 7.0 | % | 25.4 | 7.0 | % | (61.3 | ) | (21.9 | )% | |||||||||||
Net income attributable to UGI Corporation | $ | 436.6 | 100.0 | % | $ | 364.7 | 100.0 | % | $ | 281.0 | 100.0 | % | |||||||||
(1) Corporate & Other includes net after-tax gains (losses) on commodity derivative instruments not associated with current-period transactions of $51.2 million, $29.9 million and $(53.3) million in Fiscal 2017, Fiscal 2016 and Fiscal 2015, respectively. Fiscal 2017 also includes $13.9 million of after-tax unrealized losses on certain foreign currency derivative instruments.
Fiscal 2017 Financial Review
For the second year in a row, our domestic business units were faced with challenging operating environments caused by significantly warmer than normal weather. Our geographic diversity typically reduces the risk of extreme weather variations across the United States and our European LPG operations. However in our domestic businesses, Fiscal 2017, much like Fiscal 2016, was unusual in that a substantial portion of the U.S. experienced temperatures based upon heating degree days that were significantly warmer than normal. Although Fiscal 2017 temperatures based upon heating degree days were slightly colder than in Fiscal 2016, temperatures in the critical heating season months of January and February were much warmer than the prior year. Average temperatures at our UGI International operations in Europe were slightly warmer than normal but colder than the very warm temperatures experienced in Fiscal 2016. Notwithstanding the strong headwinds created by this warm weather, UGI achieved record GAAP and adjusted net income attributable to UGI (for further information on adjusted net income and adjusted diluted
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earnings per share, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share” below). This positive outcome was achieved in part due to contributions from recent investments, growth initiatives and the UGI Gas base rate case increase that became effective in October 2016.
As previously mentioned, our UGI International business experienced weather in Fiscal 2017 that was slightly warmer than normal but colder than in Fiscal 2016. Expenses associated with the integration of French LPG retail distributor Finagaz, which we acquired in May 2015, were higher in Fiscal 2017 reflecting substantial progress with our integration activities in our bulk and cylinder businesses. The higher Fiscal 2017 costs associated with these integration activities were offset in large part by the ramping up of expense synergies from these integration activities. A significant portion of the Finagaz integration activities and related integration expenses are now behind us, and we expect to see the continuing synergistic benefits from these integration activities in our future operating results. Although UGI International retail volumes were higher as a result of the colder weather, Fiscal 2017 results at UGI International were negatively affected by the absence of a significant margin parachute experienced in the prior year resulting from rapidly declining LPG commodity prices in Fiscal 2016. UGI International Fiscal 2017 results also reflect a decrease in net deferred income tax liabilities of $29.0 million resulting from a change in the French corporate income tax rate enacted in December 2016 that will become effective in Fiscal 2021.
Our UGI Utilities segment experienced a significant increase in earnings as a result of higher base rates at UGI Gas, organic customer growth and incremental revenues from distribution system improvements through distribution system improvement charges (“DSIC”). As a result, UGI Utilities net income increased nearly 20% in Fiscal 2017.
Midstream & Marketing results were about equal to last year. Fiscal 2017 results benefited from new peaking and LNG contracts, higher allowance for funds used during construction (“AFUDC”) income associated with pipeline projects and the addition of new natural gas marketing customers and volumes. These positive contributions to earnings were offset by lower capacity management revenues, reflecting lower volatility and prices for pipeline capacity, and lower electric generation income resulting principally from lower wholesale price spreads for electricity and lower generation volumes.
Average temperatures in AmeriGas Propane’s service territories for all of Fiscal 2017 were significantly warmer than normal but slightly colder than in Fiscal 2016. However temperatures in the critical heating-season months of January and February were approximately 9% warmer than in Fiscal 2016, impacting retail volumes. The effects of slightly lower retail volumes sold were partially offset by excellent operating expense and propane unit margin management notwithstanding higher and increasing wholesale prices for propane during Fiscal 2017 compared with Fiscal 2016. Growth in the AmeriGas Cylinder Exchange (“ACE”) and National Accounts programs also helped to offset the effects of the lower retail volumes sold.
Strategic Initiatives
During Fiscal 2017, we made significant strategic and operational progress in support of our long-term goals. At our UGI International business, we made substantial progress toward the full integration of the Finagaz cylinder and bulk businesses, with the last core integration activities to be finalized in Fiscal 2018. We will reap the benefits of these integration efforts in Fiscal 2018 and beyond. Our European presence and operational density continued to increase with the completion of a smaller-sized, strategic acquisition with operations in Sweden during Fiscal 2017. Late in Fiscal 2017, we acquired an electricity and natural gas marketing business (“DVEP”), which markets to small and medium enterprises in the Netherlands. In October 2017, we entered the LPG market in northern and central Italy with our acquisition of Total’s retail LPG business in Italy, now known as UniverGas Italia S.r.l. (“UniverGas”). The DVEP acquisition will allow us to leverage our experience in energy marketing and to grow in a highly attractive and profitable market in Europe while our acquisition of UniverGas expands our LPG footprint in Europe.
Our UGI Utilities business continues to grow as demand for natural gas remains strong across both the residential and commercial customer segments and as the price difference between natural gas and oil has expanded in the last fiscal year. Gas Utility continued to execute on its infrastructure replacement and system betterment program with record capital expenditures in Fiscal 2017. In January 2017, PNG filed for an increase in annual base rate revenues and received PUC approval for an increase in base rates of $11.3 million. This base rate increase became effective on October 20, 2017.
Our Midstream & Marketing businesses made significant progress on several key Marcellus Shale projects including the expansion of our LNG liquefaction capacity and the completion of a pipeline construction project that will serve a natural gas fueled, combined cycle power plant located in central Pennsylvania. We began receiving income from this investment in August 2017. We continue to make progress on our PennEast Pipeline project, with FERC expected to approve the project in Fiscal 2018. These projects, along with other smaller midstream projects, are expected to serve the growing demand across the Mid-Atlantic and Northeast regions for abundant, low-cost Marcellus Shale natural gas. In October 2017, Midstream & Marketing enhanced the buildout of its natural gas infrastructure assets with the acquisition of approximately 60 miles of natural gas gathering lines in northern Pennsylvania.
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AmeriGas Partners continued to expand its National Accounts and ACE programs in Fiscal 2017. The Partnership also acquired five retail propane distribution businesses and continued to make meaningful progress in deploying technology to improve the customer experience.
During Fiscal 2017, UGI’s domestic and international businesses continued to make significant investments in technology. In September 2017, UGI Utilities rolled out its new, state-of-the-art customer information system which significantly enhances the customer experience and provides for streamlined processes within the company. We will continue to invest in technology enhancements during Fiscal 2018 and beyond with a number of significant information technology (“IT”) projects scheduled to begin at each of our major business units to improve efficiency and align processes.
Financing Transactions and Liquidity
During Fiscal 2017, AmeriGas Partners completed the refinancing of its long-term debt, which began in Fiscal 2016. These transactions reduced the Partnership’s cost of long-term debt and extended their maturities. UGI Utilities also issued $100 million of long-term debt to provide additional long-term financing of its infrastructure betterment capital program and IT initiatives, and in October 2017, issued a $125 million unsecured term loan to repay revolving credit balances and for general corporate purposes (see Note 5 to Consolidated Financial Statements).
As more fully described below under “Financial Condition and Liquidity” and in Note 15 to Consolidated Financial Statements, on November 7, 2017, we entered into a Standby Equity Commitment Agreement (the “Commitment Agreement”) with AmeriGas Partners pursuant to which UGI has committed to make up to $225 million of capital contributions to the Partnership through July 1, 2019, for consideration comprising AmeriGas Partners Class B Common Units representing limited partner interests in the Partnership. Although the Partnership does not intend to call on this facility at the present time, this commitment by UGI provides balance sheet flexibility to the Partnership to continue its strategic initiatives following two historically warm years.
We believe each of our business units has sufficient liquidity to fund business operations during Fiscal 2018 (see “Financial Condition and Liquidity” below).
Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share
Adjusted Net Income (Loss) Attributable to UGI Corporation by Business Unit (Non-GAAP)
2017 | 2016 | 2015 | |||||||||||||||||||
(Dollars in millions) | Amount | % of Total | Amount | % of Total | Amount | % of Total | |||||||||||||||
AmeriGas Propane | $ | 54.2 | 13.3 | % | $ | 51.1 | 14.2 | % | $ | 61.0 | 17.2 | % | |||||||||
UGI International | 155.8 | 38.4 | % | 128.9 | 35.8 | % | 72.2 | 20.4 | % | ||||||||||||
Midstream & Marketing | 86.9 | 21.4 | % | 87.1 | 24.2 | % | 107.5 | 30.4 | % | ||||||||||||
UGI Utilities | 116.0 | 28.6 | % | 97.4 | 27.1 | % | 121.1 | 34.2 | % | ||||||||||||
Corporate & Other | (6.8 | ) | (1.7 | )% | (4.5 | ) | (1.3 | )% | (8.0 | ) | (2.2 | )% | |||||||||
Net income attributable to UGI Corporation | $ | 406.1 | 100.0 | % | $ | 360.0 | 100.0 | % | $ | 353.8 | 100.0 | % | |||||||||
As previously mentioned, UGI management uses “adjusted net income attributable to UGI Corporation” 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 Corporation is net income attributable to UGI after excluding net after-tax gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (principally comprising changes in unrealized gains and losses), losses on extinguishments of debt, Finagaz integration and acquisition expenses, and the impact on net deferred income taxes from a change in the French tax rate. For further information on the Company’s accounting for commodity and certain foreign currency derivative instruments, see Note 2 and Note 17 to Consolidated Financial Statements.
Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide meaningful information to investors about UGI’s performance because they eliminate the impact of gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions and other significant discrete items that can affect the comparison of period-over-period results.
The following tables reconcile net income attributable to UGI Corporation, the most directly comparable GAAP measure, to adjusted net income attributable to UGI Corporation and reconcile diluted earnings per share, the most comparable GAAP measure,
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to adjusted diluted earnings per share, to reflect the adjustments referred to above for Fiscal 2017, Fiscal 2016 and Fiscal 2015 (amounts in millions, except per share amounts).
Year Ended September 30, 2017 | Total | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Corporate & Other | ||||||||||||||||||
Adjusted net income attributable to UGI Corporation: | ||||||||||||||||||||||||
Net income attributable to UGI Corporation | $ | 436.6 | $ | 44.6 | $ | 158.6 | $ | 86.9 | $ | 116.0 | $ | 30.5 | ||||||||||||
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $31.9) (a) (b) | (51.2 | ) | — | — | — | — | (51.2 | ) | ||||||||||||||||
Unrealized losses on foreign currency derivative instruments (net of tax of $(9.9)) (a) | 13.9 | — | — | — | — | 13.9 | ||||||||||||||||||
Loss on extinguishments of debt (net of tax of $(6.1)) (a) | 9.6 | 9.6 | — | — | — | — | ||||||||||||||||||
Integration expenses associated with Finagaz (net of tax of $(13.7)) (a) | 26.2 | — | 26.2 | — | — | — | ||||||||||||||||||
Impact from change in French tax rate | (29.0 | ) | — | (29.0 | ) | — | — | — | ||||||||||||||||
Adjusted net income (loss) attributable to UGI Corporation | $ | 406.1 | $ | 54.2 | $ | 155.8 | $ | 86.9 | $ | 116.0 | $ | (6.8 | ) | |||||||||||
Adjusted diluted earnings per share: | ||||||||||||||||||||||||
UGI Corporation earnings per share - diluted | $ | 2.46 | $ | 0.25 | $ | 0.89 | $ | 0.49 | $ | 0.66 | $ | 0.17 | ||||||||||||
Net gains on commodity derivative instruments not associated with current-period transactions | (0.29 | ) | — | — | — | — | (0.29 | ) | ||||||||||||||||
Unrealized losses on foreign currency derivative instruments | 0.08 | — | — | — | — | 0.08 | ||||||||||||||||||
Loss on extinguishments of debt | 0.05 | 0.05 | — | — | — | — | ||||||||||||||||||
Integration expenses associated with Finagaz | 0.15 | — | 0.15 | — | — | — | ||||||||||||||||||
Impact from change in French tax rate | (0.16 | ) | — | (0.16 | ) | — | — | — | ||||||||||||||||
Adjusted diluted earnings (loss) per share | $ | 2.29 | $ | 0.30 | $ | 0.88 | $ | 0.49 | $ | 0.66 | $ | (0.04 | ) | |||||||||||
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Year Ended September 30, 2016 | Total | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Corporate & Other | ||||||||||||||||||
Adjusted net income attributable to UGI Corporation: | ||||||||||||||||||||||||
Net income attributable to UGI Corporation | $ | 364.7 | $ | 43.2 | $ | 111.6 | $ | 87.1 | $ | 97.4 | $ | 25.4 | ||||||||||||
Net gains on commodity derivative instruments not associated with current-period transactions (net of tax of $13.5) (a) (b) | (29.9 | ) | — | — | — | — | (29.9 | ) | ||||||||||||||||
Loss on extinguishments of debt (net of tax of $(5.0)) (a) | 7.9 | 7.9 | — | — | — | — | ||||||||||||||||||
Integration expenses associated with Finagaz (net of tax of $(10.6)) (a) | 17.3 | — | 17.3 | — | — | — | ||||||||||||||||||
Adjusted net income (loss) attributable to UGI Corporation | $ | 360.0 | $ | 51.1 | $ | 128.9 | $ | 87.1 | $ | 97.4 | $ | (4.5 | ) | |||||||||||
Adjusted diluted earnings per share: | ||||||||||||||||||||||||
UGI Corporation earnings per share – diluted | $ | 2.08 | $ | 0.25 | $ | 0.64 | $ | 0.50 | $ | 0.55 | $ | 0.14 | ||||||||||||
Net gains on commodity derivative instruments not associated with current-period transactions (b) | (0.17 | ) | — | — | — | — | (0.17 | ) | ||||||||||||||||
Loss on extinguishments of debt | 0.04 | 0.04 | — | — | — | — | ||||||||||||||||||
Integration expenses associated with Finagaz | 0.10 | — | 0.10 | — | — | — | ||||||||||||||||||
Adjusted diluted earnings (loss) per share | $ | 2.05 | $ | 0.29 | $ | 0.74 | $ | 0.50 | $ | 0.55 | $ | (0.03 | ) | |||||||||||
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Year Ended September 30, 2015 | Total | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Corporate & Other | ||||||||||||||||||
Adjusted net income attributable to UGI Corporation: | ||||||||||||||||||||||||
Net income (loss) attributable to UGI Corporation | $ | 281.0 | $ | 61.0 | $ | 52.7 | $ | 107.5 | $ | 121.1 | $ | (61.3 | ) | |||||||||||
Net losses on commodity derivative instruments not associated with current-period transactions (net of tax of $(30.9)) (a) (b) | 53.3 | — | — | — | — | 53.3 | ||||||||||||||||||
Costs associated with extinguishment of debt (net of tax of $(5.7)) (a) (c) | 4.6 | — | 4.6 | — | — | — | ||||||||||||||||||
Integration and acquisition expenses associated with Finagaz (net of tax of $(7.7)) (a) | 14.9 | — | 14.9 | — | — | — | ||||||||||||||||||
Adjusted net income (loss) attributable to UGI Corporation | $ | 353.8 | $ | 61.0 | $ | 72.2 | $ | 107.5 | $ | 121.1 | $ | (8.0 | ) | |||||||||||
Adjusted diluted earnings per share: | ||||||||||||||||||||||||
UGI Corporation earnings (loss) per share - diluted | $ | 1.60 | $ | 0.35 | $ | 0.30 | $ | 0.61 | $ | 0.69 | $ | (0.35 | ) | |||||||||||
Net losses on commodity derivative instruments not associated with current-period transactions (b) | 0.30 | — | — | — | — | 0.30 | ||||||||||||||||||
Costs associated with extinguishment of debt | 0.03 | — | 0.03 | — | — | — | ||||||||||||||||||
Integration and acquisition expenses associated with Finagaz | 0.08 | — | 0.08 | — | — | — | ||||||||||||||||||
Adjusted diluted earnings (loss) per share | $ | 2.01 | $ | 0.35 | $ | 0.41 | $ | 0.61 | $ | 0.69 | $ | (0.05 | ) | |||||||||||
(a) | Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates. |
(b) | Includes the effects of rounding. |
(c) | Costs associated with an extinguishment of debt at Antargaz are included in “Interest expense” on the Consolidated Statements of Income. |
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Results of Operations
The following analyses compare the Company’s results of operations for (1) Fiscal 2017 with Fiscal 2016 and (2) Fiscal 2016 with Fiscal 2015.
Fiscal 2017 Compared with Fiscal 2016
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:
2017 | 2016 | Variance - Favorable (Unfavorable) | |||||||||||||||||||
(Dollars in millions) | Amount | % of Total | Amount | % of Total | Amount | % Change | |||||||||||||||
AmeriGas Propane (a) | $ | 44.6 | 10.2 | % | $ | 43.2 | 11.8 | % | $ | 1.4 | 3.2 | % | |||||||||
UGI International (b)(c) | 158.6 | 36.3 | % | 111.6 | 30.6 | % | 47.0 | 42.1 | % | ||||||||||||
Midstream & Marketing | 86.9 | 19.9 | % | 87.1 | 23.9 | % | (0.2 | ) | (0.2 | )% | |||||||||||
UGI Utilities | 116.0 | 26.6 | % | 97.4 | 26.7 | % | 18.6 | 19.1 | % | ||||||||||||
Corporate & Other (d)(e) | 30.5 | 7.0 | % | 25.4 | 7.0 | % | 5.1 | N.M. | |||||||||||||
Net income attributable to UGI Corporation | $ | 436.6 | 100.0 | % | $ | 364.7 | 100.0 | % | $ | 71.9 | 19.7 | % | |||||||||
(a) | Includes net after-tax losses of $9.6 million and $7.9 million from extinguishments of debt in Fiscal 2017 and Fiscal 2016, respectively (see Note 5 to Consolidated Financial Statements). |
(b) | Fiscal 2017 includes beneficial impact of a $29.0 million adjustment to net deferred income tax liabilities associated with a change in French income tax rate, the release of a $7.6 million valuation allowance against future uses of foreign tax credit carryforwards and an income tax settlement refund of $6.7 million, plus interest, in France (see Note 6 to Consolidated Financial Statements). |
(c) | Includes after-tax integration expenses associated with Finagaz of $26.2 million and $17.3 million in Fiscal 2017 and Fiscal 2016, respectively. |
(d) | Includes net after-tax gains on commodity derivative instruments not associated with current-period transactions of $51.2 million and $29.9 million in Fiscal 2017 and Fiscal 2016, respectively. Fiscal 2017 also includes $13.9 million of after-tax unrealized losses on certain foreign currency derivative instruments. |
(e) | Fiscal 2017 includes a $7.1 million after-tax loss from the impairment of a cost basis investment (see Note 2 to Consolidated Financial Statements). |
N.M. — Variance is not meaningful.
Fiscal 2017 Highlights
• | Fiscal 2017 includes net after-tax gains on commodity derivative instruments not associated with current-period transactions of $51.2 million (equal to $0.29 per diluted share) and net after-tax unrealized losses on certain foreign currency instruments of $13.9 million (equal to $0.08 per diluted share). Fiscal 2016 includes net after-tax gains on commodity derivative instruments not associated with current-period transactions of $29.9 million (equal to $0.17 per diluted share). |
• | Fiscal 2017 and Fiscal 2016 reflect net after-tax integration expenses associated with Finagaz, which decreased net income attributable to UGI by $26.2 million (equal to $0.15 per diluted share) and $17.3 million (equal to $0.10 per diluted share), respectively. |
• | Fiscal 2017 and Fiscal 2016 include after-tax losses on extinguishments of debt at AmeriGas Propane of $9.6 million (equal to $0.05 per diluted share) and $7.9 million (equal to $0.04 per diluted share), respectively. |
• | Fiscal 2017 includes a $29.0 million decrease in net deferred income tax liabilities (equal to $0.16 per diluted share) resulting from a change in the French corporate income tax rate enacted in December 2016 that will become effective in Fiscal 2021. |
• | Average temperatures during Fiscal 2017 were significantly warmer than normal at each of our domestic business units, but colder than in Fiscal 2016. |
• | UGI Utilities’ Fiscal 2017 net income reflects the after-tax impact of an increase in UGI Gas base rates of $11.8 million (equal to $0.07 per diluted share). |
• | UGI International’s Fiscal 2017 retail unit margins were lower reflecting the effects of rising LPG commodity costs compared to the beneficial effects of declining LPG commodity costs in the prior year. |
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• | Fiscal 2017 net income reflects $10.3 million of excess tax benefits (equal to $0.06 per diluted share) resulting from the adoption of new accounting guidance on share-based payments, effective on October 1, 2016. |
• | Fiscal 2017 includes a $7.1 million after-tax loss (equal to $0.04 per diluted share) from an impairment of a cost basis investment. |
• | Although the British pound sterling and the euro during much of Fiscal 2017 were slightly weaker than during Fiscal 2016, the translation effects of these weaker currencies did not have a material impact on year-over-year UGI International net income. |
AmeriGas Propane | 2017 | 2016 | Increase (Decrease) | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 2,453.5 | $ | 2,311.8 | $ | 141.7 | 6.1 | % | |||||||
Total margin (a) | $ | 1,450.6 | $ | 1,447.0 | $ | 3.6 | 0.2 | % | |||||||
Partnership operating and administrative expenses | $ | 915.1 | $ | 928.8 | $ | (13.7 | ) | (1.5 | )% | ||||||
Partnership Adjusted EBITDA (b)(c) | $ | 551.3 | $ | 543.0 | $ | 8.3 | 1.5 | % | |||||||
Operating income (c)(d) | $ | 355.3 | $ | 356.3 | $ | (1.0 | ) | (0.3 | )% | ||||||
Retail gallons sold (millions) | 1,046.9 | 1,065.5 | (18.6 | ) | (1.7 | )% | |||||||||
Degree days – % (warmer) than normal (e) | (13.5 | )% | (15.0 | )% | — | — | |||||||||
(a) | Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2017 and Fiscal 2016 excludes net pre-tax gains of $31.1 million and $66.1 million, respectively, on AmeriGas Propane commodity derivative instruments not associated with current-period transactions. |
(b) | Partnership Adjusted EBITDA should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements). Partnership Adjusted EBITDA in Fiscal 2017 excludes an accrual of $7.5 million associated with a manufactured gas plan (“MGP”) site obtained in a prior year acquisition. |
(c) | Fiscal 2017 operating income includes adjustments to correct previously recorded gains on sales of fixed assets ($8.8 million) and decreased depreciation expense ($1.1 million) relating to certain assets acquired with the Heritage Propane acquisition in 2012, which adjustments reduced Partnership Adjusted EBITDA by $8.8 million and reduced operating income by $7.7 million. Fiscal 2017 operating income also includes adjustments to correct depreciation expense associated with prior periods which increased depreciation expense and reduced operating income by $7.5 million. |
(d) | Operating income reflects operating and administrative expenses of the General Partner. |
(e) | Deviation from average heating degree days for the 30-year period 1981-2010 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 344 Geo regions in the United States, excluding Alaska and Hawaii. |
AmeriGas Propane’s retail gallons sold during Fiscal 2017 decreased 1.7% compared with Fiscal 2016. Average temperatures based upon heating degree days during Fiscal 2017 were significantly warmer than normal but slightly colder than Fiscal 2016. Although average temperatures during Fiscal 2017 were slightly colder than the prior year, the critical heating season months of January and February were approximately 9% warmer than during the same period of Fiscal 2016.
AmeriGas Propane’s retail propane revenues increased $119.0 million during Fiscal 2017 reflecting the effects of higher average retail selling prices ($154.3 million) partially offset by the lower retail volumes sold ($35.3 million). Wholesale propane revenues increased $11.4 million during Fiscal 2017 reflecting the effects of higher average wholesale selling prices ($11.8 million) partially offset by lower wholesale volumes sold ($0.4 million). Average daily wholesale propane commodity prices during Fiscal 2017 at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 50% higher than such prices during Fiscal 2016 when commodity propane prices were at recent historic lows. Other revenues in Fiscal 2017 were slightly higher than in Fiscal 2016. AmeriGas Propane total cost of sales increased $138.1 million principally reflecting the effects on propane cost of sales of higher average propane product costs ($150.1 million) reduced by the effects of the lower propane volumes sold ($13.6 million).
AmeriGas Propane total margin increased $3.6 million in Fiscal 2017 as slightly lower retail propane total margin ($5.7 million) was more than offset by higher non-propane total margin. The slight decrease in retail propane total margin principally reflects the decrease in retail gallons sold partially offset by slightly higher average retail unit margin.
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AmeriGas Propane operating income in Fiscal 2017 was approximately equal to the prior year as lower Partnership operating and administrative expenses ($13.7 million) and the slightly higher total margin ($3.6 million) were offset by a decrease in other operating income ($16.4 million). Partnership operating and administrative expenses in Fiscal 2017 were $13.7 million lower than in Fiscal 2016 reflecting lower uninsured litigation and general insurance expenses ($26.8 million), resulting in large part from the absence of a $15.0 million accrual for a class action lawsuit recorded during the fourth quarter of Fiscal 2016, and lower group medical insurance expenses ($9.8 million). These decreases in Partnership operating and administrative expenses were partially offset by higher vehicle expenses ($7.8 million), higher bad debt expense ($6.5 million), and a $7.5 million environmental accrual associated with a former MGP site obtained in a prior year acquisition. The lower other operating income in Fiscal 2017 reflects, among other things, lower gains on asset sales ($10.3 million), primarily resulting from an $8.8 million adjustment recorded during the first quarter of Fiscal 2017 to correct previously recorded gains on sales of fixed assets, and lower fuel tax credits ($2.8 million). Partnership Adjusted EBITDA increased $8.3 million in Fiscal 2017 principally reflecting lower Fiscal 2017 Partnership operating and administrative costs which, for the calculation of Partnership Adjusted EBITDA exclude the $7.5 million environmental accrual ($21.2 million), and the slightly higher total margin ($3.6 million) offset in part by the previously mentioned lower other operating income ($16.4 million).
During Fiscal 2017, AmeriGas Partners recognized a pre-tax loss of $59.7 million (a $9.6 million after-tax loss attributable to UGI) associated with early extinguishments of debt. During Fiscal 2016, AmeriGas Partners recognized a pre-tax loss of $48.9 million (a $7.9 million after-tax loss attributable to UGI) associated with early extinguishments of debt. For further information on these transactions, see Note 5 to Consolidated Financial Statements.
UGI International | 2017 | 2016 | Increase (Decrease) | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 1,877.5 | $ | 1,868.8 | $ | 8.7 | 0.5 | % | |||||||
Total margin (a) | $ | 942.2 | $ | 965.0 | $ | (22.8 | ) | (2.4 | )% | ||||||
Operating and administrative expenses (b) | $ | 626.2 | $ | 639.7 | $ | (13.5 | ) | (2.1 | )% | ||||||
Operating income (b) | $ | 195.7 | $ | 206.6 | $ | (10.9 | ) | (5.3 | )% | ||||||
Income before income taxes (b)(c) | $ | 175.0 | $ | 182.0 | $ | (7.0 | ) | (3.8 | )% | ||||||
Retail gallons sold (millions) (d) | 827.9 | 820.5 | 7.4 | 0.9 | % | ||||||||||
UGI International degree days – % (warmer) than normal (e) | (4.5 | )% | (12.9 | )% | — | — | |||||||||
(a) | Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2017 and Fiscal 2016 excludes net pre-tax gains of $19.0 million and $31.8 million, respectively, on UGI International commodity derivative instruments not associated with current-period transactions. |
(b) | Includes Finagaz integration expenses in Fiscal 2017 and Fiscal 2016 of $39.9 million and $27.9 million, respectively. |
(c) | Fiscal 2017 excludes net pre-tax unrealized losses on certain foreign currency derivative contracts of $23.8 million. |
(d) | Retail gallons sold in Fiscal 2017 reflect a 30.7 million decline in autogas volumes principally as a result of exiting the low-margin autogas business in Poland during Fiscal 2016. Retail gallons sold in Fiscal 2016 exclude retail gallons from operations in China, which were sold in March 2016. |
(e) | Deviation from average heating degree days for the 30-year period 1981-2010 at locations in our UGI International service territories. |
Average temperatures during Fiscal 2017 at UGI International were approximately 4.5% warmer than normal but 9.7% colder than Fiscal 2016. Total retail gallons sold during Fiscal 2017 were slightly higher as the beneficial volume effects of the colder weather were substantially offset by a 30.7 million gallon decline in autogas volumes, principally as a result of exiting the low-margin, high-volume autogas business in Poland during Fiscal 2016, and lower crop-drying volumes as a result of a dry Fiscal 2017 crop season in France. During Fiscal 2017, average wholesale commodity prices for propane and butane in northwest Europe were approximately 34% and 29%, respectively, higher than in Fiscal 2016.
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 and, to a much lesser extent, the British pound sterling. Although the British pound sterling and the euro during much of Fiscal 2017 were slightly weaker than during Fiscal 2016, the translation effects of these currencies did not negatively impact UGI International net income due to gains on foreign currency exchange contracts used to hedge a portion of U.S. dollar purchases of LPG.
UGI International revenues increased $8.7 million during Fiscal 2017 as higher average bulk and cylinder LPG selling prices and the effects of the colder weather on bulk sales were substantially offset by the translation impact on revenues of the weaker British
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pound sterling and euro, the effects of exiting the low-margin autogas business in Poland and lower Fiscal 2017 wholesale sales. UGI International cost of sales increased $31.5 million during Fiscal 2017 as the effects on cost of sales from the higher average LPG commodity costs and increase in bulk sales were partially offset by the translation impact from the weaker British pound sterling and the euro, the effects of the lower volumes associated with exiting the autogas business in Poland, and the effects of the lower wholesale sales.
UGI International total margin decreased $22.8 million primarily reflecting (1) the translation effects of the weaker British pound sterling and euro; (2) slightly lower average retail bulk and cylinder LPG unit margins; and (3) the absence of margin from the autogas business in Poland. The slightly lower average retail bulk and cylinder LPG unit margins principally reflect the negative effects on current-year period unit margins of higher LPG commodity costs and the beneficial effects on prior-year unit margins of declining LPG wholesale commodity costs. These decreases in unit margin were partially offset by the increase in bulk sales resulting from the colder weather.
The $10.9 million decrease in Fiscal 2017 UGI International operating income principally reflects the previously mentioned $22.8 million decrease in total margin and a $5.0 million increase in depreciation and amortization partially offset by a $13.5 million decrease in operating and administrative expenses and a decrease in other operating expense. The decrease in operating and administrative expenses principally reflects lower operating and administrative costs in France resulting from expense synergies associated with the Finagaz integration and, to a much lesser extent, the translation effects of the weaker euro and British pound sterling offset, in part, by higher incremental Finagaz integration expenses. Operating and administrative expenses include $39.9 million and $27.9 million of Finagaz integration expenses in Fiscal 2017 and Fiscal 2016, respectively. The decrease in other operating expense reflects, in large part, the absence of a $5.5 million loss recorded during Fiscal 2016 associated with interest rate hedge ineffectiveness. UGI International income before income taxes decreased $7.0 million principally reflecting the previously mentioned $10.9 million decrease in UGI International operating income offset by slightly lower interest expense due in large part to a lower Fiscal 2017 average interest rate on UGI France SAS’s €600 million Senior Facilities Agreement term loan.
Midstream & Marketing | 2017 | 2016 | Increase (Decrease) | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 1,121.2 | $ | 866.6 | $ | 254.6 | 29.4 | % | |||||||
Total margin (a) | $ | 264.5 | $ | 264.4 | $ | 0.1 | — | % | |||||||
Operating and administrative expenses | $ | 95.6 | $ | 90.9 | $ | 4.7 | 5.2 | % | |||||||
Operating income | $ | 139.2 | $ | 146.7 | $ | (7.5 | ) | (5.1 | )% | ||||||
Income before income taxes | $ | 141.4 | $ | 144.6 | $ | (3.2 | ) | (2.2 | )% | ||||||
(a) | Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2017 and Fiscal 2016 excludes net pre-tax gains (losses) of $55.7 and $(6.3) million, respectively, on commodity derivative instruments not associated with current-period transactions. |
Temperatures across Midstream & Marketing’s energy marketing territory were 14.5% warmer than normal but 2.2% colder than in the prior year. Midstream & Marketing Fiscal 2017 revenues were $254.6 million higher than in Fiscal 2016 principally reflecting higher natural gas revenues ($262.9 million) and, to a much lesser extent, higher peaking revenues ($15.5 million). The increase in natural gas revenues principally reflects higher average natural gas prices, higher natural gas volumes associated with customer growth, and the effects of the slightly colder weather, while the increase in peaking revenues reflects an increase in the number of peaking contracts. These increases in revenues were partially offset principally by lower capacity management and electric generation revenues. Midstream & Marketing cost of sales was $856.7 million in Fiscal 2017 compared to $602.2 million in Fiscal 2016, an increase of $254.5 million, principally reflecting higher natural gas cost of sales primarily a result of the higher natural gas volumes and prices.
Midstream & Marketing total margin in Fiscal 2017 was about equal to the prior year as higher peaking total margin ($15.0 million), higher natural gas gathering total margin ($4.1 million), and higher natural gas total margin ($3.3 million) were offset primarily by a decrease in total margin from capacity management ($10.6 million), electricity generation ($6.3 million), and storage services ($3.0 million). The increase in peaking total margin reflects an increase in the number of contracts while the higher natural gas gathering and natural gas total margin reflects higher activity. The decline in capacity management margin reflects higher fixed demand charges associated with higher capacity contract commitments partially offset by slightly higher prices for pipeline capacity during the Fiscal 2017 heating season. The lower electricity generation margin reflects lower electricity price spreads, slightly lower electricity generation volumes, and lower capacity revenue.
Midstream & Marketing operating income and income before income taxes during Fiscal 2017 decreased $7.5 million and $3.2 million, respectively. The decrease in operating income principally reflects higher depreciation expense ($4.8 million) and an
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increase in operating and administrative expenses ($4.7 million). These decreases were partially offset by a $1.9 million increase in other operating income, primarily higher AFUDC associated with pipeline capital expenditures. The $4.7 million increase in operating and administrative expenses reflects higher wage and benefits expense partially offset by lower Conemaugh and Hunlock electricity generating station operating and maintenance expenses, while the $4.8 million increase in depreciation expense principally reflects incremental depreciation from the expansion of our natural gas pipeline and peaking assets. The decrease in income before income taxes in Fiscal 2017 reflects the lower operating income partially offset by $4.3 million from our PennEast pipeline equity investment reflecting AFUDC income.
UGI Utilities | 2017 | 2016 | Increase (Decrease) | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 887.6 | $ | 768.5 | $ | 119.1 | 15.5 | % | |||||||
Total margin (a) | $ | 515.6 | $ | 473.9 | $ | 41.7 | 8.8 | % | |||||||
Operating and administrative expenses | $ | 212.4 | $ | 192.7 | $ | 19.7 | 10.2 | % | |||||||
Operating income | $ | 228.3 | $ | 200.9 | $ | 27.4 | 13.6 | % | |||||||
Income before income taxes | $ | 188.1 | $ | 163.3 | $ | 24.8 | 15.2 | % | |||||||
Gas Utility system throughput – billions of cubic feet (“bcf”) | |||||||||||||||
Core market | 70.4 | 66.2 | 4.2 | 6.3 | % | ||||||||||
Total | 243.1 | 212.4 | 30.7 | 14.5 | % | ||||||||||
Electric Utility distribution sales - millions of kilowatt hours (“gwh”) | 950.6 | 961.6 | (11.0 | ) | (1.1 | )% | |||||||||
Gas Utility degree days – % (warmer) than normal (b) | (11.1 | )% | (13.6 | )% | — | — | |||||||||
(a) | Total margin represents total revenues less total cost of sales and Electric Utility gross receipts taxes, of $4.7 million and $4.8 million during Fiscal 2017 and Fiscal 2016, respectively. Gross receipt taxes are included in “Utility taxes other than income taxes” on the Consolidated Statements of Income. |
(b) | Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory. |
Temperatures in Gas Utility’s service territory during Fiscal 2017 were 11.1% warmer than normal but 2.6% colder than during Fiscal 2016. Gas Utility core market volumes increased 4.2 bcf (6.3%) principally reflecting the effects of the slightly colder Fiscal 2017 weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 30.7 bcf reflecting significantly higher large firm delivery service volumes principally associated with service to a new natural gas-fired generation facility and the higher core market volumes. 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 others. These increases were partially offset by lower interruptible delivery service volumes. Electric Utility kilowatt-hour sales were 1.1% lower than in the prior year, principally reflecting the impact on air-conditioning sales from cooler summer temperatures.
UGI Utilities Fiscal 2017 revenues increased $119.1 million reflecting a $121.7 million increase in Gas Utility revenues partially offset by slightly lower Electric Utility revenues. The higher Gas Utility revenues principally reflect an increase in core market revenues ($85.1 million), higher large firm delivery service revenues ($14.3 million) and higher off-system sales revenues ($25.0 million). The $85.1 million increase in Gas Utility core market revenues reflects higher average retail core market PGC rates ($37.0 million), the effects of the higher core market throughput ($28.0 million) and the increase in UGI Gas base rates effective October 19, 2016 ($20.1 million). The decrease in Electric Utility revenues principally reflects the lower Electric Utility volumes ($1.8 million), slightly lower average default service (“DS”) rates ($0.5 million) and lower transmission revenue ($0.4 million). Because Gas Utility and Electric Utility are subject to reconcilable PGC and DS recovery mechanisms, increases or decreases in the actual cost of gas or electricity associated with customers who purchase their gas or electricity from UGI Utilities impact revenues and cost of sales but have no direct effect on retail core-market margin (see Note 8 to Consolidated Financial Statements for a discussion of these recovery mechanisms). UGI Utilities cost of sales was $367.3 million in Fiscal 2017 compared with $289.8 million in Fiscal 2016, principally reflecting higher average retail core market PGC rates ($37.0 million), the higher Gas Utility retail core-market volumes ($14.0 million) and higher cost of sales associated with Gas Utility off-system sales ($25.0 million). The higher Gas Utility cost of sales is partially offset by a decrease in Electric Utility cost of sales of $1.5 million reflecting the lower volumes sold and the slightly lower DS rates.
UGI Utilities total margin increased $41.7 million principally reflecting higher total margin from Gas Utility core market customers ($32.7 million) and higher large firm delivery service total margin ($11.4 million) partially offset by lower other margin. The
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increase in Gas Utility core market margin principally reflects the increase in UGI Gas base rates effective October 19, 2016 ($20.1 million) and the higher core market throughput ($12.6 million). Electric Utility total margin decreased $0.8 million principally reflecting the lower volume sales and lower transmission revenue.
UGI Utilities Fiscal 2017 operating income increased $27.4 million, principally reflecting the increase in total margin ($41.7 million) and higher other operating income, net ($10.3 million). These increases in operating income were reduced by higher operating and administrative expenses ($19.7 million) and higher depreciation and amortization expense ($5.0 million) associated with increased capital expenditure activity. The higher other operating income, net, reflects a $5.8 million environmental insurance settlement, the absence of a charge recorded in the prior year related to environmental matters ($2.5 million), and lower interest on PGC overcollections ($1.6 million). The increase in UGI Utilities operating and administrative expenses in the current year reflects higher pension and employee benefits expenses ($7.0 million), higher customer accounts expense ($4.2 million) and higher regulatory asset amortization expense related to environmental remediation expenses ($1.9 million). The increase in Fiscal 2017 operating and administrative expenses also reflects the fact that Fiscal 2016 expenses were reduced by the capitalization of $5.4 million of development stage IT project costs that had been expensed in prior periods but qualified for capitalization during Fiscal 2016. UGI Utilities income before income taxes increased $24.8 million reflecting the increase in UGI Utilities operating income ($27.4 million) partially offset by higher interest expense.
Interest Expense. Our consolidated interest expense during Fiscal 2017 was $223.5 million, $5.4 million lower than the $228.9 million of interest expense recorded during Fiscal 2016. The lower interest expense principally reflects lower average interest rates on long-term debt at UGI International and AmeriGas Propane. These decreases were partially offset by the effects of higher long-term debt outstanding at AmeriGas Propane and UGI Utilities.
Income Taxes. Our effective income tax rate as a percentage of pre-tax income (excluding the effects on such rate of pre-tax income associated with non-controlling interests not subject to federal income taxes) was 28.9% in Fiscal 2017 compared to 37.8% in Fiscal 2016. The lower effective tax rate in Fiscal 2017 principally reflects (1) a decrease in net deferred tax liabilities in France as a result of the reduction in the French statutory rate from 34.43% to 28.92% effective in Fiscal 2021 which reduced consolidated income tax expense during Fiscal 2017 by $29.0 million; (2) the impact of excess tax benefits of $10.3 million resulting from the adoption of new accounting guidance on share-based payments effective October 1, 2016 (see Note 3 to Consolidated Financial Statements); (3) the release of a $7.6 million valuation allowance against future uses of foreign tax credit carryforwards; and (4) an income tax settlement refund of $6.7 million, plus interest, in France.
Fiscal 2016 Compared with Fiscal 2015
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:
2016 | 2015 | Variance - Favorable (Unfavorable) | |||||||||||||||||||
(Dollars in millions) | Amount | % of Total | Amount | % of Total | Amount | % Change | |||||||||||||||
AmeriGas Propane (a) | $ | 43.2 | 11.8 | % | $ | 61.0 | 21.7 | % | $ | (17.8 | ) | (29.2 | )% | ||||||||
UGI International (b) | 111.6 | 30.6 | % | 52.7 | 18.8 | % | 58.9 | 111.8 | % | ||||||||||||
UGI Utilities | 97.4 | 26.7 | % | 121.1 | 43.1 | % | (23.7 | ) | (19.6 | )% | |||||||||||
Midstream & Marketing | 87.1 | 23.9 | % | 107.5 | 38.3 | % | (20.4 | ) | (19.0 | )% | |||||||||||
Corporate & Other (c) | 25.4 | 7.0 | % | (61.3 | ) | (21.9 | )% | 86.7 | N.M. | ||||||||||||
Net income attributable to UGI Corporation | $ | 364.7 | 100.0 | % | $ | 281.0 | 100.0 | % | $ | 83.7 | 29.8 | % | |||||||||
(a) | Fiscal 2016 includes an after-tax loss of $7.9 million associated with extinguishments of debt. |
(b) | Fiscal 2016 includes after-tax integration expenses associated with Finagaz of $17.3 million. Fiscal 2015 includes net after-tax costs of $4.6 million associated with an extinguishment of debt at Antargaz and after-tax integration and acquisition expenses associated with Finagaz of $14.9 million. |
(c) | Includes net after-tax gains (losses) on commodity derivative instruments not associated with current-period transactions of $29.9 million and $(53.3) million in Fiscal 2016 and Fiscal 2015, respectively. |
N.M. — Variance is not meaningful.
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Fiscal 2016 Highlights
• | Fiscal 2016 includes net after-tax gains on commodity derivative instruments not associated with current-period transactions of $29.9 million (equal to $0.17 per diluted share). Fiscal 2015 includes net after-tax losses on commodity derivative instruments not associated with current-period transactions of $53.3 million (equal to $0.30 per diluted share). |
• | Fiscal 2016 and Fiscal 2015 reflect net after-tax integration expenses associated with Finagaz, which decreased net income attributable to UGI by $17.3 million (equal to $0.10 per diluted share) and $14.9 million (equal to $0.08 per diluted share), respectively. |
• | Fiscal 2016 and Fiscal 2015 include after-tax losses on extinguishments of debt of $7.9 million (equal to $0.04 per diluted share) and $4.6 million (equal to $0.03 per diluted share), respectively. |
• | Fiscal 2016 results at each of our business units was negatively impacted by temperatures that were significantly warmer than normal and, with respect to UGI’s domestic business units, significantly warmer than in Fiscal 2015. |
• | UGI International Fiscal 2016 net income (excluding the impacts of integration and acquisition expenses associated with Finagaz in Fiscal 2016 and Fiscal 2015 and the impact of costs associated with an extinguishment of debt in Fiscal 2015) improved significantly reflecting in large part the full-year operations of Finagaz, which was acquired in May 2015, and higher average unit margins. |
• | Midstream & Marketing Fiscal 2016 results were negatively affected by the warmer weather in the Mid-Atlantic region of the U.S. and the impact of lower prices for capacity management as the milder weather reduced capacity spreads between Marcellus and non-Marcellus locations. These decreases in margin were partially offset by slightly higher income from our natural gas gathering and peaking contracts. |
• | Notwithstanding the significant impact on AmeriGas Propane of the significantly warmer Fiscal 2016 heating-season weather, the Partnership benefited from a $24.5 million reduction in operating and administrative costs as a result of successful execution of its warm weather plan. |
• | Although the euro and British pound sterling were slightly weaker during Fiscal 2016, the effects of the weaker currencies did not have a material impact on UGI International net income, and did not negatively impact year-over-year net income due to higher gains on foreign currency exchange contracts used to hedge a portion of U.S. dollar purchases of LPG. |
• | Notwithstanding a decline in total margin as a result of significantly warmer weather, UGI Utilities benefited from lower operating and administrative expenses in Fiscal 2016. |
AmeriGas Propane | 2016 | 2015 | Decrease | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 2,311.8 | $ | 2,885.3 | $ | (573.5 | ) | (19.9 | )% | ||||||
Total margin (a) | $ | 1,447.0 | $ | 1,545.3 | $ | (98.3 | ) | (6.4 | )% | ||||||
Partnership operating and administrative expenses | $ | 928.8 | $ | 953.3 | $ | (24.5 | ) | (2.6 | )% | ||||||
Partnership Adjusted EBITDA (b) | $ | 543.0 | $ | 619.2 | $ | (76.2 | ) | (12.3 | )% | ||||||
Operating income | $ | 356.3 | $ | 427.6 | $ | (71.3 | ) | (16.7 | )% | ||||||
Retail gallons sold (millions) | 1,065.5 | 1,184.3 | (118.8 | ) | (10.0 | )% | |||||||||
Degree days – % (warmer) than normal (c) | (15.0 | )% | (2.9 | )% | — | — | |||||||||
(a) | Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2016 and Fiscal 2015 excludes net pre-tax gains (losses) of $66.1 million and $(47.8) million, respectively, on commodity derivative instruments not associated with current-period transactions. |
(b) | Partnership Adjusted EBITDA should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements). |
(c) | Deviation from average heating degree days for the 30-year period 1981-2010 based upon national weather statistics provided by NOAA for 344 Geo regions in the United States, excluding Alaska and Hawaii. |
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AmeriGas Propane’s retail gallons sold during Fiscal 2016 decreased 10.0% compared with Fiscal 2015. The decline in retail gallons sold principally reflects average temperatures based upon heating degree days that were 15.0% warmer than normal and 12.5% warmer than in Fiscal 2015.
Retail propane revenues decreased $546.9 million during Fiscal 2016 reflecting lower average retail selling prices ($289.0 million), principally the result of lower propane product costs, and the effects of the lower retail volumes sold ($257.9 million). Wholesale propane revenues decreased $12.4 million during Fiscal 2016 reflecting the effects of lower wholesale selling prices ($8.8 million) and lower wholesale volumes sold ($3.6 million). Average daily wholesale propane commodity prices during Fiscal 2016 at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 18% lower than such prices during Fiscal 2015. Other revenues in Fiscal 2016 were $14.2 million lower than in the prior year principally reflecting lower fee income. Total cost of sales decreased $475.2 million during Fiscal 2016 principally reflecting the effects on propane cost of sales of the significantly lower average propane product costs ($342.2 million) and the effects of the lower retail and wholesale volumes sold ($125.2 million).
AmeriGas Propane total margin decreased $98.3 million in Fiscal 2016 principally reflecting lower retail propane total margin ($91.9 million) and, to a much lesser extent, lower margin from ancillary sales and services. The decrease in retail propane total margin largely reflects the previously mentioned decline in retail gallons sold partially offset by higher average propane retail unit margin principally resulting from the benefits of declining wholesale propane commodity prices.
Partnership Adjusted EBITDA in Fiscal 2016 decreased $76.2 million principally reflecting the lower total margin of $98.3 million partially offset by lower Partnership operating and administrative expenses ($24.5 million). The decrease in operating and administrative expenses reflects, among other things, lower vehicle fuel ($13.4 million), employee compensation and benefits ($21.7 million), and uncollectible accounts ($4.6 million) expenses. Partially offsetting these decreases in operating and administrative expenses were higher expenses associated with uninsured litigation matters ($17.9 million). AmeriGas Propane operating income decreased $71.3 million in Fiscal 2016 principally reflecting the lower Partnership Adjusted EBITDA ($76.2 million) partially offset by slightly lower depreciation expense.
UGI International | 2016 | 2015 | Increase | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 1,868.8 | $ | 1,808.5 | $ | 60.3 | 3.3 | % | |||||||
Total margin (a) | $ | 965.0 | $ | 688.5 | $ | 276.5 | 40.2 | % | |||||||
Operating and administrative expenses (b) | $ | 639.7 | $ | 493.7 | $ | 146.0 | 29.6 | % | |||||||
Operating income | $ | 206.6 | $ | 112.8 | $ | 93.8 | 83.2 | % | |||||||
Income before income taxes (c) | $ | 182.0 | $ | 76.4 | $ | 105.6 | 138.2 | % | |||||||
Retail gallons sold (millions) (d) | 820.5 | 697.0 | 123.5 | 17.7 | % | ||||||||||
UGI International degree days - % (warmer) than normal (e) | (12.9 | )% | (11.2 | )% | — | — | |||||||||
(a) | Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2016 and Fiscal 2015 excludes net pre-tax gains (losses) of $31.8 million and $(28.4) million on UGI International’s commodity derivative instruments not associated with current-period transactions, respectively. |
(b) | Includes Finagaz integration and acquisition-related expenses in Fiscal 2016 and Fiscal 2015 of $27.9 million and $22.6 million, respectively. |
(c) | Fiscal 2015 income before income taxes is net of $10.3 million of costs associated with an extinguishment of debt at Antargaz which are reflected in interest expense. |
(d) | Excludes retail gallons from operations in China, which was sold in March 2016. |
(e) | Deviation from average heating degree days for the 30-year period 1981-2010 at locations in our UGI International service territories. |
UGI International’s Fiscal 2016 results include the full-year results of Finagaz, which was acquired on May 29, 2015. The acquisition of Finagaz nearly doubled our retail distribution business in France and is a significant contributor to the variances in the table above.
Based upon heating degree day data, temperatures during Fiscal 2016 were significantly warmer than normal and slightly warmer than in Fiscal 2015. Total retail gallons sold during Fiscal 2016 were significantly higher, notwithstanding the warmer weather, principally reflecting incremental retail LPG gallons associated with Finagaz and, to a much lesser extent, retail gallons associated
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with small-scale acquisitions at Flaga GmbH (“Flaga”) and AvantiGas Limited (“AvantiGas”). Partially offsetting these increases was the impact on retail volumes of exiting the low-margin autogas business in Poland (69.4 million gallons). During Fiscal 2016, average wholesale commodity prices for both propane and butane in northwest Europe were approximately 20% lower than during Fiscal 2015. Much of the lower wholesale commodity cost occurred during the early part of Fiscal 2016.
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 and, to a much lesser extent, the British pound sterling. During Fiscal 2016 and Fiscal 2015, the average un-weighted euro-to-dollar translation rates were approximately $1.11 and $1.15, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.42 and $1.55, respectively. Although the euro and the British pound sterling were weaker during Fiscal 2016 and affect the comparisons of amounts in the table above, these weaker currencies did not negatively impact UGI International net income due to higher gains on foreign currency exchange contracts used to hedge a portion of U.S. dollar purchases of LPG.
UGI International revenues increased $60.3 million during Fiscal 2016 principally reflecting incremental revenues from Finagaz and, to a much lesser extent, incremental revenues associated with small-scale acquisitions at Flaga and AvantiGas. These increases in revenues were substantially offset by lower average LPG selling prices at each of our legacy European LPG businesses and, to a lesser extent, the impact of exiting the low-margin autogas business in Poland and the effects of the weaker euro and the British pound sterling. The lower average LPG sales prices in Fiscal 2016 resulted from lower average LPG wholesale commodity prices. UGI International cost of sales decreased $216.2 million during Fiscal 2016 principally reflecting the effects of lower average LPG wholesale commodity prices and, to a much lesser extent, the absence of certain low-margin autogas volumes in Poland, the effects of the weaker euro and the British pound sterling, and higher gains from foreign currency exchange contracts used to hedge a portion of U.S. dollar purchases of LPG. These decreases in cost of sales were partially offset by incremental cost of sales associated with Finagaz.
UGI International total margin increased $276.5 million primarily reflecting incremental local-currency margin from the full-year results of Finagaz and, to a much lesser extent, higher average unit margins and the impact of the small-scale acquisitions at Flaga and AvantiGas. The higher average unit margins at our legacy UGI France and Flaga businesses reflect the benefits of declining LPG wholesale commodity costs and effective margin management. The impact of the slightly higher local currency total margin was partially offset by the effects on such margin of the weaker euro and the British pound sterling.
The $93.8 million increase in UGI International operating income principally reflects the previously mentioned $276.5 million increase in total margin partially offset by a $146.0 million increase in operating and administrative expenses, a $25.5 million increase in depreciation and amortization expense, and, to a much lesser extent, lower other operating income. The higher operating and administrative expenses and depreciation and amortization expense primarily reflects incremental expenses associated with Finagaz and, to a much lesser extent, small-scale acquisitions at Flaga and AvantiGas partially offset by the translation effects of the weaker euro and British pound sterling. Operating and administrative costs include $27.9 million and $22.6 million of Finagaz integration and acquisition-related expenses in Fiscal 2016 and Fiscal 2015, respectively. UGI International income before income taxes increased $105.6 million principally reflecting the previously mentioned $93.8 million increase in UGI International operating income and the absence of $10.3 million in costs recorded in the prior year associated with an extinguishment of debt at Antargaz which are reflected in interest expense. Excluding these costs, UGI International interest expense in Fiscal 2016 was slightly lower as higher average long-term debt outstanding at UGI France resulting from the acquisition of Finagaz was more than offset by lower average interest rates on UGI International’s long-term debt and the translation effects of the weaker euro.
Midstream & Marketing | 2016 | 2015 | Decrease | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 866.6 | $ | 1,163.6 | $ | (297.0 | ) | (25.5 | )% | ||||||
Total margin (a) | $ | 264.4 | $ | 309.0 | $ | (44.6 | ) | (14.4 | )% | ||||||
Operating and administrative expenses | $ | 90.9 | $ | 98.6 | $ | (7.7 | ) | (7.8 | )% | ||||||
Operating income | $ | 146.7 | $ | 182.6 | $ | (35.9 | ) | (19.7 | )% | ||||||
Income before income taxes | $ | 144.6 | $ | 180.5 | $ | (35.9 | ) | (19.9 | )% | ||||||
(a) | Total margin represents total revenues less total cost of sales. Amounts exclude net pre-tax losses on commodity derivative instruments not associated with current-period transactions of $6.3 million and $42.9 million during Fiscal 2016 and Fiscal 2015, respectively. |
Midstream & Marketing’s Fiscal 2016 results were negatively impacted by significantly warmer weather in its principal Mid-Atlantic and Northeast U.S. service territory. Temperatures across Midstream & Marketing’s energy marketing territory were approximately 17.8% warmer than normal in Fiscal 2016 compared to temperatures that were 4.5% colder than normal in Fiscal
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2015. Midstream & Marketing’s Fiscal 2016 revenues were $297.0 million lower than in Fiscal 2015 principally reflecting lower natural gas revenues ($240.0 million), lower capacity management revenues ($41.7 million), lower retail power revenues ($19.5 million) and, to a lesser extent, lower electric generation and HVAC revenues. These decreases in revenues were partially offset by higher combined peaking and natural gas gathering revenues ($27.8 million). The significant decrease in natural gas revenues reflects lower wholesale and retail natural gas prices during Fiscal 2016 and, to a lesser extent, lower natural gas volumes resulting from the warmer weather. The lower retail power revenues principally reflect lower weather-related sales volumes and lower retail power prices. The decline in capacity management revenues reflects lower average prices for capacity as Fiscal 2016 experienced lower locational basis differences due to less volatility in capacity values between Marcellus and non-Marcellus delivery points. The decline in electric generation revenues reflects lower average electricity prices and lower electricity production volumes during Fiscal 2016, due in large part to the effects of the warmer winter weather and the impact of planned outages, while the decline in HVAC revenues principally reflects lower activity. The decrease in Midstream & Marketing cost of sales principally reflects lower natural gas cost of sales ($227.8 million) reflecting lower natural gas prices, lower cost of sales associated with the decline in retail power sales ($17.8 million) and, to a lesser extent, lower electric generation and HVAC cost of sales.
Midstream & Marketing total margin decreased $44.6 million in Fiscal 2016 principally reflecting lower capacity management total margin ($41.7 million), lower natural gas and retail power total margin ($14.9 million), lower electric generation total margin ($9.4 million) and lower HVAC total margin. These decreases in margin were partially offset by slightly higher combined natural gas gathering and peaking total margin ($27.5 million) reflecting the expansion of our natural gas gathering assets and higher demand for peaking services. As previously mentioned, the lower capacity management margin in Fiscal 2016 reflects lower average prices for capacity as a result of lower locational basis differences in capacity values between Marcellus and non-Marcellus delivery points. The decline in natural gas marketing total margin principally reflects the effects of lower average unit margins and lower volumes sold due to the warmer weather. The decline in electric generation total margin reflects lower average electricity prices and lower electricity production volumes.
Midstream & Marketing operating income and income before income taxes during Fiscal 2016 each decreased $35.9 million principally reflecting the previously mentioned decrease in total margin ($44.6 million) partially offset by slightly lower operating and administrative expenses and higher other operating income. Operating and administrative expenses were slightly lower in Fiscal 2016 due in large part to lower operating expenses in the HVAC business ($5.0 million) on lower Fiscal 2016 activity and greater costs in the prior year associated with our electricity generation facilities. Depreciation expense was slightly higher in Fiscal 2016 principally reflecting incremental depreciation expense associated with our natural gas gathering assets and the Conemaugh electricity generating unit.
UGI Utilities | 2016 | 2015 (a) | Decrease | ||||||||||||
(Dollars in millions) | |||||||||||||||
Revenues | $ | 768.5 | $ | 1,041.6 | $ | (273.1 | ) | (26.2 | )% | ||||||
Total margin (b) | $ | 473.9 | $ | 525.2 | $ | (51.3 | ) | (9.8 | )% | ||||||
Operating and administrative expenses | $ | 192.7 | $ | 218.3 | $ | (25.6 | ) | (11.7 | )% | ||||||
Operating income | $ | 200.9 | $ | 241.7 | $ | (40.8 | ) | (16.9 | )% | ||||||
Income before income taxes | $ | 163.3 | $ | 200.6 | $ | (37.3 | ) | (18.6 | )% | ||||||
Gas Utility system throughput – billions of cubic feet (“bcf”) | |||||||||||||||
Core market | 66.2 | 81.3 | (15.1 | ) | (18.6 | )% | |||||||||
Total | 212.4 | 213.5 | (1.1 | ) | (0.5 | )% | |||||||||
Electric Utility distribution sales - millions of kilowatt hours (“gwh”) | 961.6 | 1,010.1 | (48.5 | ) | (4.8 | )% | |||||||||
Gas Utility degree days – % (warmer) colder than normal (c) | (13.6 | )% | 6.4 | % | — | — | |||||||||
(a) | Includes amounts associated with PNG Gas’ heating, ventilation and air-conditioning service business through the date of its sale in June 2015. Such amounts are not material. |
(b) | Total margin represents total revenues less total cost of sales and Electric Utility gross receipts taxes, of $4.8 million and $5.6 million during Fiscal 2016 and Fiscal 2015, respectively. Gross receipt taxes are included in “Utility taxes other than income taxes” on the Consolidated Statements of Income. |
(c) | Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory. |
Temperatures in Gas Utility’s service territory during Fiscal 2016 based upon heating degree days were 13.6% warmer than normal and 17.8% warmer than Fiscal 2015. In particular, Gas Utility temperatures in the critical heating-season month of December were
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37% warmer than normal. Gas Utility core market volumes declined 15.1 bcf (18.6%) reflecting the effects of the significantly warmer weather. Total Gas Utility Fiscal 2016 distribution system throughput was about equal to Fiscal 2015 as the lower core market volumes were substantially offset by higher large firm delivery service volumes. Electric Utility kilowatt-hour sales were 4.8% lower than in the prior year principally reflecting the impact of the warmer weather on heating-related sales.
UGI Utilities Fiscal 2016 revenues decreased $273.1 million principally reflecting a $255.7 million decrease in Gas Utility revenues and a $16.5 million decrease in Electric Utility revenues. The lower Gas Utility revenues principally reflect a decrease in core market revenues ($203.1 million) and lower off-system sales revenues ($51.4 million). The $203.1 million decrease in Fiscal 2016 Gas Utility core market revenues reflects the effects of the lower core market throughput ($135.4 million) and lower average PGC rates ($67.7 million). The lower Electric Utility revenues principally resulted from lower DS rates ($8.0 million), lower sales volumes ($5.4 million) and lower transmission revenue ($2.6 million). UGI Utilities cost of sales was $289.8 million in Fiscal 2016 compared with $510.8 million in Fiscal 2015 principally reflecting the combined effects of the lower average Gas Utility PGC rates ($92.3 million), lower cost of sales associated with Gas Utility off-system sales ($51.4 million) and lower Gas Utility retail core-market volumes sold ($67.5 million). Electric Utility cost of sales was $11.5 million lower reflecting the lower DS rates ($8.5 million) and the lower volumes sold.
UGI Utilities Fiscal 2016 total margin decreased $51.3 million principally reflecting lower Gas Utility total margin from core market customers ($43.3 million). The decrease in Gas Utility core market margin reflects the lower core market throughput. Electric Utility total margin decreased $4.2 million principally reflecting the lower volume sales as a result of the warmer Fiscal 2016 weather and the lower transmission revenue.
UGI Utilities Fiscal 2016 operating income and income before income taxes decreased $40.8 million and $37.3 million, respectively. The decreases in operating income and income before income taxes principally reflects the decrease in total margin ($51.3 million), higher depreciation expense ($4.4 million) and lower other operating income ($10.9 million) which includes, among other things, higher environmental matters expense ($4.1 million), lower margin from off-system sales ($2.2 million), lower revenue from construction services ($2.1 million) and higher interest on PGC overcollections ($1.1 million). These were partially offset by operating and administrative expenses that were $25.6 million lower than the prior year primarily reflecting lower net preliminary development stage expenses associated with an IT project ($8.6 million), including the year-over-year impact of the Fiscal 2016 capitalization of $5.4 million of such IT costs expensed in prior years (see Note 8 to Consolidated Financial Statements), and, to a lesser extent, lower uncollectible accounts ($5.7 million), system maintenance expenses ($4.8 million) and employee benefits ($4.7 million). The decrease in income before income taxes also reflects lower interest expense principally due to lower average long-term debt outstanding and lower average interest rates.
Interest Expense. Our consolidated interest expense during Fiscal 2016 was $227.8 million, $14.1 million lower than the $241.9 million of interest expense recorded during Fiscal 2015. Interest expense in Fiscal 2015 includes $10.3 million of costs associated with an extinguishment of debt at Antargaz. Excluding the impact of these debt extinguishment costs, consolidated interest expense was $3.8 million lower principally reflecting UGI Utilities’ lower average long-term debt outstanding and lower average interest rates. Notwithstanding higher average long-term debt outstanding at UGI International in Fiscal 2016 resulting from the May 2015 acquisition of Finagaz, UGI International interest expense, excluding the impact of the debt extinguishment costs, was about equal to Fiscal 2015 reflecting lower average interest rates.
Income Taxes. Our effective income tax rate as a percentage of pre-tax income for Fiscal 2016 (excluding the effects on such rate of pre-tax income associated with noncontrolling interests not subject to federal income taxes) was 37.8%, slightly below the 38.8% rate in Fiscal 2015. The lower effective tax rate in Fiscal 2016 includes, among other things, the elimination of certain deferred tax valuation allowances associated with state loss carryforwards.
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, from a receivables purchase facility (“Receivables Facility”). Long-term cash requirements 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 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.
The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its subsidiaries by its principal business units. Our cash and cash equivalents totaled $558.4 million at September 30, 2017, compared with $502.8 million at September 30, 2016. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30,
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2017 and 2016, UGI had cash and cash equivalents of $291.1 million and $125.7 million, respectively, a substantial portion of which are located in the U.S. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.
AmeriGas Propane’s ability to pay dividends to UGI is dependent upon distributions it receives from AmeriGas Partners. At September 30, 2017, our 27% effective ownership interest in the Partnership consisted of approximately 23.8 million Common Units and an aggregate 2% general partner interest. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, as amended (the “Partnership Agreement”)) relating to such fiscal quarter. AmeriGas Propane, as general partner of AmeriGas Partners, is entitled to receive incentive distributions when AmeriGas Partners’ quarterly distribution exceeds $0.605 per limited partner unit. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests in the Partnership totaled $52.7 million, $47.4 million and $39.3 million, respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2017, Fiscal 2016 and Fiscal 2015 of $43.5 million, $38.2 million and $30.4 million, respectively (see Note 14 to Consolidated Financial Statements).
During Fiscal 2017, Fiscal 2016 and Fiscal 2015, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:
Year Ended September 30, | 2017 | 2016 | 2015 | |||||||||
(Millions of dollars) | ||||||||||||
AmeriGas Propane | $ | 123.0 | $ | 107.0 | $ | 97.3 | ||||||
UGI Utilities | 57.7 | 47.0 | 65.6 | |||||||||
UGI International | 118.3 | 98.4 | 31.3 | |||||||||
Midstream & Marketing (a) | — | — | 60.0 | |||||||||
Total | $ | 299.0 | $ | 252.4 | $ | 254.2 | ||||||
(a) | Cash dividends received from Midstream & Marketing in Fiscal 2015 were used to fund a portion of the Totalgaz Acquisition. See Note 4 to Consolidated Financial Statements. |
Dividends and Distributions
On April 25, 2017, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.25 per Common Share, equal to $1.00 on an annualized basis. The dividend rate reflects an approximately 5.3% increase from the previous quarterly rate of $0.2375. The new quarterly dividend rate was effective with the dividend payable on July 1, 2017, to shareholders of record on June 15, 2017.
On April 24, 2017, the General Partner’s Board of Directors approved an increase in the quarterly distribution rate on AmeriGas Partners Common Units to $0.95 per Common Unit, equal to $3.80 per Common Unit on an annualized basis. The distribution rate reflects a 1.1% increase from the previous quarterly rate of $0.94. The new quarterly rate was effective with the distribution payable on May 18, 2017, to unitholders of record on May 10, 2017.
Repurchases of Common Stock
In January 2014, the UGI Board of Directors authorized a share repurchase program for up to 15 million shares of UGI Corporation Common Stock. The authorization permits the execution of the share repurchase program over a four-year period. Pursuant to such authorization, during Fiscal 2017, Fiscal 2016 and Fiscal 2015, the Company purchased on the open market 0.9 million, 1.25 million and 1.0 million shares at a total purchase price of $43.3 million, $47.6 million and $34.1 million, respectively.
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Long-term Debt and Credit Facilities
The Company’s debt outstanding at September 30, 2017 and 2016, comprises the following:
2017 | 2016 | ||||||||||||||||||||||||||
(millions of dollars) | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Other | Total | Total | ||||||||||||||||||||
Short-term borrowings | $ | 140.0 | $ | 17.9 | $ | 39.0 | $ | 170.0 | $ | — | $ | 366.9 | $ | 291.7 | |||||||||||||
Long-term debt (including current maturities): | |||||||||||||||||||||||||||
Senior notes | $ | 2,575.0 | $ | — | $ | — | $ | 675.0 | $ | — | $ | 3,250.0 | $ | 2,905.8 | |||||||||||||
Term loans | — | 822.1 | — | 80.0 | — | 902.1 | 884.9 | ||||||||||||||||||||
Other long-term debt | 28.6 | 21.3 | 0.5 | — | 9.4 | 59.8 | 41.6 | ||||||||||||||||||||
Unamortized debt issuance costs | (31.3 | ) | (4.6 | ) | — | (3.9 | ) | — | (39.8 | ) | (36.8 | ) | |||||||||||||||
Total long-term debt | $ | 2,572.3 | $ | 838.8 | $ | 0.5 | $ | 751.1 | $ | 9.4 | $ | 4,172.1 | $ | 3,795.5 | |||||||||||||
Total debt | $ | 2,712.3 | $ | 856.7 | $ | 39.5 | $ | 921.1 | $ | 9.4 | $ | 4,539.0 | $ | 4,087.2 | |||||||||||||
Long-term Debt
AmeriGas Partners. During Fiscal 2017, AmeriGas Partners issued, in underwritten offerings, $700 million principal amount of 5.50% Senior Notes due May 2025 and $525 million principal amount of 5.75% Senior Notes due May 2027 (collectively, the “AmeriGas 2017 Senior Notes”). The net proceeds from the issuance of the AmeriGas 2017 Senior Notes were used (1) for the early repayment, pursuant to tender offers and notices of redemption, of all of AmeriGas Partners’ 7.00% Senior Notes, having an aggregate principal balance of $980.8 million plus accrued and unpaid interest and early redemption premiums, and (2) for general corporate purposes.
UGI Utilities. Pursuant to a note purchase agreement, in October 2016, UGI Utilities issued $100 million aggregate principal amount of 4.12% Senior Notes due October 2046 (the “UGI Utilities 4.12% Senior Notes”). The net proceeds of the issuance of the UGI Utilities 4.12% Senior Notes were used (1) to provide additional financing for UGI Utilities infrastructure replacement and betterment capital program and IT initiatives, and (2) for general corporate purposes.
On October 31, 2017, UGI Utilities entered into a $125 million unsecured term loan (the “Utilities Term Loan”) with a group of banks which initially matures on October 30, 2018. Such maturity will be automatically extended to October 30, 2022 once UGI Utilities delivers to the agent a copy of the securities certificate registered with the PUC authorizing UGI Utilities’ incurring indebtedness with such maturity date. Proceeds from the Utilities Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Utilities Term Loan is payable in equal quarterly installments of $1.6 million with the balance of the principal being due and payable in full on the maturity date.
For detailed information on the Company’s short-term and long-term borrowings, see Note 5 to Consolidated Financial Statements.
Short-term Debt
Due to the seasonal nature of the Company’s businesses, cash provided by operating activities is generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services consumed during the peak heating season months. Conversely, cash from operating activities is generally at its lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest. AmeriGas Propane and UGI Utilities primarily use their credit facilities to satisfy their seasonal operating cash flow needs. Energy Services, LLC has historically used its Receivables Facility to satisfy much of its seasonal operating cash flow needs. Energy Services, LLC also has a $240 million credit facility, which it can use for general corporate purposes. UGI International principally uses borrowings under credit agreements and cash on hand to satisfy its operating cash flow needs. Borrowings under the credit facilities and the Energy Services, LLC’s Receivables Facility are classified as “Short-term borrowings” on the Consolidated Balance Sheets. See Note 5 to Consolidated Financial Statements for further information on the Company’s short-term credit facilities.
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Information about the Company’s principal credit agreements (excluding Energy Services, LLC’s Receivables Facility, which is discussed below) as of September 30, 2017 and 2016, is presented in the tables below.
(Millions of dollars or euros) | Expiration Date | Total Capacity | Borrowings Outstanding | Letters of Credit and Guarantees Outstanding | Available Borrowing Capacity | Weighted Average Interest Rate - End of Year | |||||||||||||||
September 30, 2017 | |||||||||||||||||||||
AmeriGas OLP | June 2019 | $ | 525.0 | $ | 140.0 | $ | 67.2 | $ | 317.8 | 3.74 | % | ||||||||||
UGI France SAS | April 2020 | € | 60.0 | — | — | € | 60.0 | N.A. | |||||||||||||
Flaga (a) | October 2020 | € | 55.0 | — | € | 6.5 | € | 48.5 | N.A. | ||||||||||||
Energy Services, LLC | March 2021 | $ | 240.0 | — | — | $ | 240.0 | N.A. | |||||||||||||
UGI Utilities | March 2020 | $ | 300.0 | $ | 170.0 | $ | 2.0 | $ | 128.0 | 2.11 | % | ||||||||||
September 30, 2016 | |||||||||||||||||||||
AmeriGas OLP | June 2019 | $ | 525.0 | $ | 153.2 | $ | 67.2 | $ | 304.6 | 2.79 | % | ||||||||||
UGI France SAS | April 2020 | € | 60.0 | — | — | € | 60.0 | N.A. | |||||||||||||
Flaga (a) | October 2020 | € | 55.0 | — | € | 9.6 | € | 45.4 | N.A. | ||||||||||||
Energy Services, LLC | March 2021 | $ | 240.0 | $ | — | — | $ | 240.0 | N.A. | ||||||||||||
UGI Utilities | March 2020 | $ | 300.0 | $ | 112.5 | $ | 2.0 | $ | 185.5 | 1.42 | % | ||||||||||
(a) | Total capacity comprises a €25 million multi-currency revolving credit facility, a €5 million overdraft facility and a €25 million guarantee facility. Guarantees outstanding reduce the available capacity on the €25 million guarantee facility. |
The average daily and peak short-term borrowings under the Company’s principal credit agreements during Fiscal 2017 and Fiscal 2016 are as follows:
2017 | 2016 | |||||||||||||||
(Millions of dollars or euros) | Average | Peak | Average | Peak | ||||||||||||
AmeriGas OLP | $ | 89.3 | $ | 292.5 | $ | 99.0 | $ | 249.0 | ||||||||
UGI France SAS | € | — | € | — | € | — | € | — | ||||||||
Flaga | € | — | € | — | € | — | € | — | ||||||||
Energy Services, LLC | $ | 8.0 | $ | 28.0 | $ | 23.6 | $ | 81.0 | ||||||||
UGI Utilities | $ | 80.7 | $ | 178.0 | $ | 150.8 | $ | 232.0 | ||||||||
Energy Services, LLC also has a Receivables Facility with an issuer of receivables-backed commercial paper. On October 27, 2017, the expiration date of the Receivables Facility was extended to October 26, 2018. The Receivables Facility, as amended, provides Energy Services with the ability to borrow up to $150 million of eligible receivables during the period November through April, and up to $75 million of eligible receivables during the period May through October. Energy Services, LLC uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
At September 30, 2017, the outstanding balance of trade receivables was $44.8 million of which $39.0 million was sold to the bank. At September 30, 2016, the outstanding balance of trade receivables was $35.7 million of which $25.5 million was sold to the bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Consolidated Balance Sheet (see Note 5 to Consolidated Financial Statements). During Fiscal 2017 and Fiscal 2016, peak sales of receivables were $49.0 million and $46.0 million, respectively, and average daily amounts sold were $14.0 million and $14.4 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.
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Operating Activities:
Year-to-year variations in our cash flows from operating activities can be significantly affected by changes in operating working capital especially during periods with significant changes in energy commodity prices. Cash flows from operating activities in Fiscal 2017, Fiscal 2016 and Fiscal 2015 were $964.4 million, $969.7 million and $1,163.8 million, respectively. Cash flow from operating activities before changes in operating working capital was $1,133.0 million in Fiscal 2017, $926.6 million in Fiscal 2016 and $972.0 million in Fiscal 2015. The higher cash flow before changes in operating working capital in Fiscal 2017 reflects the higher net income (after adjusting net income for the noncash effects of unrealized gains and losses on derivative instruments and loss on extinguishment of debt) and the absence of a $36.0 million cash settlement on interest rate protection agreements at UGI Utilities recorded in Fiscal 2016. The slightly lower Fiscal 2016 cash flow from operating activities before changes in operating working capital compared to Fiscal 2015 principally reflects the effects of lower net income (after adjusting net income for the noncash effects of unrealized gains and losses on derivative instruments and the loss on extinguishment of debt at AmeriGas Partners) and the $36.0 million interest rate agreements settlement at UGI Utilities partially offset by higher noncash charges for deferred income taxes and depreciation and amortization. Changes in operating working capital (used) provided operating cash flow of $(168.6) million in Fiscal 2017, $43.1 million in Fiscal 2016 and $191.8 million in Fiscal 2015. Cash flow from changes in operating working capital principally reflect the impact of energy commodity prices on changes in accounts receivable, inventories and accounts payable. The higher cash used to fund changes in operating working capital in Fiscal 2017 reflects in large part the impact of increases in LPG and natural gas prices. The significantly higher cash provided by net changes in accounts receivable, inventories and accounts payable in Fiscal 2015 reflects, in large part, the impact of significant declines in LPG and natural gas costs in Fiscal 2015. In addition, cash flow from changes in operating working capital include net refunds of UGI Utilities purchased gas and electricity costs of $15.4 million in Fiscal 2017 and $22.7 million in Fiscal 2016, and net overcollections of $51.8 million in Fiscal 2015.
Investing Activities:
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 and retirements of property, plant and equipment. Cash expenditures for property, plant and equipment totaled $638.9 million in Fiscal 2017, $563.8 million in Fiscal 2016 and $490.6 million in Fiscal 2015. Cash payments for property, plant and equipment were higher in Fiscal 2017 compared to Fiscal 2016 reflecting, in large part, higher pipeline and peaking asset-related cash capital expenditures at our Midstream & Marketing segment, and a pipeline expansion project and higher IT capital expenditures at UGI Utilities. Cash payments for property, plant and equipment were higher in Fiscal 2016 compared to Fiscal 2015 reflecting, in large part, higher Gas Utility replacement and infrastructure improvement capital expenditures, higher Energy Services midstream pipeline project capital expenditures and, to a lesser extent, incremental UGI International capital expenditures principally reflecting the full-year impact of Finagaz. Net cash used for acquisitions of businesses in Fiscal 2017 reflects net cash paid for acquisitions at AmeriGas Propane ($36.8 million) and UGI International ($64.8 million). Net cash paid for acquisitions of businesses in Fiscal 2016 includes business acquisitions at AmeriGas Propane ($37.6 million) and UGI International ($23.6 million). Net cash paid for business acquisitions in Fiscal 2015 reflects in large part the Totalgaz Acquisition (see Note 4 to Consolidated Financial Statements). Cash from changes in restricted cash, primarily cash in futures brokerage accounts, provided (used) cash of $6.1 million in Fiscal 2017, $53.7 million in Fiscal 2016 and $(52.8) million in Fiscal 2015. The amount of restricted cash required in such accounts is generally the result of changes in underlying commodity prices.
Financing Activities:
Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; short-term borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units; and issuances or repurchases of equity instruments.
During Fiscal 2017, UGI Utilities issued $100 million of Senior Notes and used the net proceeds principally to fund infrastructure replacement and betterment capital expenditures, IT initiatives and for general corporate purposes. During Fiscal 2017, AmeriGas Partners and AmeriGas Finance Corp. issued $700.0 million of Senior Notes the net proceeds of which were used in large part for the early repayment of a portion of AmeriGas Partners’ 7.00% Senior Notes having an aggregate principal balance of $500.0 million plus accrued and unpaid interest and early redemption premiums. Also during Fiscal 2017, AmeriGas Partners and AmeriGas Finance Corp. issued $525 million of Senior Notes, the net proceeds of which were used primarily for the early repayments in February and May of the remaining outstanding AmeriGas Partners’ 7.00% Senior Notes having an aggregate principal balance of $480.8 million.
In Fiscal 2016, AmeriGas Partners issued $1.35 billion face value of AmeriGas Partners Senior Notes and used substantially all of the net proceeds from the issuance to repay $1.27 billion principal amount of existing AmeriGas Partners Senior Notes subject to tender offers and notices of redemptions. In addition, during Fiscal 2016 UGI Utilities issued $300 million of Senior Notes and
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used the net proceeds principally to repay maturing long-term debt and short-term borrowings. The increases in dividends on UGI Common Stock and distributions on AmeriGas Partners’ publicly held Common Units during the three-year period principally reflect annual increases in quarterly dividend and distribution rates.
Financing cash flows in Fiscal 2015 include net proceeds from the issuance of long-term debt under the UGI France 2015 Senior Facilities Agreement totaling $652.6 million, the proceeds of which were used principally to fund a portion of the acquisition of Finagaz and to prepay term loans outstanding under Antargaz’ 2011 Senior Facilities Agreement. For further information on debt transactions, see Note 5 to Consolidated Financial Statements.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions) for Fiscal 2017, Fiscal 2016 and Fiscal 2015. We also provide amounts we expect to spend in Fiscal 2018. We expect to finance a substantial portion of our Fiscal 2018 capital expenditures from cash generated by operations, borrowings under credit facilities and cash on hand.
Year Ended September 30, | 2018 | 2017 | 2016 | 2015 | ||||||||||||
(Millions of dollars) | (estimate) | |||||||||||||||
AmeriGas Propane | $ | 112.0 | $ | 98.1 | $ | 101.7 | $ | 102.0 | ||||||||
UGI International | 107.0 | 90.3 | 99.9 | 87.5 | ||||||||||||
UGI Utilities | 317.0 | 317.7 | 262.5 | 197.7 | ||||||||||||
Midstream & Marketing | 47.0 | 117.5 | 140.4 | 88.0 | ||||||||||||
Total | $ | 583.0 | $ | 623.6 | $ | 604.5 | $ | 475.2 | ||||||||
The higher levels of UGI Utilities capital expenditures in Fiscal 2017 and Fiscal 2016, as well as those estimated for Fiscal 2018, reflect greater main replacement and system improvement capital expenditures, increases in new business capital expenditures and expected investments in new IT projects.
Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2017. Such obligations include scheduled repayments of long-term debt, interest on long-term fixed-rate debt, operating lease payments, unconditional purchase obligations for pipeline capacity, pipeline transportation and natural gas storage services and commitments to purchase natural gas, LPG and electricity, capital expenditures and derivative instruments. The following table presents contractual cash obligations with non-affiliates under agreements existing as of September 30, 2017:
Payments Due by Period | ||||||||||||||||||||
(Millions of dollars) | Total | Fiscal 2018 | Fiscal 2019 - 2020 | Fiscal 2021 - 2022 | Thereafter | |||||||||||||||
Long-term debt (a) | $ | 4,211.9 | $ | 179.6 | $ | 655.9 | $ | 80.7 | $ | 3,295.7 | ||||||||||
Interest on long-term-fixed rate debt (b) | 2,017.9 | 197.2 | 380.3 | 359.9 | 1,080.5 | |||||||||||||||
Operating leases | 454.9 | 91.0 | 147.2 | 102.4 | 114.3 | |||||||||||||||
AmeriGas Propane supply contracts | 7.4 | 7.4 | — | — | — | |||||||||||||||
UGI International supply contracts | 69.1 | 69.1 | — | — | — | |||||||||||||||
Midstream & Marketing supply contracts | 225.4 | 166.8 | 50.9 | 7.7 | — | |||||||||||||||
UGI Utilities supply, storage and transportation contracts | 332.5 | 93.8 | 100.7 | 69.4 | 68.6 | |||||||||||||||
Derivative instruments (c) | 37.7 | 18.8 | 18.6 | 0.3 | — | |||||||||||||||
Total | $ | 7,356.8 | $ | 823.7 | $ | 1,353.6 | $ | 620.4 | $ | 4,559.1 | ||||||||||
(a) | Based upon stated maturity dates for debt outstanding at September 30, 2017. |
(b) | Based upon stated interest rates adjusted for the effects of interest rate swaps. |
(c) | Represents the sum of amounts due if derivative instrument liabilities were settled at September 30, 2017, amounts reflected in the Consolidated Balance Sheet (but excluding amounts associated with interest rate and cross-currency swaps). |
“Other noncurrent liabilities” included in our Consolidated Balance Sheet at September 30, 2017, principally comprise refundable tank and cylinder deposits (as further described in Note 2 to Consolidated Financial Statements under the caption “Refundable
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Tank and Cylinder Deposits”); litigation, property and casualty liabilities and obligations under environmental remediation agreements (see Note 15 to Consolidated Financial Statements); pension and other postretirement benefit liabilities recorded in accordance with accounting guidance relating to employee retirement plans (see Note 7 to Consolidated Financial Statements); and liabilities associated with executive compensation plans (see Note 13 to Consolidated Financial Statements). These liabilities are not included in the table of Contractual Cash Obligations and Commitments because they are estimates of future payments and not contractually fixed as to timing or amount. Required minimum contributions to UGI Utilities’ pension plan (as further described below under “U.S. Pension Plan”) in Fiscal 2018 are not expected to be material. Required minimum contributions to the U.S. Pension Plan in years beyond Fiscal 2018 will depend, in large part, on the impacts of future returns on pension plan assets and interest rates on pension plan liabilities. Certain of our operating lease arrangements, primarily vehicle leases with remaining lease terms of one to ten years, have residual value guarantees. Although such fair values at the end of the leases have historically exceeded the guaranteed amount, at September 30, 2017, the maximum potential amount of future payments under lease guarantees assuming the leased equipment was deemed worthless was approximately $47 million.
UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units
On November 7, 2017, UGI entered into the Commitment Agreement with AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make up to $225 million of capital contributions to the Partnership through July 1, 2019 (the “Commitment Period”). UGI’s capital contributions may be made from time to time during the Commitment Period upon request of the Partnership.
In consideration for any capital contributions made pursuant to the Commitment Agreement, the Partnership will issue to UGI or a wholly owned subsidiary new Class B Common Units representing limited partner interests in the Partnership (“Class B Units”) at a price equal to the 20-day volume-weighted average price of the Partnership’s Common Units prior to the date of the Partnership’s capital call. The Class B Units will be entitled to cumulative quarterly distributions at a rate equal to the annualized Common Unit yield at the time of the applicable capital call, plus 130 basis points. The Partnership may choose to make the distributions in cash or in the form of additional Class B Units. While outstanding, the Class B Units will not be subject to any incentive distributions from the Partnership.
Generally, at any time after five years from the initial issuance of the Class B Units, holders may elect to convert all or any portion of the Class B Units they own into Common Units on a one-for-one basis, and at any time after six years from the initial issuance of the Class B Units, subject to certain conditions, the Partnership may elect to convert all or any portion of the Class B Units into Common Units. For additional information, see Note 15 to Consolidated Financial Statements.
U.S. Pension Plan
In the U.S., we sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). The fair values of the U.S. Pension Plan’s assets totaled $498.0 million and $463.4 million at September 30, 2017 and 2016, respectively. At September 30, 2017 and 2016, the underfunded positions of the U.S. Pension Plan, defined as the excess of the projected benefit obligation (“PBO”) over the U.S. Pension Plan’s assets, were $141.2 million and $182.0 million, respectively.
We believe we are in compliance with regulations governing defined benefit pension plans, including the Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations. Required minimum contributions to the U.S. Pension Plan in Fiscal 2018 are not expected to be material. Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2017 was $17.1million. Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2018 is expected to be approximately $13.0 million.
GAAP guidance associated with pension and other postretirement plans generally requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and other postretirement benefit plans with current year changes recognized in shareholders’ equity unless such amounts are subject to regulatory recovery. At September 30, 2017, we have recorded after-tax charges to UGI Corporation’s stockholders’ equity of $19.2 million and recorded regulatory assets totaling $141.3 million in order to reflect the funded status of our pension and other postretirement benefit plans. For a more detailed discussion of the U.S. Pension Plan and our other postretirement benefit plans, see Note 7 to Consolidated Financial Statements.
Related Party Transactions
During Fiscal 2017, Fiscal 2016 and Fiscal 2015, we did not enter into any related-party transactions that had a material effect on our financial condition, results of operations or cash flows.
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Off-Balance-Sheet Arrangements
UGI primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the recognition and measurement guidance relating to guarantees under GAAP.
We do not have any off-balance-sheet arrangements that are expected to have a material effect on our financial condition, change in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Utility Regulatory Matters
Base Rate Filings. On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21.7 million annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PUC providing for an $11.3 million PNG annual base distribution rate increase. On August 31, 2017, the PUC approved the Joint Petition and the increase became effective October 20, 2017.
On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27.0 million annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016.
Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at 5% of distribution charges billed to customers.
PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions seeking approval to increase the maximum allowable DSIC from 5% to 10% of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues, effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018.
On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.
Manufactured Gas Plants
From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility. UGI Utilities also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania.
Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into a consent order and agreement (“COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2.5 million, $1.8 million and $1.1 million, for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018 and 2019, respectively. At September 30, 2017 and 2016, our estimated accrued liabilities for environmental investigation and remediation costs related
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to the COAs for UGI Utilities, CPG and PNG totaled $54.3 million and $55.1 million, respectively. UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 8 to the Consolidated Financial Statements).
We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to UGI Utilities’ results of operations because UGI Utilities, CPG and PNG receive ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.
From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by a former subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At September 30, 2017, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material.
Market Risk Disclosures
Our primary market risk exposures are (1) commodity price risk; (2) interest rate risk; and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.
Commodity Price Risk
The risk associated with fluctuations in the prices the Partnership and our UGI International operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for LPG and other energy commodities. Their profitability is sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. The Partnership and UGI International may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements and over-the-counter derivative commodity instruments including price swap and option contracts. Our UGI International operations use over-the-counter derivative commodity instruments and may from time to time enter into other derivative contracts, similar to those used by the Partnership, to reduce market risk associated with a portion of their LPG purchases. Over-the-counter derivative commodity instruments used to economically hedge forecasted purchases of LPG are generally settled at expiration of the contract. In addition, certain of our UGI International businesses hedge a portion of their anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts as further described below.
Gas Utility's tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments, including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”), to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility's PGC recovery mechanism.
Electric Utility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations.
In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures contracts are recorded at fair value with changes in fair value reflected in “Operating and administrative expenses” on the Consolidated Statements of Income.
In order to manage market price risk relating to substantially all of Midstream & Marketing’s fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX, Intercontinental Exchange (“ICE”) and over-the-counter natural
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gas and electricity futures and natural gas basis swap contracts or enters into fixed-price supply arrangements. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge a portion of its anticipated sales of electricity from its electricity generation facilities. Although Midstream & Marketing’s fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas or electricity would adversely impact Midstream & Marketing’s results. In order to reduce this risk of supplier nonperformance, Midstream & Marketing has diversified its purchases across a number of suppliers. UGI International’s natural gas and electricity marketing businesses also use natural gas and electricity futures and forward contracts to economically hedge market risk associated with fixed-price sales and purchase contracts.
From time to time, Midstream & Marketing purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. Midstream & Marketing from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Midstream & Marketing also uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas or propane.
Midstream & Marketing has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to supply electricity under these agreements, Midstream & Marketing would be required to purchase electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact Midstream & Marketing’s results.
Interest Rate Risk
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact their fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt includes short-term borrowings and UGI France SAS’s and Flaga’s variable-rate term loans. These debt agreements have interest rates that are generally indexed to short-term market interest rates. UGI France SAS and Flaga, through the use of pay-fixed receive-variable interest rate swaps, have fixed the underlying euribor interest rates on their euro-denominated term loans through all, or a substantial portion of, the periods such debt is outstanding. In addition, Flaga’s U.S. dollar-denominated loan has been swapped from a floating-rate U.S. dollar-denominated interest rate to a fixed-rate euro-denominated interest rate through a cross-currency swap, removing interest rate risk (and foreign currency exchange risk as further described below under Foreign Currency Exchange Rate Risk) associated with the underlying interest payments. At September 30, 2017, combined borrowings outstanding under variable-rate debt agreements, excluding UGI France SAS’s and Flaga’s effectively fixed-rate term loan and Flaga’s U.S. dollar-denominated loan, totaled $366.9 million. Based upon average borrowings outstanding under variable-rate borrowings (excluding UGI France SAS’s and Flaga’s effectively fixed-rate term loan debt and Flaga’s U.S. dollar-denominated loan), an increase in short-term interest rates of 100 basis points (1%) would have increased our Fiscal 2017 interest expense by approximately $3 million. The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of approximately $259 million at September 30, 2017. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of approximately $291 million at September 30, 2017.
Long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt with similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce interest rate risk associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”).
Foreign Currency Exchange Rate Risk
Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro and, to a lesser extent, the U.S. dollar versus the British pound sterling. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. From time to time, we use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Gains or losses on net investment hedges remain in accumulated other comprehensive income until such foreign operations are sold or liquidated. At September 30, 2017, there were no unsettled net investment hedges outstanding. With respect to our net investments in our UGI International operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar would reduce their aggregate net book value at September 30, 2017, by approximately $120 million, which amount would be reflected in other comprehensive income.
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In addition, in order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March.
Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts.
As previously mentioned, Flaga has a cross-currency swap to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of U.S. dollar-denominated debt. This cross-currency hedge includes initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance.
Derivative Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions as deemed appropriate.
Certain of these derivative instrument agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2017, restricted cash in brokerage accounts totaled $10.3 million. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at September 30, 2017. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At September 30, 2017, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
The following table summarizes the fair values of unsettled market risk sensitive derivative instrument assets (liabilities) held at September 30, 2017. The table also includes the changes in fair values of derivative instruments that would result if there were (1) a 10% adverse change in the market prices of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges; (2) a 50 basis point adverse change in the three-month and one-month euribor rates; and (3) a 10% change in the value of the euro and the British pound sterling versus the U.S. dollar. Gas Utility’s and Electric Utility’s derivative instruments other than gasoline futures contracts are excluded from the table below because any associated net gains or losses are refundable to or recoverable from customers in accordance with Gas Utility and Electric Utility ratemaking.
Asset (Liability) | ||||||||
(Millions of dollars) | Fair Value | Change in Fair Value | ||||||
September 30, 2017: | ||||||||
Commodity price risk | $ | 64.8 | $ | (61.0 | ) | |||
Interest rate risk | $ | (2.3 | ) | $ | (1.5 | ) | ||
Foreign currency exchange rate risk | $ | (28.9 | ) | $ | (51.4 | ) | ||
Critical Accounting Policies and Estimates
Accounting policies and estimates discussed in this section are those that we consider to be the most critical to an understanding of our financial statements because they involve significant judgments and uncertainties. Changes in these policies and estimates could have a material effect on the financial statements. The application of these accounting policies and estimates necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements. Management has reviewed these critical accounting policies, and the estimates and assumptions associated with them, with the Company’s Audit Committee. Also, see Note 2 to Consolidated Financial Statements which discusses the significant accounting policies that we have selected from acceptable alternatives.
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Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation that arises in the normal course of business. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere, and PNG and CPG owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with GAAP, we record a reserve when it is probable that a liability exists and the amount or range of amounts related to such liability can be reasonably estimated. When there is a range of possible loss with equal likelihood, liabilities recorded are based upon the low end of such range. The likelihood of a loss with respect to a particular contingency is often difficult to predict and determining a reasonable estimate of the loss or a range of possible loss may not be practicable based upon the information available and the potential effects of future events and decisions by third parties that will determine the ultimate resolution of the contingency. Reasonable estimates involve management judgments based on a broad range of information and prior experience and include an evaluation of the nature of the claim, the procedural status of the matter, the probability or likelihood of success of prosecuting or defending the claim, the information available with respect to the claim, the opinions and views of outside counsel and other advisors, and past experience in similar matters. These judgments are reviewed quarterly as more information is received, and the amounts reserved are updated as necessary. Our estimated reserves may differ materially from the ultimate liability and such reserves may change materially as more information becomes available.
Accounting For Derivative Instruments at Fair Value. The Company enters into derivative instruments to economically hedge the risks associated with changes in commodity prices, interest rates and foreign currency rates. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies. These derivatives are recognized as assets and liabilities at fair value on the Consolidated Balance Sheets. Derivative assets and liabilities are presented net by counterparty on our Consolidated Balance Sheets if the right of offset exists. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. Changes in the fair values of certain derivative instruments that qualify and are designated as cash flow hedges are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, both of which are components of equity, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. Changes in the fair values of derivative instruments that we do not designate as, or that do not qualify for, hedge accounting under GAAP, which currently comprises all of our commodity and certain of our foreign currency derivative instruments, are recognized in earnings on the Consolidated Statements of Income. The fair values of our derivative instruments are determined based upon actively-quoted market prices for identical assets and liabilities, indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Gains and losses associated with derivatives utilized by UGI Utilities to manage the price risk inherent in its natural gas and electricity purchasing activities are recoverable through Gas Utility PGC or Electric Utility DS mechanisms, subject to PUC approval. Accordingly, the offset to the changes in fair values of these derivatives for which the normal purchases and normal sales exception under GAAP does not apply are recorded as either a regulatory asset or liability on the Consolidated Balance Sheets. At September 30, 2017, the net fair value of our derivative assets totaled $80.6 million and the net fair value of our derivative liabilities totaled $46.8 million.
Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation by the PUC. In accordance with accounting guidance associated with rate-regulated entities, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2017, our regulatory assets and regulatory liabilities totaled $368.9 million and $49.2 million, respectively. For additional information on regulatory assets and liabilities, see Notes 2 and 8 to Consolidated Financial Statements.
Depreciation and Amortization of Long-Lived Assets. We compute depreciation on utility property, plant and equipment on a straight-line basis based upon the projected service lives of its various classes of depreciable property and on our non-utility property, plant and equipment on a straight-line basis over estimated useful lives generally ranging from 3 to 40 years. We also use amortization methods and determine asset values of intangible assets subject to amortization using reasonable assumptions and projections. Changes in the estimated useful lives of property, plant and equipment and changes in intangible asset amortization methods or values could have a material effect on our results of operations. As of September 30, 2017, our net property, plant and equipment totaled $5,537.0 million and we recorded depreciation expense of $357.3 million during Fiscal 2017. As of September 30, 2017, our net intangible assets subject to amortization totaled $477.6 million and we recorded amortization expense on intangible assets subject to amortization of $50.8 million during Fiscal 2017.
Purchase Price Allocations. From time to time, the Company enters into material business combinations. In accordance with accounting guidance associated with business combinations, the purchase price is allocated to the various assets acquired and liabilities assumed at their estimated fair value. Fair values of assets acquired and liabilities assumed are based upon available information and we may involve an independent third party to perform appraisals. Estimating fair values can be complex and
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subject to significant business judgment and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, if necessary, up to one year from the acquisition date to finalize the purchase price allocation.
Goodwill Impairment Evaluation. Our goodwill is the result of business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2017, we adopted new accounting guidance simplifying the test for goodwill impairment. The adoption of the new guidance did not impact the consolidated financial statements. See Note 3 to Consolidated Financial Statements for more information.
For certain of our reporting units with goodwill, we assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit. As of September 30, 2017, our goodwill totaled $3,107.2 million. We did not record any impairments of goodwill in Fiscal 2017, Fiscal 2016 or Fiscal 2015.
Impairment of Long-Lived Assets. Impairment testing for individual long-lived assets, or groups of long-lived assets, is required when circumstances indicate that such assets may be impaired. If it is determined that a triggering event has occurred, we prepare a quantitative evaluation based upon undiscounted cash flow projections expected to be realized over the remaining useful life of the asset or the primary asset of an asset group. A long-lived asset or group of assets is considered impaired when the carrying amount of such assets exceeds the associated undiscounted estimated future cash flows. When determining whether an asset or group of assets has been impaired, management groups assets at the lowest level that has identifiable cash flows. Performing an impairment test on long-lived assets involves judgment in areas such as identifying when a triggering event requiring evaluation occurs; identifying and grouping assets; and, if the asset or group of assets is determined to be impaired based upon an excess of carrying amount over estimated undiscounted future cash flows, determining the fair value of the asset or asset group. Although cash flow estimates are based upon relevant information at the time the estimates are made, estimates of future cash flows are by nature highly uncertain and contemplate factors that change over time such as the expected use of the asset including future production and sales volumes, expected fluctuations in prices of commodities and expected proceeds from disposition. No material provisions for impairments of long-lived assets were recorded during Fiscal 2017, Fiscal 2016 or Fiscal 2015.
Pension Plan Assumptions. Pension plan assumptions are significant inputs to the actuarial models that measure pension benefit obligations and pension expense. The cost of providing benefits under the U.S. Pension Plan is dependent on historical information such as employee age, length of service, level of compensation and the actual rate of return on plan assets. In addition, certain assumptions relating to the future are used to determine pension expense including mortality assumptions, the discount rate applied to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase, among others. Assets of the U.S. Pension Plan are held in trust and consist principally of equity and fixed income mutual funds and investments in UGI Corporation Common Stock. Changes in plan assumptions as well as fluctuations in actual equity or fixed income market returns could have a material impact on future pension costs. We believe the two most critical assumptions are (1) the expected rate of return on plan assets, and (2) the discount rate. A decrease in the expected rate of return on U.S. Pension Plan assets of 50 basis points to a rate of 6.90% would result in an increase in pre-tax pension cost of approximately $2.3 million in Fiscal 2018. A decrease in the discount rate of 50 basis points to a rate of 3.50% would result in an increase in pre-tax pension cost of approximately $4.4 million in Fiscal 2018. For additional information on our U.S. Pension Plan, see Note 7 to Consolidated Financial Statements.
Income Taxes. We use the asset and liability method of accounting for income taxes. Under this method, income tax expense is recognized for the amount of taxes payable or refundable for the current year and for deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. Positions taken by an entity
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in its tax returns must satisfy a more-likely-than-not recognition threshold assuming the positions will be examined by tax authorities with full knowledge of relevant information. We use assumptions, judgments and estimates to determine our current provision for income taxes. We also use assumptions, judgments and estimates to determine our deferred tax assets and liabilities and any valuation allowance to be recorded against a deferred tax asset. Our assumptions, judgments and estimates relative to the current provision for income tax give consideration to current tax laws, our interpretation of current tax laws and possible outcomes of current and future audits conducted by foreign and domestic tax authorities. Changes in tax law or our interpretation thereof and the resolution of current and future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. Our assumptions, judgments and estimates relative to the amount of deferred income taxes take into account estimates of the amount of future taxable income. Actual taxable income or future estimates of taxable income could render our current assumptions, judgments and estimates inaccurate. Changes in the assumptions, judgments and estimates mentioned above could cause our actual income tax obligations to differ significantly from our estimates. As of September 30, 2017, our net deferred tax liabilities totaled $1,330.7 million.
Recently Issued Accounting Pronouncements
See Note 3 to the Consolidated Financial Statements for a discussion of the effects of recently issued accounting guidance.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
“Quantitative and Qualitative Disclosures About Market Risk” are contained in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Market Risk Disclosures” and are incorporated by reference.
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Management’s Annual Report on Internal Control Over Financial Reporting and the financial statements and financial statement schedules referred to in the Index contained on page F-2 of this Report are incorporated herein by reference.
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
ITEM 9A. | CONTROLS AND PROCEDURES |
(a) | The Company's disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed or submitted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company's management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures, as of September 30, 2017, were effective at the reasonable assurance level. |
(b) | For “Management’s Annual Report on Internal Control Over Financial Reporting” see Item 8 of this Report (which information is incorporated herein by reference). |
(c) | Effective on September 4, 2017, our wholly-owned subsidiary, UGI Utilities, Inc., implemented a new customer service and meter management system to replace its legacy system. We consider the system replacement to be material to UGI Corporation. The implementation resulted in greater automation of internal controls in the UGI Utilities Meter-to-Bill cycle. As a result of the implementation, controls that were previously determined to be effective were replaced with new or modified controls that were also determined to be effective. Other than this system implementation, there were no changes in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. |
ITEM 9B. | OTHER INFORMATION |
None.
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PART III:
ITEMS 10 THROUGH 14.
In accordance with General Instruction G(3), and except as set forth below, the information required by Items 10, 11, 12, 13 and 14 is incorporated in this Report by reference to the following portions of UGI’s Proxy Statement, which will be filed with the SEC by December 31, 2017.
Information | Captions of Proxy Statement Incorporated by Reference | ||
Item 10. | Directors, Executive Officers and Corporate Governance | Election of Directors - Nominees; Corporate Governance; Director Independence; Board Leadership Structure and Role in Risk Management; Board Meetings and Attendance; Board and Committee Structure; Communications with the Board; Securities Ownership of Certain Beneficial Owners - Security Ownership of Directors and Executive Officers; Securities Ownership of Certain Beneficial Owners - Section 16(a) Beneficial Ownership Reporting Compliance; Report of the Audit Committee of the Board of Directors | |
The Code of Ethics for the Chief Executive Officer and Senior Financial Officers of UGI Corporation is available without charge on the Company’s website, www.ugicorp.com, or by writing to Treasurer, UGI Corporation, P. O. Box 858, Valley Forge, PA 19482. | |||
Item 11. | Executive Compensation | Compensation of Directors; Report of the Compensation and Management Development Committee of the Board of Directors; Compensation Discussion and Analysis; Compensation of Executive Officers; Compensation Committee Interlocks and Insider Participation | |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | Security Ownership of Directors and Executive Officers; Securities Ownership of Certain Beneficial Owners; Section 16(a) Beneficial Ownership Reporting Compliance. | |
Item 13. | Certain Relationships and Related Transactions, and Director Independence | Election of Directors - Director Independence and Board and Committee Structure; Policy for Approval of Related Person Transactions | |
Item 14. | Principal Accounting Fees and Services | Our Independent Registered Public Accounting Firm | |
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Equity Compensation Table
The following table sets forth information as of the end of Fiscal 2017 with respect to compensation plans under which our equity securities are authorized for issuance.
Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | Weighted average exercise price of outstanding options, warrants and rights (b) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) | ||||||||
Equity compensation plans approved by security holders | 8,781,748 | (1) | $ | 30.20 | 10,855,935 | (2) | |||||
978,834 | (3) | $ | 0 | ||||||||
Equity compensation plans not approved by security holders | 0 | ||||||||||
Total | 9,760,582 | $ | 30.20 | (4) | |||||||
(1) | Represents 8,781,748 stock options under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 and the UGI Corporation 2013 Omnibus Incentive Compensation Plan. |
(2) | Represents 4,116 securities remaining for future issuance of stock options from the 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 and 10,851,819 of securities remaining for issuance from the UGI Corporation 2013 Omnibus Incentive Compensation Plan. The UGI Corporation 2013 Omnibus Incentive Compensation Plan was approved by the shareholders on January 24, 2013. |
(3) | Represents 978,834 restricted stock units under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 and the UGI Corporation 2013 Omnibus Incentive Compensation Plan. |
(4) | Weighted-average exercise price of outstanding options; excludes restricted stock units. |
The information concerning the Company’s executive officers required by Item 10 is set forth below.
EXECUTIVE OFFICERS
Name | Age | Position | ||
John L. Walsh | 62 | President and Chief Executive Officer | ||
Kirk R. Oliver | 59 | Chief Financial Officer | ||
Robert F. Beard | 52 | President and Chief Executive Officer, UGI Utilities, Inc. | ||
Monica M. Gaudiosi | 54 | Vice President, General Counsel and Secretary | ||
Joseph L. Hartz | 54 | President, UGI Energy Services, LLC | ||
Marie-Dominique Ortiz-Landazabal | 49 | Vice President - Accounting and Financial Control and Chief Accounting Officer | ||
Roger Perreault | 53 | President, UGI International | ||
Jerry E. Sheridan | 52 | President and Chief Executive Officer, AmeriGas Propane, Inc. | ||
All officers are elected for a one-year term at the organizational meetings of the respective Boards of Directors held each year.
There are no family relationships between any of the officers or between any of the officers and any of the directors.
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John L. Walsh
Mr. Walsh is a Director and President (since 2005) and Chief Executive Officer (since 2013) of UGI Corporation. In addition, Mr. Walsh serves as a Director and Chairman of the Board of AmeriGas Propane, Inc. (since 2016), where he had served as a director and vice chairman since 2005. He also serves as a Director and Vice Chairman of UGI Utilities, Inc. (since 2005). Both AmeriGas Propane, Inc. and UGI Utilities, Inc. are subsidiaries of UGI Corporation. Mr. Walsh served as Chief Operating Officer of UGI Corporation (2005 to 2013) and as President and Chief Executive Officer of UGI Utilities, Inc. (2009 to 2011). Previously, Mr. Walsh was the Chief Executive of the Industrial and Special Products division of the BOC Group plc, an industrial gases company, a position he assumed in 2001. He was an Executive Director of BOC (2001 to 2005) having joined BOC in 1986 as Vice President - Special Gases and having held various senior management positions in BOC, including President of Process Gas Solutions, North America (2000 to 2001) and President of BOC Process Plants (1996 to 2000). Mr. Walsh also serves as Director at Main Line Health, Inc., the United Way of Southeastern Pennsylvania and Southern New Jersey, the World Affairs Council of Philadelphia, and the Philadelphia Zoo, and as Trustee at the Saint Columbkille Partnership School.
Kirk R. Oliver
Mr. Oliver is Chief Financial Officer of UGI Corporation (since 2012). From December 2011 until September 2012, Mr. Oliver served as Senior Managing Director & Chief Operating Officer of InfraREIT Capital Partners, LLC, a partnership that invests in infrastructure assets, primarily electric transmission and gas pipeline assets. Prior to joining InfraREIT Capital, Mr. Oliver served as Senior Vice President and Chief Financial Officer of Allegheny Energy, Inc., an electric utility company (2008 to 2011) and as a Senior Executive at Hunt Power, LLC, a company that develops and invests in electric and gas utility projects (2007 to 2008). Mr. Oliver served in various positions at TXU Corp. (now Energy Future Holdings Corp.), an electricity distribution, generation and transmission company in Texas (1998 to 2006), including as Executive Vice President and Chief Financial Officer (2004 to 2006), Senior Vice President, Finance (2000 to 2003) and Vice President, Treasurer and Assistant Secretary (1998 to 1999). Prior to joining TXU Corp., Mr. Oliver spent eleven years as an investment banker in the Global Power and Energy Group at Lehman Brothers and six years at Motorola Inc. As previously announced, Mr. Oliver will leave his position as Chief Financial Officer of UGI Corporation in early 2018.
Robert F. Beard
Mr. Beard is President and Chief Executive Officer and a Director of UGI Utilities, Inc. (since 2011). He previously served as Vice President - Marketing, Rates and Gas Supply (2010 to 2011) and Vice President - Southern Region (2008 to 2010) of UGI Utilities, Inc. From 2006 until 2008, Mr. Beard served as Vice President - Operations and Engineering of PPL Gas Utilities Corporation and, from 2002 until 2006, he served as Director - Operations and Engineering of PPL Gas Utilities Corporation.
Monica M. Gaudiosi
Ms. Gaudiosi is the Vice President, General Counsel and Secretary of UGI Corporation and UGI Utilities, Inc. (since 2012). She is also Vice President (since 2012), General Counsel (since July 2015) and Secretary (since 2012) of AmeriGas Propane, Inc. Prior to joining UGI Corporation, Ms. Gaudiosi served as Senior Vice President and General Counsel (2007 to 2012) and Senior Vice President and Associate General Counsel (2005 to 2007) of Southern Union Company. Prior to joining Southern Union Company in 2005, Ms. Gaudiosi held various positions with General Electric Capital Corporation (1997 to 2005). Before joining General Electric Capital Corporation, Ms. Gaudiosi was an associate at the law firms of Hunton & Williams (1994 to 1997) and Sutherland, Asbill & Brennan (1988 to 1994).
Joseph L. Hartz
Mr. Hartz is President of UGI Energy Services, LLC (since March 2017). He previously served as Chief Operating officer (June 2014 to March 2017) and as Vice President - Supply and Operations (July 2010 to June 2014) of UGI Energy Services, LLC. He joined UGI Energy Services, LLC in 1985 as an accountant and has held various positions of increasing responsibility, including Vice President - Assets and Supply and Chief Financial Officer.
Marie-Dominique Ortiz-Landazabal
Marie-Dominique Ortiz-Landazabal is Vice President - Accounting and Financial Control and Chief Accounting Officer of UGI Corporation (since December 2015). She previously served as General Auditor since January 2012 when she joined UGI Corporation. Prior to joining the Company, Ms. Ortiz-Landazabal was Manager, Accounting Policies and Specialty Accounting at Air Products and Chemicals, Inc. (September 2010 until December 2011). Prior to her position at Air Products, she held positions of increasing responsibility at PricewaterhouseCoopers LLP in Florida, Virginia, Paris (France), and Philadelphia, Pennsylvania
64
(1994-2010).
Roger Perreault
Mr. Perreault is President - UGI International (since December 2015). Prior to joining UGI Corporation, Mr. Perreault held various positions at Air Liquide, an industrial gases company he joined in 1994. He was Group Vice President of the Large Industries World Business line based in Frankfurt, Germany (2014-2015). Previously, he held several positions in management ranging from business development to general management in Canada. Mr. Perreault then became President of Air Liquide Chile (2003-2005), President of Air Liquide Brazil (2005-2008) and then President of Large Industries North America based in Houston, Texas (2008-2014). Prior to joining Air Liquide, Mr. Perreault was a chemical engineer and operations manager with I.C.I. in Quebec, Canada.
Jerry E. Sheridan
Mr. Sheridan is President, Chief Executive Officer and a Director of AmeriGas Propane, Inc. (since March 2012). Previously, he served as Vice President - Operations and Chief Operating Officer (2011 to 2012) and as Vice President - Finance and Chief Financial Officer (2005 to 2011) of AmeriGas Propane, Inc. Mr. Sheridan served as President and Chief Executive Officer (2003 to 2005) of Potters Industries, Inc., a global manufacturer of engineered glass materials and a wholly-owned subsidiary of PQ Corporation, a global producer of inorganic specialty chemicals. In addition, Mr. Sheridan served as Executive Vice President (2003 to 2005) and as Vice President and Chief Financial Officer (1999 to 2003) of PQ Corporation. Mr. Sheridan also serves on the Management Board of CP Kelco (since 2013), a privately held company that provides innovative products and solutions through the use of nature-based chemistry.
PART IV:
ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
(a) | Documents filed as part of this report: |
(1) | Financial Statements: |
Included under Item 8 are the following financial statements and supplementary data:
Management’s Annual Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm (on Internal Control Over Financial Reporting)
Report of Independent Registered Public Accounting Firm (on Consolidated Financial Statements and Schedules)
Consolidated Balance Sheets as of September 30, 2017 and 2016
Consolidated Statements of Income for the years ended September 30, 2017, 2016 and 2015
Consolidated Statements of Comprehensive Income for the years ended September 30, 2017, 2016 and 2015
Consolidated Statements of Cash Flows for the years ended September 30, 2017, 2016 and 2015
Consolidated Statements of Changes in Equity for the years ended September 30, 2017, 2016 and 2015
Notes to Consolidated Financial Statements
(2) | Financial Statement Schedules: |
I — Condensed Financial Information of Registrant (Parent Company)
II — Valuation and Qualifying Accounts for the years ended September 30, 2017, 2016 and 2015
We have omitted all other financial statement schedules because the required information is (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
65
(3) | List of Exhibits: |
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
Incorporation by Reference | |||||
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | |
3.1 | UGI | Form 10-Q (6/30/05) | 3.1 | ||
3.2 | UGI | Form 8-K (7/29/14) | 3.1 | ||
3.3 | UGI | Form 8-K (7/31/17) | 3.1 | ||
4.1 | Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of long-term debt not required to be filed pursuant to Item 601(b)(4) of Regulation S-K). | ||||
4.2 | The description of the Company’s Common Stock contained in the Company’s registration statement filed under the Securities Exchange Act of 1934, as amended. | UGI | Form 8-B/A (4/17/96) | 3.(4) | |
4.3 | UGI Corporation’s (Second) Amended and Restated Articles of Incorporation, as amended, and Bylaws referred to in 3.1, 3.2, and 3.3 above. | ||||
4.4 | AmeriGas Partners, L.P. | Form 10-Q (6/30/09) | 3.1 | ||
4.5 | AmeriGas Partners, L.P. | Form 8-K (3/14/12) | 3.1 | ||
4.6 | AmeriGas Partners, L.P. | Form 8-K (7/27/15) | 3.1 | ||
66
Incorporation by Reference | |||||
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | |
4.7 | Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994. | Utilities | Registration Statement No. 33-77514 (4/8/94) | 4(c) | |
4.8 | Utilities | Form 8-K (9/12/06) | 4.2 | ||
4.9 | AmeriGas Partners, L.P. | Form 8-K (1/12/12) | 4.1 | ||
4.10 | AmeriGas Partners, L.P. | Form 8-K (1/12/12) | 4.2 | ||
4.11 | Form of Fixed Rate Medium-Term Note. | Utilities | Form 8-K (8/26/94) | 4(i) | |
4.12 | Utilities | Form 8-K (8/1/96) | 4(i) | ||
4.13 | Utilities | Form 8-K (8/1/96) | 4(ii) | ||
4.14 | Officer’s Certificate establishing Medium-Term Notes Series. | Utilities | Form 8-K (8/26/94) | 4(iv) | |
4.15 | Utilities | Form 8-K (8/1/96) | 4(iv) | ||
4.16 | Utilities | Form 8-K (5/21/02) | 4.2 | ||
4.17 | Utilities | Form 8-K (5/21/02) | 4.1 | ||
4.18 | Utilities | Form 8-K (10/30/13) | 4.1 | ||
67
Incorporation by Reference | |||||
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | |
4.19 | Utilities | Form 8-K (4/28/16) | 4.1 | ||
4.20 | AmeriGas Partners, L.P. | Form 8-K (6/27/16) | 4.1 | ||
4.21 | AmeriGas Partners, L.P. | Form 8-K (6/27/16) | 4.2 | ||
4.22 | AmeriGas Partners, L.P. | Form 8-K (12/28/16) | 4.1 | ||
4.23 | AmeriGas Partners, L.P. | Form 8-K (2/13/17) | 4.1 | ||
10.1** | AmeriGas Partners, L.P. | Form 8-K (7/30/10) | 10.2 | ||
10.2** | AmeriGas Partners, L.P. | Form 10-K (9/30/16) | 10.7 | ||
10.3** | AmeriGas Partners, L.P. | Form 10-Q (3/31/13) | 10.9 | ||
*10.4** | |||||
10.5** | AmeriGas Partners, L.P. | Form 10-Q (3/31/14) | 10.4 | ||
68
Incorporation by Reference | |||||
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | |
10.6** | UGI | Form 10-Q (12/31/12) | 10.1 | ||
10.7** | UGI | Form 10-Q (6/30/12) | 10.1 | ||
10.8** | AmeriGas Partners, L.P. | Form 10-Q (3/31/12) | 10.6 | ||
*10.9** | |||||
*10.10** | |||||
10.11** | AmeriGas Partners, L.P. | Form 10-Q (6/30/17) | 10.1 | ||
10.12** | AmeriGas Partners, L.P. | Form 10-Q (6/30/17) | 10.2 | ||
10.13** | AmeriGas Partners, L.P. | Form 10-Q (6/30/17) | 10.3 | ||
10.14** | AmeriGas Partners, L.P. | Form 10-Q (6/30/17) | 10.4 | ||
10.15** | UGI | Form 10-Q (6/30/08) | 10.3 | ||
10.16** | UGI | Form 10-K (9/30/16) | 10.15 | ||
10.17** | AmeriGas Partners, L.P. | Form 10-K (9/30/09) | 10.29 | ||
10.18** | UGI | Form 10-Q (6/30/17) | 10.2 | ||
69
Incorporation by Reference | |||||
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | |
10.19** | UGI | Form 10-Q (6/30/17) | 10.3 | ||
10.20** | UGI | Form 10-Q (6/30/17) | 10.4 | ||
10.21** | UGI | Form 10-Q (6/30/17) | 10.5 | ||
*10.22** | |||||
10.23** | UGI | Form 10-K (9/30/16) | 10.25 | ||
10.24** | UGI | Form 10-K (9/30/16) | 10.26 | ||
10.25** | UGI | Form 10-Q (6/30/17) | 10.6 | ||
*10.26** | |||||
10.27** | UGI | Form 10-Q (6/30/17) | 10.1 | ||
10.28** | UGI | Form 10-K (9/30/16) | 10.30 | ||
10.29** | UGI | Form 10-K (9/30/16) | 10.31 | ||
70
Incorporation by Reference | |||||
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | |
10.30** | UGI | Form 10-Q (3/31/13) | 10.14 | ||
*10.31** | |||||
10.32** | UGI | Form 10-Q (6/30/17) | 10.7 | ||
10.33** | Utilities | Form 10-Q (3/31/13) | 10.2 | ||
10.34** | Utilities | Form 10-Q (6/30/17) | 10.1 | ||
10.35 | UGI | Form 10-K (9/30/10) | 10.37 | ||
10.36 | AmeriGas Partners, L.P. | Form 10-K (9/30/15) | 10.40 | ||
10.37 | AmeriGas Partners, L.P. | Form 10-Q (12/31/10) | 10.1 | ||
*10.38 | |||||
71
Incorporation by Reference | |||||
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | |
*10.39 | |||||
10.40 | Utilities | Form 10-K (9/30/14) | 10.16 | ||
10.41 | Utilities | Form 10-K (9/30/14) | 10.19 | ||
10.42 | AmeriGas Partners, L.P. | Form 8-K (6/18/14) | 10.1 | ||
10.43 | AmeriGas Partners, L.P. | Form 8-K (6/20/16) | 10.2 | ||
72
Incorporation by Reference | |||||
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | |
10.44 | Utilities | Form 8-K (3/27/15) | 10.1 | ||
10.45 | UGI | Form 10-Q (6/30/15) | 10.1 | ||
10.46 | UGI | Form 10-Q (6/30/17) | 10.8 | ||
10.47 | UGI | Form 8-K (2/29/16) | 10.1 | ||
10.48 | Utilities | Form 10-K (9/30/16) | 10.19 | ||
10.49 | Utilities | Form 8-K (10/31/17) | 10.1 | ||
73
Incorporation by Reference | |||||
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | |
10.50 | AmeriGas Partners, L.P. | Form 8-K (11/7/17) | 10.1 | ||
14 | UGI | Form 10-K (9/30/03) | 14 | ||
*21 | |||||
*23 | |||||
*31.1 | |||||
*31.2 | |||||
*32 | |||||
*101.INS | XBRL Instance | ||||
*101.SCH | XBRL Taxonomy Extension Schema | ||||
*101.CAL | XBRL Taxonomy Extension Calculation Linkbase | ||||
*101.DEF | XBRL Taxonomy Extension Definition Linkbase | ||||
*101.LAB | XBRL Taxonomy Extension Labels Linkbase | ||||
*101.PRE | XBRL Taxonomy Extension Presentation Linkbase | ||||
* | Filed herewith. |
** | As required by Item 15(a)(3), this exhibit is identified as a compensatory plan or arrangement. |
ITEM 16. FORM 10-K SUMMARY
None.
74
EXHIBIT INDEX
Exhibit No. | Description |
10.4 | |
10.9 | |
10.10 | |
10.22 | |
10.26 | |
10.31 | |
10.38 | |
10.39 | |
21 | |
23 | |
31.1 | |
31.2 | |
32 | |
101.INS | XBRL Instance |
101.SCH | XBRL Taxonomy Extension Schema |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase |
101.DEF | XBRL Taxonomy Extension Definition Linkbase |
101.LAB | XBRL Taxonomy Extension Labels Linkbase |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase |
75
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
UGI CORPORATION | |||
Date: | November 21, 2017 | By: | /s/ Kirk R. Oliver |
Kirk R. Oliver Chief Financial Officer | |||
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 21, 2017, by the following persons on behalf of the Registrant in the capacities indicated.
Signature | Title | |
/s/ John L. Walsh | President and Chief Executive Officer (Principal Executive Officer) and Director | |
John L. Walsh | ||
/s/ Kirk R. Oliver | Chief Financial Officer (Principal Financial Officer) | |
Kirk R. Oliver | ||
/s/ Marie-Dominique Ortiz-Landazabal | Vice President - Accounting and Financial Control and Chief Accounting Officer (Principal Accounting Officer) | |
Marie-Dominique Ortiz-Landazabal | ||
/s/ Marvin O. Schlanger | Chairman and Director | |
Marvin O. Schlanger | ||
/s/ M. Shawn Bort | Director | |
M. Shawn Bort | ||
/s/ Theodore A. Dosch | Director | |
Theodore A. Dosch | ||
/s/ Richard W. Gochnauer | Director | |
Richard W. Gochnauer | ||
/s/ Frank S. Hermance | Director | |
Frank S. Hermance | ||
/s/ Anne Pol | Director | |
Anne Pol | ||
/s/ James B. Stallings, Jr. | Director | |
James B. Stallings, Jr. | ||
/s/ Roger B. Vincent | Director | |
Roger B. Vincent | ||
76
UGI CORPORATION AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2017
F-1
UGI CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
Pages | |
Financial Statement Schedules: | |
For the years ended September 30, 2017, 2016 and 2015: | |
We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
F-2
Reports of Management
Financial Statements
The Company’s consolidated financial statements and other financial information contained in this Annual Report were prepared by management, which is responsible for their fairness, integrity and objectivity. The consolidated financial statements and related information were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include amounts that are based on management’s best judgments and estimates.
The Audit Committee of the Board of Directors is composed of three members, each of whom is independent and a non-employee director of the Company. The Committee is responsible for monitoring and overseeing the financial reporting process, the adequacy of internal accounting controls, the independence and performance of the Company’s independent registered accounting firm and internal auditors. The Committee meets regularly, with and without management present, with the independent registered accounting firm and the internal auditors, both of which report directly to the Committee. In addition, the Committee provides regular reports to the Board of Directors.
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, of the Company’s internal control over financial reporting as of September 30, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO 2013 Framework”).
Internal control over financial reporting refers to the process, designed under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, and effected by the Company’s Board of Directors, to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changing conditions, or the degree of compliance with the policies or procedures may deteriorate.
Based on its assessment, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2017, based on the COSO 2013 Framework. Ernst & Young LLP, our independent registered public accounting firm, has audited the effectiveness of the Company’s internal control over financial reporting as of September 30, 2017, as stated in their report, which appears herein.
/s/ John L. Walsh
Chief Executive Officer
/s/ Kirk R. Oliver
Chief Financial Officer
/s/ Marie-Dominique Ortiz-Landazabal
Chief Accounting Officer
F-3
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of UGI Corporation:
We have audited UGI Corporation’s internal control over financial reporting as of September 30, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). UGI Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, UGI Corporation maintained, in all material respects, effective internal control over financial reporting as of September 30, 2017, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of UGI Corporation and subsidiaries as of September 30, 2017 and 2016, and the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the three years in the period ended September 30, 2017 of UGI Corporation and subsidiaries and our report dated November 21, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
November 21, 2017
F-4
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of UGI Corporation:
We have audited the accompanying consolidated balance sheets of UGI Corporation and subsidiaries as of September 30, 2017 and 2016, and the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the three years in the period ended September 30, 2017. Our audits also included the financial statement schedules listed in the Index at Item 15(a). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of UGI Corporation and subsidiaries at September 30, 2017 and 2016, and the consolidated results of their operations and their cash flows for each of the three years in the period ended September 30, 2017, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), UGI Corporation's internal control over financial reporting as of September 30, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated November 21, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
November 21, 2017
F-5
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
September 30, | |||||||
2017 | 2016 | ||||||
ASSETS | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 558.4 | $ | 502.8 | |||
Restricted cash | 10.3 | 15.6 | |||||
Accounts receivable (less allowances for doubtful accounts of $26.9 and $27.3, respectively) | 626.8 | 551.6 | |||||
Accrued utility revenues | 13.3 | 12.8 | |||||
Inventories | 278.6 | 210.3 | |||||
Utility regulatory assets | 8.3 | 3.2 | |||||
Derivative instruments | 63.1 | 30.9 | |||||
Prepaid expenses and other current assets | 138.7 | 96.6 | |||||
Total current assets | 1,697.5 | 1,423.8 | |||||
Property, plant and equipment | |||||||
Non-utility | 5,564.6 | 5,346.4 | |||||
Utility | 3,285.3 | 2,998.9 | |||||
8,849.9 | 8,345.3 | ||||||
Accumulated depreciation and amortization | (3,312.9 | ) | (3,107.3 | ) | |||
Net property, plant, and equipment | 5,537.0 | 5,238.0 | |||||
Goodwill | 3,107.2 | 2,989.0 | |||||
Intangible assets, net | 611.7 | 580.3 | |||||
Utility regulatory assets | 360.6 | 391.9 | |||||
Derivative instruments | 9.2 | 6.5 | |||||
Other assets | 259.0 | 217.7 | |||||
Total assets | $ | 11,582.2 | $ | 10,847.2 | |||
LIABILITIES AND EQUITY | |||||||
Current liabilities | |||||||
Current maturities of long-term debt | $ | 177.5 | $ | 29.5 | |||
Short-term borrowings | 366.9 | 291.7 | |||||
Accounts payable | 439.6 | 391.2 | |||||
Employee compensation and benefits accrued | 124.7 | 115.1 | |||||
Deposits and advances | 206.9 | 241.3 | |||||
Derivative instruments | 25.0 | 48.5 | |||||
Accrued interest | 60.7 | 48.1 | |||||
Other current liabilities | 288.8 | 276.6 | |||||
Total current liabilities | 1,690.1 | 1,442.0 | |||||
Debt and other liabilities | |||||||
Long-term debt | 3,994.6 | 3,766.0 | |||||
Deferred income taxes | 1,357.0 | 1,212.4 | |||||
Deferred investment tax credits | 3.0 | 3.3 | |||||
Derivative instruments | 21.8 | 21.9 | |||||
Other noncurrent liabilities | 774.8 | 806.6 | |||||
Total liabilities | 7,841.3 | 7,252.2 | |||||
Commitments and contingencies (Note 15) | |||||||
Equity: | |||||||
UGI Corporation stockholders’ equity: | |||||||
UGI Common Stock, without par value (authorized – 450,000,000 shares; issued – 173,987,691 and 173,894,141 shares, respectively) | 1,188.6 | 1,201.6 | |||||
Retained earnings | 2,106.7 | 1,834.1 | |||||
Accumulated other comprehensive loss | (93.4 | ) | (154.7 | ) | |||
Treasury stock, at cost | (38.6 | ) | (36.9 | ) | |||
Total UGI Corporation stockholders’ equity | 3,163.3 | 2,844.1 | |||||
Noncontrolling interests, principally in AmeriGas Partners | 577.6 | 750.9 | |||||
Total equity | 3,740.9 | 3,595.0 | |||||
Total liabilities and equity | $ | 11,582.2 | $ | 10,847.2 | |||
See accompanying Notes to Consolidated Financial Statements.
F-6
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
Year Ended September 30, | |||||||||||
2017 | 2016 | 2015 | |||||||||
Revenues | $ | 6,120.7 | $ | 5,685.7 | $ | 6,691.1 | |||||
Costs and Expenses | |||||||||||
Cost of sales (excluding depreciation shown below) | 2,837.3 | 2,437.5 | 3,736.5 | ||||||||
Operating and administrative expenses | 1,857.8 | 1,865.9 | 1,773.9 | ||||||||
Utility taxes other than income taxes | 15.6 | 15.8 | 16.1 | ||||||||
Depreciation | 357.3 | 338.6 | 313.2 | ||||||||
Amortization | 59.0 | 62.3 | 60.9 | ||||||||
Other operating income, net | (10.5 | ) | (22.4 | ) | (44.4 | ) | |||||
5,116.5 | 4,697.7 | 5,856.2 | |||||||||
Operating income | 1,004.2 | 988.0 | 834.9 | ||||||||
Income (loss) from equity investees | 4.3 | (0.2 | ) | (1.2 | ) | ||||||
Loss on extinguishments of debt | (59.7 | ) | (48.9 | ) | — | ||||||
Losses on foreign currency contracts, net | (23.9 | ) | — | — | |||||||
Interest expense | (223.5 | ) | (228.9 | ) | (241.9 | ) | |||||
Income before income taxes | 701.4 | 710.0 | 591.8 | ||||||||
Income taxes | (177.6 | ) | (221.2 | ) | (177.8 | ) | |||||
Net income including noncontrolling interests | 523.8 | 488.8 | 414.0 | ||||||||
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners | (87.2 | ) | (124.1 | ) | (133.0 | ) | |||||
Net income attributable to UGI Corporation | $ | 436.6 | $ | 364.7 | $ | 281.0 | |||||
Earnings per common share attributable to UGI Corporation stockholders: | |||||||||||
Basic | $ | 2.51 | $ | 2.11 | $ | 1.62 | |||||
Diluted | $ | 2.46 | $ | 2.08 | $ | 1.60 | |||||
Weighted-average common shares outstanding (thousands): | |||||||||||
Basic | 173,662 | 173,154 | 173,115 | ||||||||
Diluted | 177,159 | 175,572 | 175,667 | ||||||||
Dividends declared per common share | $ | 0.975 | $ | 0.930 | $ | 0.890 | |||||
See accompanying Notes to Consolidated Financial Statements.
F-7
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of dollars)
Year Ended September 30, | |||||||||||
2017 | 2016 | 2015 | |||||||||
Net income including noncontrolling interests | $ | 523.8 | $ | 488.8 | $ | 414.0 | |||||
Net gains (losses) on derivative instruments (net of tax of $(0.5), $12.3 and $(8.0), respectively) | 1.7 | (16.5 | ) | 16.8 | |||||||
Reclassifications of net (gains) losses on derivative instruments (net of tax of $4.1, $5.0 and $(2.8), respectively) | (9.7 | ) | (8.1 | ) | 1.6 | ||||||
Foreign currency translation adjustments (net of tax of $(0.6), $0.0 and $(1.0), respectively) | 34.6 | (4.9 | ) | (63.5 | ) | ||||||
Foreign currency gains (losses) on long-term intra-company transactions (net of tax of $0.0, $0.0 and $(6.7), respectively) | 24.8 | (1.9 | ) | (50.6 | ) | ||||||
Benefit plans, principally actuarial gains (losses) (net of tax of $(3.8), $7.1 and $1.4, respectively) | 6.5 | (10.9 | ) | (1.2 | ) | ||||||
Reclassifications of benefit plans actuarial losses and net prior service credits (net of tax of $(2.1), $(0.4) and $(0.8), respectively) | 3.4 | 2.2 | 1.4 | ||||||||
Other comprehensive income (loss) | 61.3 | (40.1 | ) | (95.5 | ) | ||||||
Comprehensive income including noncontrolling interests | 585.1 | 448.7 | 318.5 | ||||||||
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners | (87.2 | ) | (124.1 | ) | (130.9 | ) | |||||
Comprehensive income attributable to UGI Corporation | $ | 497.9 | $ | 324.6 | $ | 187.6 | |||||
See accompanying Notes to Consolidated Financial Statements.
F-8
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
Year Ended September 30, | |||||||||||
2017 | 2016 | 2015 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||
Net income including noncontrolling interests | $ | 523.8 | $ | 488.8 | $ | 414.0 | |||||
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: | |||||||||||
Depreciation and amortization | 416.3 | 400.9 | 374.1 | ||||||||
Deferred income taxes, net | 110.1 | 77.4 | 13.7 | ||||||||
Provision for uncollectible accounts | 30.7 | 21.7 | 31.6 | ||||||||
Changes in unrealized (gains) losses on derivative instruments | (82.0 | ) | (91.6 | ) | 119.1 | ||||||
Equity-based compensation expense | 19.3 | 23.8 | 29.2 | ||||||||
Loss on extinguishments of debt | 59.7 | 48.9 | — | ||||||||
Settlement of UGI Utilities interest rate protection agreements | — | (36.0 | ) | — | |||||||
Loss on private equity partnership investment | 11.0 | — | — | ||||||||
Other, net | 44.1 | (7.3 | ) | (9.7 | ) | ||||||
Net change in: | |||||||||||
Accounts receivable and accrued utility revenues | (103.6 | ) | 37.3 | 163.3 | |||||||
Inventories | (64.7 | ) | 29.4 | 181.4 | |||||||
Utility deferred fuel costs, net of changes in unsettled derivatives | (15.4 | ) | (22.7 | ) | 51.8 | ||||||
Accounts payable | 49.9 | (40.0 | ) | (134.9 | ) | ||||||
Other current assets | (37.5 | ) | (8.6 | ) | (25.6 | ) | |||||
Other current liabilities | 2.7 | 47.7 | (44.2 | ) | |||||||
Net cash provided by operating activities | 964.4 | 969.7 | 1,163.8 | ||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||
Expenditures for property, plant and equipment | (638.9 | ) | (563.8 | ) | (490.6 | ) | |||||
Acquisitions of businesses, net of cash acquired | (101.6 | ) | (61.2 | ) | (447.5 | ) | |||||
Decrease (increase) in restricted cash | 6.1 | 53.7 | (52.8 | ) | |||||||
Other, net | (29.0 | ) | 12.7 | 14.6 | |||||||
Net cash used by investing activities | (763.4 | ) | (558.6 | ) | (976.3 | ) | |||||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||
Dividends on UGI Common Stock | (168.9 | ) | (160.7 | ) | (153.5 | ) | |||||
Distributions on AmeriGas Partners publicly held Common Units | (261.6 | ) | (257.3 | ) | (248.9 | ) | |||||
Issuances of debt, net of issuance costs | 1,307.1 | 1,629.5 | 660.3 | ||||||||
Repayments of debt, including redemption premiums | (1,064.8 | ) | (1,569.9 | ) | (429.4 | ) | |||||
Receivables Facility net borrowings | 13.5 | 6.0 | 12.0 | ||||||||
Increase (decrease) in short-term borrowings | 61.2 | 95.7 | (31.9 | ) | |||||||
Issuances of UGI Common Stock | 11.0 | 13.7 | 11.9 | ||||||||
Repurchases of UGI Common Stock | (43.3 | ) | (47.6 | ) | (34.1 | ) | |||||
Other | (0.8 | ) | 15.5 | (3.5 | ) | ||||||
Net cash used by financing activities | (146.6 | ) | (275.1 | ) | (217.1 | ) | |||||
Effect of exchange rate changes on cash and cash equivalents | 1.2 | (2.9 | ) | (20.2 | ) | ||||||
Cash and cash equivalents increase (decrease) | $ | 55.6 | $ | 133.1 | $ | (49.8 | ) | ||||
CASH AND CASH EQUIVALENTS | |||||||||||
End of year | $ | 558.4 | $ | 502.8 | $ | 369.7 | |||||
Beginning of year | 502.8 | 369.7 | 419.5 | ||||||||
Increase (decrease) | $ | 55.6 | $ | 133.1 | $ | (49.8 | ) | ||||
SUPPLEMENTAL CASH FLOW INFORMATION | |||||||||||
Cash paid for: | |||||||||||
Interest | $ | 202.1 | $ | 228.9 | $ | 227.0 | |||||
Income taxes | $ | 98.0 | $ | 134.5 | $ | 173.1 | |||||
See accompanying Notes to Consolidated Financial Statements.
F-9
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions of dollars, except per share amounts)
Year Ended September 30, | |||||||||||
2017 | 2016 | 2015 | |||||||||
Common stock, without par value | |||||||||||
Balance, beginning of year | $ | 1,201.6 | $ | 1,214.6 | $ | 1,215.6 | |||||
Common stock issued: | |||||||||||
Employee and director plans (including losses on treasury stock transactions), net of tax withheld | (28.2 | ) | (39.7 | ) | (22.1 | ) | |||||
Excess tax benefits realized on equity-based compensation | — | 15.5 | 8.3 | ||||||||
Equity-based compensation expense | 13.2 | 11.2 | 13.2 | ||||||||
Gain on sale of treasury stock | 2.0 | — | — | ||||||||
Loss from acquisition of noncontrolling interests through business combination | — | — | (0.4 | ) | |||||||
Balance, end of year | $ | 1,188.6 | $ | 1,201.6 | $ | 1,214.6 | |||||
Retained earnings | |||||||||||
Balance, beginning of year | $ | 1,834.1 | $ | 1,630.1 | $ | 1,502.6 | |||||
Cumulative effect of change in accounting for share-based payments | 4.9 | — | — | ||||||||
Net income attributable to UGI Corporation | 436.6 | 364.7 | 281.0 | ||||||||
Cash dividends on common stock | (168.9 | ) | (160.7 | ) | (153.5 | ) | |||||
Balance, end of year | $ | 2,106.7 | $ | 1,834.1 | $ | 1,630.1 | |||||
Accumulated other comprehensive income (loss) | |||||||||||
Balance, beginning of year | $ | (154.7 | ) | $ | (114.6 | ) | $ | (21.2 | ) | ||
Net gains (losses) on derivative instruments | 1.7 | (16.5 | ) | 16.8 | |||||||
Reclassification of net (gains) losses on derivative instruments | (9.7 | ) | (8.1 | ) | 3.7 | ||||||
Benefit plans, principally actuarial gains (losses) | 6.5 | (10.9 | ) | (1.2 | ) | ||||||
Reclassification of benefit plans actuarial losses and net prior service credits | 3.4 | 2.2 | 1.4 | ||||||||
Foreign currency gains (losses) on long-term intra-company transactions | 24.8 | (1.9 | ) | (50.6 | ) | ||||||
Foreign currency translation adjustments | 34.6 | (4.9 | ) | (63.5 | ) | ||||||
Balance, end of year | $ | (93.4 | ) | $ | (154.7 | ) | $ | (114.6 | ) | ||
Treasury stock | |||||||||||
Balance, beginning of year | $ | (36.9 | ) | $ | (44.9 | ) | $ | (44.7 | ) | ||
Common stock issued: | |||||||||||
Employee and director plans | 49.6 | 84.7 | 40.5 | ||||||||
Repurchases of common stock | (43.3 | ) | (47.6 | ) | (34.1 | ) | |||||
Reacquired common stock – employee and director plans | (8.2 | ) | (29.1 | ) | (6.6 | ) | |||||
Sale of treasury stock | 0.2 | — | — | ||||||||
Balance, end of year | $ | (38.6 | ) | $ | (36.9 | ) | $ | (44.9 | ) | ||
Total UGI Corporation stockholders’ equity | $ | 3,163.3 | $ | 2,844.1 | $ | 2,685.2 | |||||
Noncontrolling interests | |||||||||||
Balance, beginning of year | $ | 750.9 | $ | 880.4 | $ | 1,004.1 | |||||
Net income attributable to noncontrolling interests, principally in AmeriGas Partners | 87.2 | 124.1 | 133.0 | ||||||||
Reclassification of net gains on derivative instruments | — | — | (2.1 | ) | |||||||
Dividends and distributions | (261.6 | ) | (257.3 | ) | (249.4 | ) | |||||
Change in noncontrolling interests as a result of business combination | — | — | (5.2 | ) | |||||||
Other | 1.1 | 3.7 | — | ||||||||
Balance, end of year | $ | 577.6 | $ | 750.9 | $ | 880.4 | |||||
Total equity | $ | 3,740.9 | $ | 3,595.0 | $ | 3,565.6 | |||||
See accompanying Notes to Consolidated Financial Statements.
F-10
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Index to Notes
Note 1 — Nature of Operations
Note 2 — Summary of Significant Accounting Policies
Note 3 — Accounting Changes
Note 4 — Acquisitions
Note 5 — Debt
Note 6 — Income Taxes
Note 7 — Employee Retirement Plans
Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters
Note 9 — Inventories
Note 10 — Property, Plant and Equipment
Note 11 — Goodwill and Intangible Assets
Note 12 — Series Preferred Stock
Note 13 — Common Stock and Equity-Based Compensation
Note 14 — Partnership Distributions
Note 15 — Commitments and Contingencies
Note 16 — Fair Value Measurements
Note 17 — Derivative Instruments and Hedging Activities
Note 18 — Accumulated Other Comprehensive Income (Loss)
Note 19 — Other Operating Income, Net
Note 20 — Quarterly Data (unaudited)
Note 21 — Segment Information
Note 1 — Nature of Operations
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; and (3) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production, electricity generation and energy services business. In Europe, we market and distribute propane and other liquefied petroleum gases (“LPG”) and market energy products and services. We refer to UGI and its consolidated subsidiaries collectively as “the Company,” “we” or “us.”
We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the “Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30, 2017, the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances (see Note 14).
Our wholly owned subsidiary, UGI Enterprises, LLC (“Enterprises”) (formerly known as UGI Enterprises, Inc. prior to its merger with and into UGI Enterprises, LLC effective October 1, 2017), through subsidiaries, conducts (1) an LPG distribution business in France and in northern, central and eastern European countries, and (2) natural gas marketing businesses in France, Belgium and the United Kingdom, and a natural gas and electricity marketing business in the Netherlands. These businesses are conducted principally through our subsidiaries, UGI France SAS, Flaga GmbH (“Flaga”) and AvantiGas Limited. We refer to our foreign operations collectively as “UGI International.”
On May 29, 2015, UGI France SAS (a Société par actions simplifiée) (“France SAS”) (formerly UGI Bordeaux Holding), an indirect wholly owned subsidiary of UGI, purchased all of the outstanding shares of Totalgaz SAS (the “Totalgaz Acquisition”),
F-11
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
a retail distributor of LPG in France. The retail LPG distribution business of Totalgaz SAS and its subsidiaries is referred to herein as “Finagaz” and is included in our UGI International reportable segment (see Notes 4 and 21). The retail LPG distribution business of France SAS prior to the Totalgaz Acquisition is also referred to herein as “Antargaz.”
UGI Energy Services, LLC (“Energy Services, LLC”), a wholly owned subsidiary of Enterprises, conducts directly and through subsidiaries, energy marketing, midstream transmission, liquefied natural gas (“LNG”), storage, natural gas gathering, natural gas production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S. Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. A first-tier subsidiary of Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in portions of eastern and central Pennsylvania (“HVAC”). Energy Services, LLC and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation by the Federal Energy Regulatory Commission ("FERC"). We refer to the businesses of Energy Services, LLC and its subsidiaries and HVAC as “Midstream & Marketing.”
UGI Utilities, Inc. (“UGI Utilities”) conducts a natural gas distribution utility business (“Gas Utility”) directly and through its wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities in eastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission. Electric Utility is subject to regulation by the PUC. UGI Utilities is used herein as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries.
Note 2 — Summary of Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
Certain prior-year amounts have been reclassified to conform to the current-year presentation. Also, during Fiscal 2017, we corrected an immaterial error in our cylinder deposit liability account at two UGI International subsidiaries that arose prior to Fiscal 2015 which decreased opening retained earnings as of October 1, 2015 by $6.8, or 0.5%, increased other noncurrent liabilities by $10.6 and decreased deferred income tax liabilities by $3.8.
Principles of Consolidation
The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the public’s interests in the Partnership, and outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests. We eliminate intercompany accounts and transactions when we consolidate.
Entities in which we do not have control but have significant influence over operating and financial policies are accounted for by the equity method. Investments in business entities that are not publicly traded and in which we do not have significant influence over operating and financial policies are accounted for using the cost method.
Our equity and cost method investments are included in “Other assets” on the Consolidated Balance Sheets and comprise the following amounts at September 30, 2017 and 2016:
2017 | 2016 | ||||||
Equity method investments | $ | 59.1 | $ | 25.9 | |||
Cost method investments (a) | $ | 61.3 | $ | 70.1 | |||
(a) | Cost method investments at September 30, 2017 and 2016 include $7.0 and $18.0, respectively, associated with our investment in a private equity partnership that invests in renewable energy companies. |
F-12
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
A wholly owned subsidiary of UGI, UGI PennEast, LLC, and four other members comprising wholly owned subsidiaries of Southern Company, New Jersey Resources, South Jersey Industries, and Enbridge, Inc., hold 20% membership interests each in PennEast Pipeline Company, LLC (“PennEast”). PennEast is focused on constructing an approximate 118-mile natural gas pipeline from Luzerne County, Pennsylvania to the Trenton-Woodbury interconnection in New Jersey. Affiliates of all members plan to be customers of the pipeline under 15-year contracts. PennEast is considered to be an equity method investment as we have the ability to exercise significant influence, but not control, over PennEast. We are obligated to provide capital contributions based upon our ownership percentage. Our investment in PennEast at September 30, 2017 and 2016 totaled $51.0 and $17.4, respectively.
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator. For additional information regarding the effects of rate regulation on our utility operations, see Note 8.
Fair Value Measurements
The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements performed on a recurring basis principally relate to derivative instruments and investments held in supplemental executive retirement plan grantor trusts.
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:
• | Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. |
• | Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. |
• | Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. |
Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.
Derivative Instruments
Derivative instruments are reported on the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.
F-13
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Certain of our derivative instruments are designated and qualify as cash flow hedges and from time to time we also enter into net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers.
Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “Losses on foreign currency contracts, net” on the Consolidated Statements of Income.
Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, if any, are included in cash flows from operating activities on the Consolidated Statements of Cash Flows. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges, if any, are included in cash flow from operating activities while cash flows from the currency portion of such hedges, if any, are included in cash flow from financing activities.
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 17.
Foreign Currency Translation
Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income.
Revenue Recognition
Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing and our UGI International energy marketing business record revenues when energy products are delivered or services are provided to customers. Revenues from the sale of appliances and equipment are recognized at the later of sale or installation. Revenues from repair or maintenance services are recognized upon completion of services.
UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service rendered and commodities delivered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective.
We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in “Utility taxes other than income taxes” on the Consolidated Statements of Income in accordance with regulatory practice.
Accounts Receivable
Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.
LPG Delivery Expenses
Expenses associated with the delivery of LPG to customers of the Partnership and our UGI International operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as “Operating and administrative expenses” on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and UGI International delivery vehicles is classified in “Depreciation” on the Consolidated Statements of Income.
F-14
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Income Taxes
AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. AmeriGas OLP has subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation.
UGI Utilities records deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. UGI Utilities also records a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize.
We record interest on tax deficiencies and income tax penalties in “Income taxes” on the Consolidated Statements of Income. For Fiscal 2017, Fiscal 2016 and Fiscal 2015, interest income or expense recognized in “Income taxes” on the Consolidated Statements of Income was not material.
Earnings Per Common Share
Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2017, Fiscal 2016 and Fiscal 2015:
(Thousands of shares) | 2017 | 2016 | 2015 | ||||||
Weighted-average common shares outstanding for basic computation | 173,662 | 173,154 | 173,115 | ||||||
Incremental shares issuable for stock options and common stock awards (a) | 3,497 | 2,418 | 2,552 | ||||||
Weighted-average common shares outstanding for diluted computation | 177,159 | 175,572 | 175,667 | ||||||
(a) | For Fiscal 2017, Fiscal 2016 and Fiscal 2015, there were 146 shares, 38 shares and 1 share, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive. See “Equity-Based Compensation” below for a description of the impact on the calculation of diluted shares for Fiscal 2017, resulting from the adoption of new accounting guidance regarding share-based payments. |
Cash and Cash Equivalents
For cash flow purposes, cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities of three months or less when purchased.
Restricted Cash
Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
Inventories
Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for non-utility LPG and natural gas and Gas Utility natural gas; specific identification for appliances; and the first-in, first-out (“FIFO”) method for all other inventories.
F-15
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at original cost. Capitalized costs include labor, materials and other direct and indirect costs, and for certain operations subject to cost-of-service rate regulation, allowance for funds used during construction (“AFUDC”). The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.
We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives. At September 30, 2017, estimated useful lives by type were as follows:
Asset Type | Minimum Estimated Useful Life (in years) | Maximum Estimated Useful Life (in years) | ||
Buildings and improvements | 10 | 40 | ||
Equipment, primarily cylinders and tanks | 5 | 40 | ||
Electricity generation facilities | 25 | 40 | ||
Pipeline and related assets | 25 | 40 | ||
Transportation equipment and office furniture and fixtures | 3 | 12 | ||
Computer software | 1 | 10 | ||
We record depreciation expense for UGI Utilities’ plant and equipment on a straight-line basis based upon the projected service lives of the various classes of its depreciable property. The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2017, 2016 and 2015 were as follows:
2017 | 2016 | 2015 | ||||||
Gas Utility | 2.2 | % | 2.2 | % | 2.2 | % | ||
Electric Utility | 2.4 | % | 2.5 | % | 2.5 | % | ||
When UGI Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over five years, consistent with prior ratemaking treatment.
No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
Goodwill and Intangible Assets
We amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. No amortization expense of intangible assets is included in cost of sales in the Consolidated Statements of Income (see Note 11). Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships, certain tradenames and noncompete agreements, do not exceed 15 years. We review definite-lived intangible assets for impairment whenever events or changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset. Intangible assets with indefinite lives are not amortized but are tested for impairment annually (and more frequently if events or changes in circumstances between annual tests indicate that it is more likely than not that they are impaired) and written down to fair value, if impaired.
We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. Each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance simplifying the test for goodwill impairment. The adoption of the new guidance did not impact the consolidated financial statements (see Note 3).
F-16
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
For certain of our reporting units with goodwill, we assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit.
There were no accumulated impairment losses at September 30, 2017 and 2016, and no provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2017, Fiscal 2016 or Fiscal 2015.
Impairment of Long-Lived Assets and Cost Basis Investments
We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No material provisions for impairments were recorded during Fiscal 2017, Fiscal 2016 or Fiscal 2015.
We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary. During Fiscal 2017, we recorded a pre-tax loss of $11.0 associated with an other-than-temporary impairment of our investment in a private equity partnership that invests in renewable energy companies. This loss is reflected in “Other operating income, net” on the Consolidated Statements of Income. No other-than-temporary impairment losses were recognized during Fiscal 2016 or Fiscal 2015.
Deferred Debt Issuance Costs
We defer and amortize debt issuance costs and debt premiums and discounts over the expected lives of the respective debt issues considering maturity dates. Deferred debt issuance costs associated with long-term debt are reflected as a direct deduction from the carrying amount of such debt. Deferred debt issuance costs associated with line of credit facilities are classified as “Other assets” on our Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt prior to their stated maturity are generally recognized and recorded in loss on extinguishment of debt. As permitted by regulatory authorities, gains or losses resulting from refinancings of UGI Utilities’ debt are deferred and amortized over the lives of the new issuances.
Refundable Tank and Cylinder Deposits
Included in “Other noncurrent liabilities” on our Consolidated Balance Sheets are customer paid deposits on tanks and cylinders primarily owned by subsidiaries of France SAS of $279.9 and $267.2 at September 30, 2017 and 2016, respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.
Environmental Matters
We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.
Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably
F-17
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see Note 15.
Employee Retirement Plans
We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our U.S. pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 7).
Equity-Based Compensation
All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units” or “Unit awards”), are measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as a liability or as equity on our Consolidated Balance Sheets. Equity-based compensation costs associated with the portion of Unit awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with the portion of Unit awards classified as liabilities are measured based upon their estimated fair value at the grant date and remeasured as of the end of each period.
We record deferred tax assets for awards that we expect will result in deductions on our income tax returns based on the amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Prior to the adoption of new accounting guidance effective October 1, 2016, differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return were recorded in Common Stock (if the tax benefit exceeded the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeded the tax benefit and no tax windfall pool existed from previous awards). We calculated this tax windfall pool using the shortcut method.
Effective October 1, 2016, we adopted Accounting Standards Update (“ASU”) No. 2016-09, “Improvements to Employee Share-Based Payments Accounting” (“ASU 2016-09”) issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. In addition, assumed proceeds under the treasury stock method used for computing diluted shares outstanding no longer include windfall tax benefits in the diluted shares calculation.
In accordance with the required prospective method of transition relating to excess tax benefits, we recognized income tax benefits of $10.3 related to excess tax benefits for share-based awards that were exercised or vested during Fiscal 2017. This amount is reflected in “Income taxes” on the Consolidated Statements of Income. In addition, upon the adoption of ASU 2016-09, we recorded a $4.9 increase to retained earnings and decrease to deferred income tax liabilities for excess tax benefits related to prior period unrecognized state tax benefits. We elected to use the prospective method of transition for classifying excess tax benefits as cash flow from operating activities on the Consolidated Statements of Cash Flows and prior periods were not adjusted. We have historically presented employee taxes paid for net settled awards as a financing activity on the Consolidated Statements of Cash Flows and therefore there is no transition impact from this requirement. In addition, as provided by the new guidance, we elected to account for forfeitures of share-based payments when they occur.
For additional information on our equity-based compensation plans and related disclosures, see Note 13.
F-18
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 3 — Accounting Changes
Adoption of New Accounting Standards
Definition of a Business. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance which clarifies the definition of a business. The new guidance is intended to assist entities with evaluating whether a set of transferred assets and activities comprises a business. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements.
Cash Flow Classification. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance on the classification of certain cash receipts and payments in the statement of cash flows. The guidance is generally required to be applied retrospectively. The adoption of the new guidance did not impact our consolidated financial statements.
Goodwill Impairment. During the fourth quarter of Fiscal 2017, the Company adopted new accounting guidance regarding the test for goodwill impairment. Under the new accounting guidance, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements.
Employee Share-based Payments. Effective October 1, 2016, the Company adopted ASU 2016-09 regarding share-based payments. See Note 2 for a detailed description of the impact of the new guidance.
Equity Method Accounting. Effective October 1, 2016, the Company adopted new accounting guidance regarding the accounting for an investment that qualifies for use of the equity method as a result of an increase in an investor’s level of ownership or influence. The guidance requires that the equity method investor add the cost of acquiring an additional interest to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date such investment qualifies for equity method accounting. The new guidance eliminates the previous requirement in such circumstances to apply the effects of the equity method of accounting retrospectively. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements.
Accounting Standards Not Yet Adopted
Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required only prospectively. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.
Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.
Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.
F-19
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities.
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption.
The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue by UGI Utilities.
The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.
Note 4 — Acquisitions
Acquisition of Totalgaz
On May 29, 2015 (the “Acquisition Date”), UGI, through its wholly owned indirect subsidiary, France SAS, acquired all of the outstanding shares of Totalgaz SAS, a retail distributor of LPG in France, for €451.8 ($496.6) in cash, including €30.0 ($33.0) for estimated Acquisition Date working capital. In November 2015, France SAS received €1.1 ($1.2) of cash as a result of the completion of the final working capital amount. The Totalgaz Acquisition was consummated pursuant to the terms of a Share Purchase Agreement dated November 11, 2014, between Total Marketing Services, a subsidiary of global energy company, Total, and France SAS. The Totalgaz Acquisition nearly doubled our retail LPG distribution business in France and was consistent with our growth strategies, one of which is to grow our core business through acquisitions. The Totalgaz Acquisition was funded from existing cash balances and a portion of loan proceeds from France SAS’s May 29, 2015, issuance of a €600 term loan under its 2015 Senior Facilities Agreement (see Note 5).
F-20
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The Company accounted for the Totalgaz Acquisition using the acquisition method. The components of the final Totalgaz purchase price allocation are as follows:
Assets acquired: | |||
Cash | $ | 86.8 | |
Accounts receivable (a) | 170.3 | ||
Prepaid expenses and other current assets | 11.0 | ||
Property, plant and equipment | 375.6 | ||
Intangible assets (b) | 91.3 | ||
Other assets | 21.4 | ||
Total assets acquired | $ | 756.4 | |
Liabilities assumed: | |||
Accounts payable | 109.2 | ||
Other current liabilities | 103.5 | ||
Deferred income taxes | 117.5 | ||
Other noncurrent liabilities | 113.4 | ||
Total liabilities assumed | $ | 443.6 | |
Goodwill | 183.8 | ||
Net consideration transferred (including working capital adjustments) | $ | 496.6 | |
(a) | Approximates the gross contractual amounts of receivables acquired. |
(b) | Comprises $79.3 of customer relationships and $12.0 of tradenames ($8.3 of which is subject to amortization), having average amortization periods of 15 years. |
We allocated the purchase price of the acquisition to identifiable intangible assets and property, plant and equipment based on estimated fair values as follows:
• | Customer relationships were valued using a multi-period, excess earnings method. Key assumptions used in this method include discount rates, growth rates and cash flow projections. These assumptions are most sensitive and susceptible to change as they require significant management judgment; |
• | Tradenames were valued using the relief from royalty method, which estimates our theoretical royalty savings from ownership of the tradenames. Key assumptions used in this method include discount rates, royalty rates, growth rates and sales projections. These assumptions are most sensitive and susceptible to change as they require significant management judgment; and |
• | Property, plant and equipment were valued based on estimated fair values primarily using depreciated replacement cost and market value methods. |
The excess of the purchase price for the Totalgaz Acquisition over the fair values of the assets acquired and liabilities assumed has been reflected as goodwill, assigned to the UGI International reportable segment, and results principally from anticipated synergies and value creation resulting from the Company’s combined LPG businesses in France. The goodwill is not deductible for income tax purposes.
The Company recognized $16.1 of direct transaction-related costs associated with the Totalgaz Acquisition during Fiscal 2015, which are reflected primarily in “Operating and administrative expenses” on the Consolidated Statements of Income. The acquisition of Totalgaz did not have a material impact on the Company’s revenues or net income attributable to UGI for the year ended September 30, 2015.
F-21
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The following table presents unaudited pro forma revenues, net income attributable to UGI Corporation and earnings per share data for Fiscal 2015 as if the Totalgaz Acquisition had occurred on October 1, 2014. The unaudited pro forma consolidated information reflects the historical results of Totalgaz SAS and its subsidiaries after giving effect to adjustments directly attributable to the transaction, including depreciation, amortization, interest expense, intercompany eliminations and related income tax effects. The unaudited pro forma net income also reflects the effects of the issuance of the €600 term loan under France SAS’s 2015 Senior Facilities Agreement and the associated repayment of the term loan outstanding under Antargaz’ 2011 Senior Facilities Agreement as if such transactions had occurred on October 1, 2014. Amounts in the table below exclude costs associated with extinguishment of debt under Antargaz’ 2011 Senior Facilities Agreement (see Note 5):
2015 | |||||||
As Reported | Pro Forma Adjusted | ||||||
Revenues | $ | 6,691.1 | $ | 7,065.8 | |||
Net income attributable to UGI Corporation | $ | 281.0 | $ | 341.2 | |||
Earnings per common share attributable to UGI Corporation stockholders: | |||||||
Basic | $ | 1.62 | $ | 1.97 | |||
Diluted | $ | 1.60 | $ | 1.94 | |||
The unaudited pro forma consolidated information is not necessarily indicative of the results that would have occurred had the Totalgaz Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results.
Other Acquisitions
During Fiscal 2017, UGI International acquired an energy marketing business with operations in the Netherlands and an LPG distribution business with operations in Sweden, and AmeriGas Propane acquired several retail propane distribution businesses. During Fiscal 2016, UGI International acquired several LPG distribution businesses with operations in Austria, Norway and the United Kingdom, and AmeriGas Propane acquired several retail propane distribution businesses. During Fiscal 2015, in addition to the Totalgaz Acquisition in France, UGI International acquired an LPG distribution business with operations in Hungary, and AmeriGas Propane acquired several retail propane distribution businesses.
Total cash paid and liabilities incurred in connection with these acquisitions were as follows:
2017 | 2016 | 2015 | ||||||||||||||||||||||
AmeriGas Propane | UGI International | AmeriGas Propane | UGI International | AmeriGas Propane | UGI International | |||||||||||||||||||
Total cash paid | $ | 36.8 | $ | 99.7 | $ | 37.6 | $ | 24.1 | $ | 20.8 | $ | 17.6 | ||||||||||||
Liabilities incurred (a) | 10.8 | 20.6 | 11.8 | — | 4.2 | — | ||||||||||||||||||
Total purchase price | $ | 47.6 | $ | 120.3 | $ | 49.4 | $ | 24.1 | $ | 25.0 | $ | 17.6 | ||||||||||||
(a) | Reflects notes payable to seller and liabilities associated with noncompete agreements. |
Note 5 — Debt
Significant Financing Activities
AmeriGas Propane. During Fiscal 2017, AmeriGas Partners issued, in underwritten offerings, $700 principal amount of 5.50% Senior Notes due May 2025 and $525 principal amount of 5.75% Senior Notes due May 2027 (collectively, the “AmeriGas 2017 Senior Notes”). The AmeriGas 2017 Senior Notes rank equally with AmeriGas Partners’ existing outstanding senior notes. The net proceeds from the issuance of the AmeriGas 2017 Senior Notes were used (1) for the early repayment, pursuant to tender offers and notices of redemption, of all of AmeriGas Partners’ 7.00% Senior Notes, having an aggregate principal balance of $980.8 plus accrued and unpaid interest and early redemption premiums, and (2) for general corporate purposes.
F-22
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
During Fiscal 2016, AmeriGas Partners issued in an underwritten offering $675 principal amount of 5.625% Senior Notes due May 2024 and $675 principal amount of 5.875% Senior Notes due August 2026 (collectively, the “AmeriGas 2016 Senior Notes”). The AmeriGas 2016 Senior Notes rank equally with AmeriGas Partners’ existing outstanding senior notes. The net proceeds from the issuance of the AmeriGas 2016 Senior Notes were used (1) for the early repayment, pursuant to tender offers and notices of redemption, of all of AmeriGas Partners’ previously issued 6.50% Senior Notes, 6.75% Senior Notes and 6.25% Senior Notes, having an aggregate principal balance of $1,270.0 plus accrued and unpaid interest and early redemption premiums and (2) for general corporate purposes.
In connection with the early repayments of AmeriGas’ Senior Notes, during Fiscal 2017 and 2016, the Partnership recognized pre-tax losses which are reflected in “Loss on extinguishments of debt” on the Consolidated Statements of Income and comprise the following:
2017 | 2016 | ||||||
Early redemption premiums | $ | 51.3 | $ | 39.6 | |||
Write-off of unamortized debt issuance costs | 8.4 | 9.3 | |||||
Loss on extinguishments of debt | $ | 59.7 | $ | 48.9 | |||
UGI International. In April 2015, France SAS entered into a new five-year Senior Facilities Agreement with a consortium of banks consisting of a €600 variable-rate term loan and a €60 revolving credit facility (“2015 Senior Facilities Agreement”) in anticipation of its then-pending acquisition of Totalgaz, which was consummated in May 2015 (see Note 4). On May 29, 2015, France SAS borrowed €600 ($659.6) under the 2015 Senior Facilities Agreement. The term loan proceeds were used (1) to fund a portion of the Totalgaz Acquisition, including related fees and expenses; (2) to make a capital contribution from France SAS to its wholly owned subsidiary, AGZ Holding, to prepay €342 principal amount, plus accrued interest, outstanding under Antargaz’ 2011 Senior Facilities Agreement due March 2016 (the “2011 Senior Facilities Agreement”); (3) to settle Antargaz’ existing pay-fixed, receive-variable interest rate swaps associated with the 2011 Senior Facilities Agreement; and (4) for general corporate purposes. As a result of prepaying the term loan outstanding under the 2011 Senior Facilities Agreement and concurrently settling the associated pay-fixed, receive-variable interest rate swaps, we recorded a pre-tax loss of $10.3 comprising a $9.0 loss on interest rate swaps and the write-off of $1.3 of debt issuance costs. These amounts are included in “Interest expense” on the Fiscal 2015 Consolidated Statement of Income.
In October 2015, Flaga entered into a €100.8 Credit Facility Agreement (“Flaga Credit Facility Agreement”) with a bank. The Flaga Credit Facility Agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility, a €25 guarantee facility and a €45.8 term loan facility. Concurrent with entering into the Flaga Credit Facility Agreement, Flaga terminated its then-existing €46 multi-currency working capital facility.
In October 2015, borrowings under the Flaga Credit Facility Agreement’s €45.8 term loan were used to refinance a €19.1 ($21.4) term loan and a €26.7 ($29.8) term loan. Because the cash flows associated with the refinancing of the then-existing term loans were with the same bank, such cash flows have been reflected “net” on the Consolidated Statement of Cash Flows.
In September 2015, Flaga terminated its then-existing $52 U.S. dollar-denominated variable-rate term loan due September 2016 and concurrently entered into a $59.1 U.S. dollar-denominated variable-rate term loan with the same bank. The $59.1 term loan matures in September 2018. Because the cash flows from the termination of the $52 term loan and the concurrent issuance of the $59.1 term loan were with the same bank, such cash flows have been reflected “net” in the financing activities section of the Fiscal 2015 Consolidated Statement of Cash Flows.
UGI Utilities. In April 2016, UGI Utilities entered into a Note Purchase Agreement (the “2016 Note Purchase Agreement”) with a consortium of lenders. Pursuant to the 2016 Note Purchase Agreement, UGI Utilities issued $100 aggregate principal amount of 2.95% Senior Notes due June 2026 and $200 aggregate principal amount of 4.12% Senior Notes due September 2046 in June 2016 and September 2016, respectively. In October 2016, UGI Utilities issued $100 aggregate principal amount of 4.12% Senior Notes due October 2046. The net proceeds of the issuance of these senior notes were used (1) to repay UGI Utilities’ maturing 5.75% Senior Notes, 7.37% Medium-term Notes and 5.64% Medium-term Notes; (2) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and the information technology initiatives; and (3) for general corporate purposes. The UGI Utilities Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt.
F-23
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
On October 31, 2017, UGI Utilities entered into a $125 unsecured term loan (the “Utilities Term Loan”) with a group of banks which initially matures on October 30, 2018. Such maturity will be automatically extended to October 30, 2022 once UGI Utilities delivers to the agent a copy of the securities certificate registered with the PUC authorizing UGI Utilities’ incurring indebtedness with such maturity date. Proceeds from the Utilities Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Utilities Term Loan is payable in equal quarterly installments of $1.6 with the balance of the principal being due and payable in full on the maturity date. Under the Utilities Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The Utilities Term Loan requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.
F-24
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Long-term Debt
Long-term debt comprises the following at September 30:
2017 | 2016 | ||||||
AmeriGas Propane: | |||||||
AmeriGas Partners Senior Notes: | |||||||
5.50% due May 2025 | $ | 700.0 | $ | — | |||
5.875% due August 2026 | 675.0 | 675.0 | |||||
5.625% due May 2024 | 675.0 | 675.0 | |||||
5.75% due May 2027 | 525.0 | — | |||||
7.00%, due May 2022 | — | 980.8 | |||||
HOLP Senior Secured Notes, including unamortized premium of $0.4 and $0.7, respectively (a) | 11.3 | 15.2 | |||||
Other | 17.3 | 14.2 | |||||
Unamortized debt issuance costs | (31.3 | ) | (26.6 | ) | |||
Total AmeriGas Propane | 2,572.3 | 2,333.6 | |||||
UGI International: | |||||||
France SAS Senior Facilities term loan, due through April 2020 (b) | 708.9 | 674.4 | |||||
Flaga variable-rate term loan, due October 2020 (c) | 54.1 | 51.4 | |||||
Flaga U.S. dollar variable-rate term loan, due September 2018 (d) | 59.1 | 59.1 | |||||
Other | 21.3 | 1.4 | |||||
Unamortized debt issuance costs | (4.6 | ) | (6.7 | ) | |||
Total UGI International | 838.8 | 779.6 | |||||
UGI Utilities: | |||||||
Senior Notes: | |||||||
4.12%, due September 2046 | 200.0 | 200.0 | |||||
4.98%, due March 2044 | 175.0 | 175.0 | |||||
4.12%, due October 2046 | 100.0 | — | |||||
6.21%, due September 2036 | 100.0 | 100.0 | |||||
2.95%, due June 2026 | 100.0 | 100.0 | |||||
Medium-Term Notes: | |||||||
6.13%, due October 2034 | 20.0 | 20.0 | |||||
6.50%, due August 2033 | 20.0 | 20.0 | |||||
5.67%, due January 2018 | 20.0 | 20.0 | |||||
7.25%, due November 2017 | 20.0 | 20.0 | |||||
6.17%, due June 2017 | — | 20.0 | |||||
Unamortized debt issuance costs | (3.9 | ) | (3.5 | ) | |||
Total UGI Utilities | 751.1 | 671.5 | |||||
Other | 9.9 | 10.8 | |||||
Total long-term debt | 4,172.1 | 3,795.5 | |||||
Less: current maturities | (177.5 | ) | (29.5 | ) | |||
Total long-term debt due after one year | $ | 3,994.6 | $ | 3,766.0 | |||
(a) | At September 30, 2017 and 2016, the effective interest rate on the HOLP Senior Secured Notes was 6.75%. These notes are collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash. |
(b) | Borrowings bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate, which euribor rate has a floor of 0.0%. The margin on term loan borrowings (which ranges from 1.60% to 2.70%) is dependent upon the ratio of France SAS’ consolidated total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement. At September 30, 2017 and 2016, such margin was 1.90%. France SAS has entered into pay-fixed, receive-variable interest rate swaps through April 30, 2019, to fix the underlying euribor rate on term loan borrowings at 0.18%. At |
F-25
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
September 30, 2017 and 2016, the effective interest rate on the term loan was approximately 2.10%. Principal amounts outstanding under the term loan are due as follows: €60 due April 2018; €60 due April 2019; and €480 due April 2020.
(c) | Borrowings bear interest at three-month euribor rates, plus a margin and other fees. The margin and other fees range from 1.20% to 2.60% and are based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined, as well as fees defined by the local jurisdiction. Flaga has entered into pay-fixed, receive-variable interest rate swaps that generally fix the underlying market rate at 0.23%, effective October 2016. The effective interest rate on this term loan at September 30, 2017 and 2016, was 1.80% and 2.11%, respectively. |
(d) | Borrowings bear interest at a one-month LIBOR rate plus a margin of 1.125%. Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments by entering into a cross-currency swap arrangement with a bank. At September 30, 2017 and 2016, the effective interest rate on this term loan was 0.87%. |
Scheduled principal repayments of long-term debt due in fiscal years 2018 to 2022 follows:
2018 | 2019 | 2020 | 2021 | 2022 | |||||||||||||||
AmeriGas Propane | $ | 8.6 | $ | 8.2 | $ | 7.5 | $ | 3.2 | $ | 1.2 | |||||||||
UGI International | 130.3 | 71.5 | 567.1 | 54.1 | 20.4 | ||||||||||||||
UGI Utilities | 40.0 | — | — | — | — | ||||||||||||||
Other | 0.7 | 0.8 | 0.8 | 0.9 | 0.9 | ||||||||||||||
Total | $ | 179.6 | $ | 80.5 | $ | 575.4 | $ | 58.2 | $ | 22.5 | |||||||||
Credit Facilities and Short-term Borrowings
Information about the Company’s principal credit agreements (excluding Energy Services, LLC’s Receivables Facility which is discussed below) as of September 30, 2017 and 2016, is presented in the following table. Borrowings outstanding under these agreements are classified as “Short-term borrowings” on the Consolidated Balance Sheets.
Expiration Date | Total Capacity | Borrowings Outstanding | Letters of Credit and Guarantees Outstanding | Available Borrowing Capacity | Weighted Average Interest Rate - End of Year | ||||||||||||||||
September 30, 2017 | |||||||||||||||||||||
AmeriGas OLP (a) | June 2019 | $ | 525.0 | $ | 140.0 | $ | 67.2 | $ | 317.8 | 3.74 | % | ||||||||||
France SAS (b) | April 2020 | € | 60.0 | — | — | € | 60.0 | N.A. | |||||||||||||
Flaga (c) | October 2020 | € | 55.0 | — | € | 6.5 | € | 48.5 | N.A. | ||||||||||||
Energy Services, LLC (d) | March 2021 | $ | 240.0 | — | — | $ | 240.0 | N.A. | |||||||||||||
UGI Utilities (e) | March 2020 | $ | 300.0 | $ | 170.0 | $ | 2.0 | $ | 128.0 | 2.11 | % | ||||||||||
September 30, 2016 | |||||||||||||||||||||
AmeriGas OLP (a) | June 2019 | $ | 525.0 | $ | 153.2 | $ | 67.2 | $ | 304.6 | 2.79 | % | ||||||||||
France SAS (b) | April 2020 | € | 60.0 | — | — | € | 60.0 | N.A. | |||||||||||||
Flaga (c) | October 2020 | € | 55.0 | — | € | 9.6 | € | 45.4 | N.A. | ||||||||||||
Energy Services, LLC (d) | March 2021 | $ | 240.0 | $ | — | — | $ | 240.0 | N.A. | ||||||||||||
UGI Utilities (e) | March 2020 | $ | 300.0 | $ | 112.5 | $ | 2.0 | $ | 185.5 | 1.42 | % | ||||||||||
(a) | The AmeriGas OLP Credit Agreement includes a $125 sublimit for letters of credit and permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, or one-, two-, three-, or six-month Eurodollar Rate, as defined, plus a margin. The applicable margin on base rate borrowings ranges from 0.50% to 1.50%; the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.50%; and the facility fee ranges from 0.30% to 0.45%. The aforementioned margins and facility fees are dependent upon AmeriGas Partners’ ratio of debt to EBITDA, as defined. |
(b) | Borrowings under the 2015 Senior Facilities Agreement revolving credit facility bear interest at market rates (one-, two-, three-, or six-month euribor) plus a margin. The margin on credit facility borrowings ranges from 1.45% to 2.55% based upon France SAS’s ratio of consolidated total net debt to EBITDA, as defined. |
F-26
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
(c) | The Flaga Credit Facility Agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility and a €25 guarantee facility. Revolving credit facility borrowings bear interest at market rates (generally one, three or six-month euribor rates) plus margins. The margins on revolving facility borrowings, which range from 1.45% to 3.65%, are based upon the actual currency borrowed and certain consolidated equity, return on assets and debt to EBITDA ratios, each as defined. Facility fees on the unused amount of the revolving credit facility are 30% of the lowest applicable margin. Guarantees outstanding reduce the available capacity on the €25 guarantee facility. |
(d) | The Energy Services, LLC Credit Agreement (“Energy Services Credit Agreement”) includes a $50 sublimit for letters of credit and can be used for general corporate purposes of Energy Services, LLC and its subsidiaries. Energy Services, LLC may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined, does not exceed 3.00 to 1.00. Borrowings bear interest at either (i) the Alternate Base Rate plus a margin or (ii) a rate derived from LIBOR (“Adjusted LIBOR”) plus a margin. The Alternate Base Rate, as defined, is the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, and (c) Adjusted LIBOR plus 1.00%. The margin on such borrowings is currently 2.25%. The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services, LLC. |
(e) | The UGI Utilities Credit Agreement includes a $100 sublimit for letters of credit. Borrowings bear interest at prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. |
Accounts Receivable Securitization Facility. Energy Services, LLC has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2018. The Receivables Facility, as amended, provides Energy Services, LLC with the ability to borrow up to $150 of eligible receivables during the period November to April, and up to $75 of eligible receivables during the period May to October. Energy Services, LLC 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, LLC 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. Amounts sold to the bank are reflected as “Short-term borrowings” on the Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services, LLC 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. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses on sales of receivables to the bank during Fiscal 2017, Fiscal 2016 and Fiscal 2015, which amounts are included in “Interest expense” on the Consolidated Statements of Income, were not material.
Information regarding the amounts of trade receivables transferred to ESFC and the amounts sold to the bank during Fiscal 2017, Fiscal 2016 and Fiscal 2015, as well as the balance of ESFC trade receivables at September 30, 2017, 2016 and 2015 follows:
2017 | 2016 | 2015 | ||||||||||
Trade receivables transferred to ESFC during the year | $ | 1,017.3 | $ | 756.4 | $ | 1,037.8 | ||||||
ESFC trade receivables sold to the bank during the year | 243.0 | 204.0 | 306.5 | |||||||||
ESFC trade receivables - end of year (a) | 44.8 | 35.7 | 44.1 | |||||||||
(a) | At September 30, 2017 and 2016, the amounts of ESFC trade receivables sold to the bank were $39.0 and $25.5, respectively, and are reflected as “Short-term borrowings” on the Consolidated Balance Sheets. |
Restrictive Covenants
Our long-term debt and credit facility agreements generally contain customary covenants and default provisions which may include, among other things, restrictions on the incurrence of additional indebtedness and also restrict liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions.
The AmeriGas Propane Credit Agreement requires that AmeriGas OLP and AmeriGas Partners maintain ratios of total indebtedness to EBITDA, as defined, below certain thresholds. In addition, the Partnership must maintain a minimum ratio of EBITDA to
F-27
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
interest expense, as defined and as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result therefrom, AmeriGas OLP is permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter.
Under the AmeriGas Partners Senior Notes Indentures, AmeriGas Partners is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. At September 30, 2017, these restrictions did not limit the amount of Available Cash. See Note 14 for the definition of Available Cash included in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P., as amended (“Partnership Agreement”).
The HOLP Senior Secured Notes financial covenants require AmeriGas OLP to maintain a ratio of Consolidated Funded Indebtedness to Consolidated EBITDA (as defined) below certain thresholds and to maintain a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense (as defined).
The 2015 Senior Facilities Agreement requires France SAS and its consolidated subsidiaries to maintain a ratio of total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement, that shall not exceed 3.50 to 1.00 as determined semiannually. France SAS will generally be permitted to make restricted payments, such as dividends, if no event of default exists or would exist upon payment of such dividend.
Borrowings under the Flaga Credit Facility Agreement are guaranteed by UGI. The Flaga U.S. dollar term loan and associated interest rate and cross-currency swap agreements are guaranteed by UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending banks may accelerate repayment of the debt.
The UGI Utilities Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. Certain of UGI Utilities’ Senior Notes contain financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
The Energy Services Credit Agreement requires that Energy Services, LLC and subsidiaries not exceed a ratio of total indebtedness to EBITDA, as defined, of 3.50 to 1.00, and maintain a minimum ratio of EBITDA to interest expense, as defined, of 3.50 to 1.00.
Restricted Net Assets
At September 30, 2017, the amount of net assets of UGI’s consolidated subsidiaries that were restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $1,500.
Note 6 — Income Taxes
Income before income taxes comprises the following:
2017 | 2016 | 2015 | |||||||||
Domestic | $ | 527.3 | $ | 518.9 | $ | 552.3 | |||||
Foreign | 174.1 | 191.1 | 39.5 | ||||||||
Total income before income taxes | $ | 701.4 | $ | 710.0 | $ | 591.8 | |||||
F-28
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The provisions for income taxes consist of the following:
2017 | 2016 | 2015 | |||||||||
Current expense (benefit): | |||||||||||
Federal | $ | (2.7 | ) | $ | 44.2 | $ | 97.1 | ||||
State | 14.0 | 20.9 | 32.2 | ||||||||
Foreign | 56.2 | 78.7 | 36.0 | ||||||||
Investment tax credit | — | — | (1.2 | ) | |||||||
Total current expense | 67.5 | 143.8 | 164.1 | ||||||||
Deferred expense (benefit): | |||||||||||
Federal | 125.8 | 81.2 | 28.1 | ||||||||
State | 16.4 | 1.3 | 2.9 | ||||||||
Foreign | (31.8 | ) | (4.8 | ) | (17.0 | ) | |||||
Investment tax credit amortization | (0.3 | ) | (0.3 | ) | (0.3 | ) | |||||
Total deferred expense | 110.1 | 77.4 | 13.7 | ||||||||
Total income tax expense | $ | 177.6 | $ | 221.2 | $ | 177.8 | |||||
Federal income taxes for Fiscal 2017, Fiscal 2016 and Fiscal 2015 are net of foreign tax credits of $40.9, $25.6 and $63.0, respectively.
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:
2017 | 2016 | 2015 | ||||||
U.S. federal statutory tax rate | 35.0 | % | 35.0 | % | 35.0 | % | ||
Difference in tax rate due to: | ||||||||
Noncontrolling interests not subject to tax | (4.3 | ) | (6.2 | ) | (7.9 | ) | ||
State income taxes, net of federal benefit | 2.9 | 3.0 | 3.3 | |||||
Valuation allowance adjustments | (1.1 | ) | (0.9 | ) | 0.8 | |||
Effects of foreign operations | (1.1 | ) | 0.6 | 0.2 | ||||
Deferred tax effects of French tax rate change | (4.1 | ) | — | — | ||||
Excess tax benefits on share-based payments | (1.3 | ) | — | — | ||||
Other, net | (0.7 | ) | (0.3 | ) | (1.4 | ) | ||
Effective tax rate | 25.3 | % | 31.2 | % | 30.0 | % | ||
Earnings of the Company’s foreign subsidiaries are generally subject to U.S. taxation upon repatriation to the U.S. and the Company’s tax provisions reflect the related incremental U.S. tax except for certain foreign subsidiaries whose unremitted earnings are considered to be indefinitely reinvested. At September 30, 2017, unremitted earnings of foreign subsidiaries of approximately $119.7 were deemed to be indefinitely reinvested. No deferred tax liability has been recognized with regard to the remittance of such earnings. Because of the availability of U.S. foreign tax credits, it is likely no U.S. tax would be due if such earnings were repatriated.
Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2017, Fiscal 2016 and Fiscal 2015, the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $2.5, $1.3 and $1.5, respectively.
F-29
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Deferred tax liabilities (assets) comprise the following at September 30:
2017 | 2016 | ||||||
Excess book basis over tax basis of property, plant and equipment | $ | 975.8 | $ | 873.9 | |||
Investment in AmeriGas Partners | 326.8 | 323.2 | |||||
Intangible assets and goodwill | 98.2 | 87.1 | |||||
Utility regulatory assets | 132.2 | 148.3 | |||||
Other | 11.7 | 11.9 | |||||
Gross deferred tax liabilities | 1,544.7 | 1,444.4 | |||||
Pension plan liabilities | (57.7 | ) | (79.7 | ) | |||
Employee-related benefits | (65.4 | ) | (63.1 | ) | |||
Operating loss carryforwards | (30.9 | ) | (31.5 | ) | |||
Foreign tax credit carryforwards | (106.1 | ) | (105.1 | ) | |||
Utility regulatory liabilities | (9.3 | ) | (13.9 | ) | |||
Derivative instruments | (1.7 | ) | (14.7 | ) | |||
Utility environmental liabilities | (22.2 | ) | (22.8 | ) | |||
Other | (27.8 | ) | (28.3 | ) | |||
Gross deferred tax assets | (321.1 | ) | (359.1 | ) | |||
Deferred tax assets valuation allowance | 107.1 | 114.3 | |||||
Net deferred tax liabilities | $ | 1,330.7 | $ | 1,199.6 | |||
In December 2016, the French Parliament approved the Finance Bill for 2017 and amended the Finance Bill for 2016 (collectively the “Finance Bills”). The Finance Bills, among other things, will reduce the French corporate income tax rate from the current 34.43% to 28.92%, effective for fiscal years starting after January 1, 2020 (Fiscal 2021). As a result of the future income tax rate reduction, during Fiscal 2017 the Company reduced its net deferred income tax labilities and recognized a deferred tax benefit of $29.0.
At September 30, 2017, foreign net operating loss carryforwards principally relating to Flaga, UGI International Holdings BV and certain subsidiaries of France SAS totaled $24.5, $2.5 and $22.6, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $187.9 and expire through 2037. We also have operating loss carryforwards of $19.7 for certain operations of AmeriGas Propane that expire through 2037. At September 30, 2017, deferred tax assets relating to operating loss carryforwards include $5.6 for Flaga, $7.8 for certain subsidiaries of France SAS, $0.7 for UGI International Holdings BV, $6.8 for AmeriGas Propane and $10.0 for certain other subsidiaries.
The valuation allowance for all deferred tax assets decreased by $7.2 in Fiscal 2017 due to the reversal of $7.6 of valuation allowances associated with future utilization of foreign tax credits and a decrease in foreign operating loss carryforwards of $1.5, partially offset by an increase in foreign tax credits of $1.1, and an increase in state capital loss carryforwards of $0.8. A valuation allowance of $0.2 remains for deferred tax assets related to other state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries because, on a state reportable basis, it is more likely than not that these assets will expire unused. A valuation allowance of $7.5 also exists for deferred tax assets related to certain subsidiaries of France SAS, and certain subsidiaries of Flaga and UGI International Holdings BV.
In Fiscal 2017, the Company reversed $7.6 in valuation allowances associated with foreign tax credit carryforwards whose utilization before expiration had previously not met a more-likely-than-not threshold. In Fiscal 2016, the Company reversed valuation allowances associated with certain state tax net operating loss carryforwards of approximately $5.5 as a result of certain tax planning strategies that were related to legal entity classification. Operating activities and tax deductions related to the exercise of non-qualified stock options contributed to the state net operating losses disclosed above. Prior to the adoption of ASU 2016-09, we would first recognize the utilization of state net operating losses from operations (which exclude the impact of tax deductions for exercises of non-qualified stock options) to reduce income tax expense. Then, to the extent state net operating loss carryforwards, if realized, related to non-qualified stock option deductions, the resulting benefits were credited to UGI Corporation stockholders’
F-30
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
equity. The Fiscal 2016 table of deferred tax assets and liabilities does not include $7.7 of deferred tax assets and a corresponding valuation allowance for unrealized state tax benefits for share-based compensation deductions.
We have foreign tax credit carryforwards of approximately $106.1 expiring through 2027 resulting from the actual and planned repatriation of France SAS’s accumulated earnings since acquisition which are includable in U.S. taxable income. Prior to Fiscal 2017, we expected that these credits would expire unused and a valuation allowance had been provided for the entire foreign tax credit carryforward amount. The Company continuously monitors the potential utilization of these credits and performs the appropriate weighing of positive and negative evidence in reaching a conclusion of whether utilization reaches a level of more likely than not. In Fiscal 2017, the Company concluded it was more likely than not that $98.5 of the credits will expire before utilization and therefore reversed $7.6 of the prior year valuation allowance against these credits. The amount of the deferred tax asset considered realizable could be adjusted if estimates of future taxable income during the carryforward period are reduced or increased.
We conduct business and file tax returns in the U.S., numerous states, local jurisdictions and in France and certain other European countries. Our U.S. federal income tax returns are settled through the 2013 tax year, our French tax returns are settled through the 2013 tax year, our Austrian tax returns are settled through 2014 and our other European tax returns are effectively settled for various years from 2008 to 2015. State and other income tax returns in the U.S. are generally subject to examination for a period of three to five years after the filing of the respective returns.
As of September 30, 2017, we have unrecognized income tax benefits totaling $12.2 including related accrued interest of $0.5. If these unrecognized tax benefits were subsequently recognized, $8.1 would be recorded as a benefit to income taxes on the Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. There is no material change expected in unrecognized tax benefits and related interest in the next twelve months.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
2017 | 2016 | 2015 | |||||||||
Unrecognized tax benefits — beginning of year | $ | 7.2 | $ | 3.2 | $ | 2.4 | |||||
Additions for tax positions of the current year | 1.9 | 2.2 | 0.9 | ||||||||
Additions for tax positions taken in prior years | 4.6 | 2.3 | 0.5 | ||||||||
Settlements with tax authorities/statute lapses | (1.5 | ) | (0.5 | ) | (0.6 | ) | |||||
Unrecognized tax benefits — end of year | $ | 12.2 | $ | 7.2 | $ | 3.2 | |||||
Note 7 — Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans
In the U.S., we sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). U.S. Pension Plan benefits are based on years of service, age and employee compensation.
We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, certain UGI International employees in France, Belgium and the Netherlands are covered by defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the UGI International plans, such amounts are not material.
The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the U.S. Pension Plan and the UGI International pension plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 2017 and 2016. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Change in benefit obligations: | |||||||||||||||
Benefit obligations — beginning of year | $ | 707.7 | $ | 614.7 | $ | 30.9 | $ | 25.4 | |||||||
Service cost | 11.9 | 10.1 | 1.0 | 0.7 | |||||||||||
Interest cost | 25.0 | 26.8 | 0.8 | 0.9 | |||||||||||
Actuarial (gain) loss | (19.6 | ) | 83.3 | (4.8 | ) | 6.6 | |||||||||
Plan amendments | 1.2 | — | — | (1.5 | ) | ||||||||||
Curtailment | (3.6 | ) | (1.4 | ) | (0.4 | ) | (0.3 | ) | |||||||
Foreign currency | 2.9 | 0.1 | 0.4 | — | |||||||||||
Benefits paid | (27.7 | ) | (25.9 | ) | (0.9 | ) | (0.9 | ) | |||||||
Benefit obligations — end of year | $ | 697.8 | $ | 707.7 | $ | 27.0 | $ | 30.9 | |||||||
Change in plan assets: | |||||||||||||||
Fair value of plan assets — beginning of year | $ | 493.7 | $ | 453.8 | $ | 13.7 | $ | 12.5 | |||||||
Actual gain on plan assets | 47.0 | 53.4 | 1.3 | 1.3 | |||||||||||
Foreign currency | 1.6 | 0.1 | — | — | |||||||||||
Employer contributions | 14.6 | 11.4 | 0.6 | 0.6 | |||||||||||
Benefits paid | (27.7 | ) | (25.0 | ) | (0.8 | ) | (0.7 | ) | |||||||
Fair value of plan assets — end of year | $ | 529.2 | $ | 493.7 | $ | 14.8 | $ | 13.7 | |||||||
Funded status of the plans — end of year | $ | (168.6 | ) | $ | (214.0 | ) | $ | (12.2 | ) | $ | (17.2 | ) | |||
Assets (liabilities) recorded in the balance sheet: | |||||||||||||||
Assets in excess of liabilities — included in other noncurrent assets | $ | — | $ | — | $ | 5.4 | $ | 4.1 | |||||||
Unfunded liabilities — included in other noncurrent liabilities | (168.6 | ) | (214.0 | ) | (17.6 | ) | (21.3 | ) | |||||||
Net amount recognized | $ | (168.6 | ) | $ | (214.0 | ) | $ | (12.2 | ) | $ | (17.2 | ) | |||
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): | |||||||||||||||
Prior service cost (credit) | $ | 0.7 | $ | (0.6 | ) | $ | (1.5 | ) | $ | (1.5 | ) | ||||
Net actuarial loss (gain) | 21.3 | 31.4 | (0.6 | ) | 3.8 | ||||||||||
Total | $ | 22.0 | $ | 30.8 | $ | (2.1 | ) | $ | 2.3 | ||||||
Amounts recorded in regulatory assets and liabilities (pre-tax): | |||||||||||||||
Prior service cost (credit) | $ | 1.0 | $ | 1.2 | $ | (1.6 | ) | $ | (2.2 | ) | |||||
Net actuarial loss | 139.5 | 181.0 | 1.2 | 2.4 | |||||||||||
Total | $ | 140.5 | $ | 182.2 | $ | (0.4 | ) | $ | 0.2 | ||||||
In Fiscal 2018, we estimate that we will amortize approximately $13.5 of net actuarial losses, primarily associated with the U.S. Pension Plan, and $0.5 of net prior service credits from UGI stockholders’ equity and regulatory assets into retiree benefit cost.
Actuarial assumptions for our U.S. plans are described below. Assumptions for the UGI International plans are based upon market conditions in France, Belgium and the Netherlands. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the plans’ benefit payments. The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Pension Plan | Other Postretirement Benefits | ||||||||||||||||
2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||
Weighted-average assumptions: | |||||||||||||||||
Discount rate – benefit obligations | 4.00 | % | 3.80 | % | 4.60 | % | 4.00 | % | 3.80 | % | 4.70 | % | |||||
Discount rate – benefit cost | 3.80 | % | 4.60 | % | 4.60 | % | 3.80 | % | 4.70 | % | 4.60 | % | |||||
Expected return on plan assets | 7.50 | % | 7.55 | % | 7.75 | % | 5.00 | % | 5.00 | % | 5.00 | % | |||||
Rate of increase in salary levels | 3.25 | % | 3.25 | % | 3.25 | % | 3.25 | % | 3.25 | % | 3.25 | % | |||||
The ABOs for the U.S. Pension Plan were $605.2 and $601.3 as of September 30, 2017 and 2016, respectively.
Net periodic pension expense and other postretirement benefit cost include the following components:
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||
Service cost | $ | 11.9 | $ | 10.1 | $ | 10.0 | $ | 1.0 | $ | 0.7 | $ | 0.7 | |||||||||||
Interest cost | 25.0 | 26.8 | 25.5 | 0.8 | 0.9 | 0.8 | |||||||||||||||||
Expected return on assets | (33.6 | ) | (32.4 | ) | (32.2 | ) | (0.7 | ) | (0.6 | ) | (0.6 | ) | |||||||||||
Curtailment gain | (1.4 | ) | (1.2 | ) | (0.8 | ) | — | — | — | ||||||||||||||
Amortization of: | |||||||||||||||||||||||
Prior service cost (benefit) | 0.3 | 0.3 | 0.3 | (0.6 | ) | (0.6 | ) | (0.5 | ) | ||||||||||||||
Actuarial loss | 16.7 | 10.9 | 10.0 | 0.3 | — | 0.1 | |||||||||||||||||
Net benefit cost | 18.9 | 14.5 | 12.8 | 0.8 | 0.4 | 0.5 | |||||||||||||||||
Change in associated regulatory liabilities | — | — | — | (0.5 | ) | 1.0 | 3.7 | ||||||||||||||||
Net benefit cost after change in regulatory liabilities | $ | 18.9 | $ | 14.5 | $ | 12.8 | $ | 0.3 | $ | 1.4 | $ | 4.2 | |||||||||||
The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Common Stock and smallcap common stocks (prior to their liquidation during Fiscal 2017). It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, we made cash contributions to the U.S. Pension Plan of $11.4, $9.9 and $11.1 respectively. The minimum required contributions in Fiscal 2018 are not expected to be material.
UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. Any required contributions to the VEBA during Fiscal 2018 are not expected to be material.
Expected payments for pension and other postretirement welfare benefits are as follows:
Pension Benefits | Other Postretirement Benefits | ||||||
Fiscal 2018 | $ | 29.5 | $ | 1.1 | |||
Fiscal 2019 | $ | 29.9 | $ | 1.1 | |||
Fiscal 2020 | $ | 31.5 | $ | 1.1 | |||
Fiscal 2021 | $ | 39.0 | $ | 1.1 | |||
Fiscal 2022 | $ | 39.6 | $ | 1.0 | |||
Fiscal 2023 - 2027 | $ | 196.2 | $ | 4.9 | |||
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The assumed domestic health care cost trend rates at September 30 are as follows:
2017 | 2016 | ||||
Health care cost trend rate assumed for next year | 7.00 | % | 7.25 | % | |
Rate to which the cost trend rate is assumed to decline (ultimate trend rate) | 5.0 | % | 5.0 | % | |
Fiscal year that the rate reaches the ultimate trend rate | 2026 | 2026 | |||
A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 2017 other postretirement benefit cost or September 30, 2017, other postretirement benefit ABO.
We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans (“Supplemental Defined Benefit Plans”). At September 30, 2017 and 2016, the PBOs of these plans, including obligations for amounts held in grantor trusts, were $50.7 and $47.4, respectively. We recorded pre-tax costs for these plans of $3.1 in Fiscal 2017, $2.6 in Fiscal 2016 and $2.3 in Fiscal 2015. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $11.3 and $13.0 at September 30, 2017 and 2016, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $1.1 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2018. During Fiscal 2017 and 2016 the Company made payments with respect to the Supplemental Defined Benefit Plans totaling $1.3 and $0.4, respectively. There were no such payments made in Fiscal 2015. The total fair value of the grantor trust investment assets associated with the Supplemental Defined Benefit Plans, which are included in “Other assets” on the Consolidated Balance Sheets, totaled $31.8 and $28.4 at September 30, 2017 and 2016, respectively.
U.S. Pension Plan and VEBA Assets
The assets of the U.S. Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the U.S. Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks (prior to their liquidation in Fiscal 2017) and UGI Common Stock. Assets associated with the UGI International plans are excluded from the disclosures in the tables below as such assets are not material.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows:
U.S. Pension Plan
Actual | Target Asset Allocation | Permitted Range | ||||||||
2017 | 2016 | |||||||||
Equity investments: | ||||||||||
Domestic | 55.2 | % | 54.1 | % | 52.5 | % | 40.0% – 65.0% | |||
International | 12.4 | % | 10.2 | % | 12.5 | % | 7.5% – 17.5% | |||
Total | 67.6 | % | 64.3 | % | 65.0 | % | 60.0% – 70.0% | |||
Fixed income funds & cash equivalents | 32.4 | % | 35.7 | % | 35.0 | % | 30.0% – 40.0% | |||
Total | 100.0 | % | 100.0 | % | 100.0 | % | ||||
VEBA
Actual | Target Asset Allocation | Permitted Range | ||||||||
2017 | 2016 | |||||||||
Domestic equity investments | 63.1 | % | 69.9 | % | 65.0 | % | 60.0% – 70.0% | |||
Fixed income funds & cash equivalents | 36.9 | % | 30.1 | % | 35.0 | % | 30.0% – 40.0% | |||
Total | 100.0 | % | 100.0 | % | 100.0 | % | ||||
Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500, actively managed mid- and small-cap mutual funds, and a separately managed account comprising small-cap common stocks (prior to their liquidation in Fiscal 2017). Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 7.7% and 8.0% of U.S. Pension Plan assets at September 30, 2017 and 2016, respectively.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The fair values of U.S. Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee. The fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2, as of September 30, 2017 and 2016 are as follows:
U.S. Pension Plan | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other(a) | Total | |||||||||||||||
September 30, 2017: | |||||||||||||||||||
Domestic equity investments: | |||||||||||||||||||
S&P 500 Index equity mutual funds | $ | 171.6 | $ | — | $ | — | $ | — | $ | 171.6 | |||||||||
Small and midcap equity mutual funds | 65.2 | — | — | — | 65.2 | ||||||||||||||
UGI Corporation Common Stock | 38.1 | — | — | — | 38.1 | ||||||||||||||
Total domestic equity investments | 274.9 | — | — | — | 274.9 | ||||||||||||||
International index equity mutual funds | 61.6 | — | — | — | 61.6 | ||||||||||||||
Fixed income investments: | |||||||||||||||||||
Bond index mutual funds | 156.2 | — | — | — | 156.2 | ||||||||||||||
Cash equivalents | — | — | — | 5.3 | 5.3 | ||||||||||||||
Total fixed income investments | 156.2 | — | — | 5.3 | 161.5 | ||||||||||||||
Total | $ | 492.7 | $ | — | $ | — | $ | 5.3 | $ | 498.0 | |||||||||
September 30, 2016: | |||||||||||||||||||
Domestic equity investments: | |||||||||||||||||||
S&P 500 Index equity mutual funds | $ | 158.9 | $ | — | $ | — | $ | — | $ | 158.9 | |||||||||
Small and midcap equity mutual funds | 43.2 | — | — | — | 43.2 | ||||||||||||||
Smallcap common stocks | 11.4 | — | — | — | 11.4 | ||||||||||||||
UGI Corporation Common Stock | 37.0 | — | — | — | 37.0 | ||||||||||||||
Total domestic equity investments | 250.5 | — | — | — | 250.5 | ||||||||||||||
International index equity mutual funds | 47.3 | — | — | — | 47.3 | ||||||||||||||
Fixed income investments: | |||||||||||||||||||
Bond index mutual funds | 147.8 | — | — | — | 147.8 | ||||||||||||||
Cash equivalents | — | — | — | 17.8 | 17.8 | ||||||||||||||
Total fixed income investments | 147.8 | — | — | 17.8 | 165.6 | ||||||||||||||
Total | $ | 445.6 | $ | — | $ | — | $ | 17.8 | $ | 463.4 | |||||||||
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
VEBA | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other (a) | Total | |||||||||||||||
September 30, 2017: | |||||||||||||||||||
S&P 500 Index equity mutual fund | $ | 9.3 | $ | — | $ | — | $ | — | $ | 9.3 | |||||||||
Bond index mutual fund | 5.1 | — | — | — | 5.1 | ||||||||||||||
Cash equivalents | — | — | — | 0.4 | 0.4 | ||||||||||||||
Total | $ | 14.4 | $ | — | $ | — | $ | 0.4 | $ | 14.8 | |||||||||
September 30, 2016: | |||||||||||||||||||
S&P 500 Index equity mutual fund | $ | 9.6 | $ | — | $ | — | $ | — | $ | 9.6 | |||||||||
Bond index mutual fund | 4.0 | — | — | — | 4.0 | ||||||||||||||
Cash equivalents | — | — | — | 0.1 | 0.1 | ||||||||||||||
Total | $ | 13.6 | $ | — | $ | — | $ | 0.1 | $ | 13.7 | |||||||||
(a) | Assets measured at net asset value (“NAV”) and therefore excluded from the fair value hierarchy. |
The expected long-term rates of return on U.S. Pension Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.
Defined Contribution Plans
We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans totaled $15.1 in Fiscal 2017, $14.3 in Fiscal 2016 and $15.2 in Fiscal 2015. The Company also sponsors certain nonqualified supplemental defined contribution executive retirement plans. These plans generally provide supplemental benefits to certain executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal Revenue Code. The Company makes payments to self-directed grantor trusts with respect to these supplemental defined contribution plans. Such payments during Fiscal 2017, Fiscal 2016 and Fiscal 2015 were not material. At September 30, 2017 and 2016, the total fair values of these grantor trust investment assets, which amounts are included in “Other assets” on the Consolidated Balance Sheets, were $3.6 and $4.6, respectively.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters
The following regulatory assets and liabilities associated with UGI Utilities are included in our Consolidated Balance Sheets at September 30:
2017 | 2016 | ||||||
Regulatory assets: | |||||||
Income taxes recoverable | $ | 121.4 | $ | 115.7 | |||
Underfunded pension and postretirement plans | 141.3 | 183.1 | |||||
Environmental costs | 61.6 | 59.4 | |||||
Deferred fuel and power costs | 7.7 | 0.2 | |||||
Removal costs, net | 31.0 | 27.9 | |||||
Other | 5.9 | 8.8 | |||||
Total regulatory assets | $ | 368.9 | $ | 395.1 | |||
Regulatory liabilities (a): | |||||||
Postretirement benefit overcollections | $ | 17.5 | $ | 17.5 | |||
Deferred fuel and power refunds | 10.6 | 22.3 | |||||
State income tax benefits — distribution system repairs | 18.4 | 15.1 | |||||
Other | 2.7 | 0.7 | |||||
Total regulatory liabilities | $ | 49.2 | $ | 55.6 | |||
(a) | Regulatory liabilities are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance Sheets. |
Other than removal costs, UGI Utilities currently does not recover a rate of return on the regulatory assets included in the table above.
Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of the tax benefit on accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. UGI Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 65 years.
Underfunded pension and other postretirement plans. This regulatory asset represents the portion of net actuarial losses and prior service costs (credits) associated with pension and other postretirement benefits which are probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants.
Environmental costs. Environmental costs principally represent estimated probable future environmental remediation and investigation costs that UGI Gas, CPG and PNG expect to incur, primarily at MGP sites in Pennsylvania, in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (“DEP”). Pursuant to base rate orders, UGI Gas, PNG and CPG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2017, the period over which UGI Gas, PNG and CPG expect to recover these costs will depend upon future remediation activity. For additional information on environmental costs, see Note 15.
Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. As required by PUC ratemaking, removal costs include actual costs incurred associated with asset retirement obligations. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over five years.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Postretirement benefit overcollections. This regulatory liability represents the difference between amounts recovered through rates by UGI Gas and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With respect to UGI Gas, postretirement benefit overcollections are generally being refunded to customers over a ten-year period beginning October 19, 2016, the date UGI Gas’ Joint Petition pursuant to its January 19, 2016 base rate filing became effective (see “Base Rate Filings” below). With respect to Electric Utility, the excess of the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits is being deferred for future rate refund to customers.
Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.
Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains on such contracts at September 30, 2017 and 2016 were $0.1 and $4.3, respectively.
In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at September 30, 2017 and 2016, were not material.
State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal benefit, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.
Other. Other regulatory assets and liabilities comprise a number of deferred items including, among others, a portion of preliminary stage information technology costs, energy efficiency conservation costs and rate case expenses.
Other Regulatory Matters
Base Rate Filings. On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21.7 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PUC providing for an $11.3 PNG annual base distribution rate increase. On August 31, 2017, the PUC approved the Joint Petition and the increase became effective October 20, 2017.
On January 19, 2016, UGI Utilities filed a rate request with the PUC to increase UGI Gas’s annual base operating revenues for residential, commercial and industrial customers by $58.6. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2016, a Joint Petition for Approval of Settlement of all issues providing for a $27.0 UGI Gas annual base distribution rate increase, to be effective October 19, 2016, was filed with the PUC (“Joint Petition”). On October 14, 2016, the PUC approved the Joint Petition with a minor modification which had no effect on the $27.0 base distribution rate increase. The increase became effective on October 19, 2016.
Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at 5% of distribution charges billed to customers.
PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from 5% to 10% of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018.
On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.
Preliminary Stage Information Technology Costs. During Fiscal 2016, we determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during Fiscal 2016, we capitalized $5.8 of such project costs ($5.4 of which had been expensed prior to Fiscal 2016) and recorded associated increases to utility property, plant and equipment ($2.7) and regulatory assets ($3.1). Subsequent to this determination, we continue to capitalize such preliminary stage project costs in accordance with GAAP related to regulated entities.
Note 9 — Inventories
Inventories comprise the following at September 30:
2017 | 2016 | ||||||
Non-utility LPG and natural gas | $ | 188.4 | $ | 129.8 | |||
Gas Utility natural gas | 39.5 | 29.2 | |||||
Materials, supplies and other | 50.7 | 51.3 | |||||
Total inventories | $ | 278.6 | $ | 210.3 | |||
At September 30, 2017, UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) having terms ranging from one to three years. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.
As of September 30, 2017, UGI Utilities had SCAAs with Energy Services, LLC, the effects of which are eliminated in consolidation, and with a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at September 30, 2017 and 2016, comprising 2.3 billion cubic feet (“bcf”) and 3.5 bcf of natural gas, was $6.7 and $7.6, respectively.
F-40
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 10 — Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:
2017 | 2016 | ||||||
Utilities: | |||||||
Distribution | $ | 2,835.3 | $ | 2,634.2 | |||
Transmission | 96.4 | 93.5 | |||||
Work in process | 112.6 | 103.9 | |||||
General and other | 241.0 | 167.3 | |||||
Total Utilities | 3,285.3 | 2,998.9 | |||||
Non-utility: | |||||||
Land | 180.1 | 169.9 | |||||
Buildings and improvements | 351.2 | 382.2 | |||||
Transportation equipment | 289.3 | 301.7 | |||||
Equipment, primarily cylinders and tanks | 3,529.4 | 3,421.5 | |||||
Electric generation | 310.0 | 309.4 | |||||
Pipeline and related assets | 454.5 | 235.8 | |||||
Work in process | 95.3 | 201.6 | |||||
Other | 354.8 | 324.3 | |||||
Total non-utility | 5,564.6 | 5,346.4 | |||||
Total property, plant and equipment | $ | 8,849.9 | $ | 8,345.3 | |||
Note 11 — Goodwill and Intangible Assets
Changes in the carrying amount of goodwill by reportable segment are as follows:
AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Total | |||||||||||||||
Balance September 30, 2015 | $ | 1,956.0 | $ | 803.7 | $ | 11.6 | $ | 182.1 | $ | 2,953.4 | |||||||||
Acquisitions | 24.2 | 16.9 | — | — | 41.1 | ||||||||||||||
Dispositions | — | (1.6 | ) | — | — | (1.6 | ) | ||||||||||||
Purchase accounting adjustments | (1.9 | ) | (2.6 | ) | — | — | (4.5 | ) | |||||||||||
Foreign currency translation | — | 0.6 | — | — | 0.6 | ||||||||||||||
Balance September 30, 2016 | 1,978.3 | 817.0 | 11.6 | 182.1 | 2,989.0 | ||||||||||||||
Acquisitions | 23.0 | 55.5 | — | — | 78.5 | ||||||||||||||
Purchase accounting adjustments | — | (1.7 | ) | — | — | (1.7 | ) | ||||||||||||
Foreign currency translation | — | 41.4 | — | — | 41.4 | ||||||||||||||
Balance September 30, 2017 | $ | 2,001.3 | $ | 912.2 | $ | 11.6 | $ | 182.1 | $ | 3,107.2 | |||||||||
Intangible assets comprise the following at September 30:
2017 | 2016 | ||||||
Customer relationships, noncompete agreements and other | $ | 817.8 | $ | 773.5 | |||
Trademarks and tradenames (not subject to amortization) | 134.1 | 131.6 | |||||
Gross carrying amount | 951.9 | 905.1 | |||||
Accumulated amortization | (340.2 | ) | (324.8 | ) | |||
Intangible assets, net | $ | 611.7 | $ | 580.3 | |||
F-41
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Amortization expense of intangible assets was $50.8, $54.3 and $52.0 for Fiscal 2017, Fiscal 2016 and Fiscal 2015, respectively. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2018 — $53.5; Fiscal 2019 — $51.6; Fiscal 2020 — $50.2; Fiscal 2021 — $48.3; Fiscal 2022 — $46.6.
Note 12 — Series Preferred Stock
UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2017 or 2016.
UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. At September 30, 2017 and 2016, there were no shares of UGI Utilities Series Preferred Stock outstanding.
Note 13 — Common Stock and Equity-Based Compensation
Common Stock
On January 30, 2014, the Company’s Board of Directors authorized the repurchase of up to 15,000,000 shares of UGI Corporation Common Stock over a four-year period. Pursuant to such authorization, during Fiscal 2017, Fiscal 2016 and Fiscal 2015, the Company purchased and placed in treasury stock 900,000, 1,250,000 and 1,000,000 shares at a total cost of $43.3, $47.6 and $34.1, respectively.
UGI Common Stock share activity for Fiscal 2015, Fiscal 2016 and Fiscal 2017 follows:
Issued | Treasury | Outstanding | ||||||
Balance, September 30, 2014 | 173,770,641 | (1,496,860 | ) | 172,273,781 | ||||
Issued: | ||||||||
Employee and director plans | 36,350 | 1,155,376 | 1,191,726 | |||||
Repurchases of common stock | — | (1,000,000 | ) | (1,000,000 | ) | |||
Reacquired common stock – employee and director plans | — | (77,004 | ) | (77,004 | ) | |||
Balance, September 30, 2015 | 173,806,991 | (1,418,488 | ) | 172,388,503 | ||||
Issued: | ||||||||
Employee and director plans | 87,150 | 2,355,202 | 2,442,352 | |||||
Repurchases of common stock | — | (1,250,000 | ) | (1,250,000 | ) | |||
Reacquired common stock – employee and director plans | — | (620,406 | ) | (620,406 | ) | |||
Balance, September 30, 2016 | 173,894,141 | (933,692 | ) | 172,960,449 | ||||
Issued: | ||||||||
Employee and director plans | 93,550 | 1,051,704 | 1,145,254 | |||||
Sale of reacquired common stock | — | 50,000 | 50,000 | |||||
Repurchases of common stock | — | (900,000 | ) | (900,000 | ) | |||
Reacquired common stock – employee and director plans | — | (111,966 | ) | (111,966 | ) | |||
Balance, September 30, 2017 | 173,987,691 | (843,954 | ) | 173,143,737 | ||||
Equity-Based Compensation
The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, UGI Common Stock-based equity instruments and AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $19.3 ($11.8 after-tax), $23.8 ($15.4 after-tax) and $29.2 ($18.9 after-tax) in Fiscal 2017, Fiscal 2016 and Fiscal 2015, respectively.
UGI Equity-Based Compensation Plans and Awards. On January 24, 2013, the Company’s shareholders approved the UGI Corporation 2013 Omnibus Incentive Compensation Plan (the “2013 OICP”). The 2013 OICP succeeds the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “2004 OECP”) for awards granted on
F-42
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
or after January 24, 2013. The 2004 OECP will continue in effect but all future grants issued pursuant to it will be solely in the form of options to acquire UGI Common Stock. Under the 2013 OICP, we may grant options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”), other equity-based awards and cash to employees and non-employee directors. The exercise price for options may not be less than the fair market value on the grant date. Awards granted under the 2013 OICP may vest immediately or ratably over a period of years, and stock options can be exercised no later than ten years from the grant date. In addition, the 2013 OICP provides that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
Under the 2004 OECP, we could grant options to acquire shares of UGI Common Stock, UGI Units and other equity-based awards to employees and non-employee directors through January 23, 2013 (except with respect to the granting of stock option awards as previously mentioned). Under the 2004 OECP, the exercise price for stock options could not be less than the fair market value on the grant date. Awards granted under the 2004 OECP could vest immediately or ratably over a period of years, and stock options could be exercised no later than ten years from the date of grant. In addition, the 2004 OECP provided that the awards of UGI Units could include the crediting of dividend equivalents to participants’ accounts.
Under the 2013 OICP, awards representing up to 21,750,000 shares of UGI Common Stock may be granted. Dividend equivalents on UGI Unit awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are accumulated in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of UGI Common Stock and cash. Substantially all UGI Unit awards granted to France SAS employees are settled in shares of UGI Common Stock and do not accrue dividend equivalents. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions. It is currently our practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit awards. Stock options may be net exercised whereby shares equal to the option price and the grantee’s minimum applicable payroll tax withholding are withheld from the number of shares payable (“net exercise”). We record shares withheld pursuant to a net exercise as shares reacquired.
UGI Stock Option Awards. Stock option transactions under equity-based compensation plans during Fiscal 2015, Fiscal 2016 and Fiscal 2017 follow:
Shares | Weighted Average Option Price | Total Intrinsic Value | Weighted Average Contract Term (Years) | |||||||||
Shares under option — September 30, 2014 | 8,957,290 | $ | 21.44 | $ | 113.3 | 7.0 | ||||||
Granted | 1,336,985 | $ | 37.70 | |||||||||
Canceled | (85,365 | ) | $ | 30.45 | ||||||||
Exercised | (953,533 | ) | $ | 19.10 | $ | 15.4 | ||||||
Shares under option — September 30, 2015 | 9,255,377 | $ | 23.97 | $ | 104.5 | 6.6 | ||||||
Granted | 1,510,625 | $ | 34.67 | |||||||||
Canceled | (84,213 | ) | $ | 34.13 | ||||||||
Exercised | (2,193,338 | ) | $ | 20.38 | $ | 40.1 | ||||||
Shares under option — September 30, 2016 | 8,488,451 | $ | 26.68 | $ | 157.6 | 6.6 | ||||||
Granted | 1,343,800 | $ | 46.51 | |||||||||
Canceled | (60,236 | ) | $ | 41.86 | ||||||||
Exercised | (990,267 | ) | $ | 21.40 | $ | 26.7 | ||||||
Shares under option — September 30, 2017 | 8,781,748 | $ | 30.20 | $ | 146.7 | 6.3 | ||||||
Options exercisable — September 30, 2015 | 6,050,946 | $ | 20.74 | |||||||||
Options exercisable — September 30, 2016 | 5,522,370 | $ | 22.94 | |||||||||
Options exercisable — September 30, 2017 | 5,973,668 | $ | 25.53 | $ | 127.4 | 5.3 | ||||||
Options not exercisable — September 30, 2017 | 2,808,080 | $ | 40.13 | $ | 19.3 | 7.8 | ||||||
F-43
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Cash received from stock option exercises and associated tax benefits were $17.7 and $9.6, $27.3 and $14.9, and $16.2 and $5.8 in Fiscal 2017, Fiscal 2016 and Fiscal 2015, respectively. As of September 30, 2017, there was $7.0 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 1.9 years.
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2017:
Range of exercise prices | |||||||||||||||||||
Under $20.00 | $20.00 – $25.00 | $25.01 – $30.00 | $30.01 – $35.00 | Over $35.00 | |||||||||||||||
Options outstanding at September 30, 2017: | |||||||||||||||||||
Number of options | 1,351,925 | 1,947,779 | 1,462,977 | 1,402,988 | 2,616,079 | ||||||||||||||
Weighted average remaining contractual life (in years) | 3.3 | 4.6 | 6.1 | 8.1 | 8.3 | ||||||||||||||
Weighted average exercise price | $ | 18.26 | $ | 21.57 | $ | 27.43 | $ | 33.66 | $ | 42.93 | |||||||||
Options exercisable at September 30, 2017: | |||||||||||||||||||
Number of options | 1,351,925 | 1,947,779 | 1,342,377 | 499,351 | 832,236 | ||||||||||||||
Weighted average exercise price | $ | 18.26 | $ | 21.57 | $ | 27.42 | $ | 33.52 | $ | 38.81 | |||||||||
UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $7.62 in Fiscal 2017, $4.87 in Fiscal 2016 and $5.47 in Fiscal 2015. These amounts were determined using a Black-Scholes option pricing model which values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments and the risk-free interest rate over the expected life of the option. The expected life of option awards represents the period of time during which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on historical UGI dividend rates. The risk free interest rate is based on U.S. Treasury bonds with terms comparable to the options in effect on the date of grant.
The assumptions we used for valuing option grants during Fiscal 2017, Fiscal 2016 and Fiscal 2015 are as follows:
2017 | 2016 | 2015 | |||
Expected life of option | 5.75 years | 5.75 years | 5.75 years | ||
Weighted average volatility | 19.8% | 19.5% | 19.5% | ||
Weighted average dividend yield | 2.1% | 2.6% | 2.5% | ||
Expected volatility | 19.8% | 19.3% | 19.1% -19.5% | ||
Expected dividend yield | 2.1% | 2.6% | 2.5% | ||
Risk free rate | 1.8% - 2.1% | 1.2% - 1.9% | 1.5% - 1.8% | ||
UGI Unit Awards. UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of UGI Performance Units ultimately paid at the end of the performance period (generally three years) may be higher or lower than the target amount, or even zero, based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to the Russell Midcap Utility Index, excluding telecommunication companies (“UGI comparator group”). For grants issued on or after January 1, 2013, grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 25th percentile compared to the UGI comparator group, the employee will not be paid. At the 25th percentile, the employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70%; at the 50th percentile, 100%; and at the 90th percentile and above, 200%. For grants issued prior to January 1, 2013, grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 40th percentile compared to the UGI comparator group, the employee will not be paid. At the 40th percentile, the employee will be paid an award equal to 50% of the target award; at the 50th percentile, 100%; and at the 100th percentile, 200%. The actual amount of the award is interpolated between these percentile rankings. Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.
The fair value of UGI Stock Units on the grant date is equal to the market price of UGI Stock on the grant date plus the fair value of dividend equivalents if applicable. Under GAAP, UGI Performance Units are equity awards with a market-based condition
F-44
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
which, if settled in shares, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of UGI Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award is accounted for as equity and the fair value of the award over the target, as well as all dividend equivalents, is accounted for as a liability. The expected term of the UGI Performance Unit awards is three years based on the performance period. Expected volatility is based on the historical volatility of UGI Common Stock over a three-year period. The risk-free interest rate is based on the yields on U.S. Treasury bonds at the time of grant. Volatility for all companies in the UGI comparator groups is based on historical volatility.
The following table summarizes the weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs:
Grants Awarded in Fiscal Year | |||||
2017 | 2016 | 2015 | |||
Risk free rate | 1.5% | 1.3% | 1.1% | ||
Expected life | 3 years | 3 years | 3 years | ||
Expected volatility | 18.9% | 17.5% | 15.9% | ||
Dividend yield | 2.1% | 2.7% | 2.3% | ||
The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $50.91 for Units granted in Fiscal 2017, $32.64 for Units granted in Fiscal 2016 and $38.43 for Units granted in Fiscal 2015.
The following table summarizes UGI Unit award activity for Fiscal 2017:
Total | Vested | Non-Vested | ||||||||||||||||||
Number of UGI Units | Weighted Average Grant Date Fair Value (per Unit) | Number of UGI Units | Weighted Average Grant Date Fair Value (per Unit) | Number of UGI Units | Weighted Average Grant Date Fair Value (per Unit) | |||||||||||||||
September 30, 2016 | 999,083 | $ | 25.44 | 672,075 | $ | 21.17 | 327,008 | $ | 34.21 | |||||||||||
UGI Performance Units: | ||||||||||||||||||||
Granted | 143,300 | $ | 50.91 | 20,283 | $ | 50.94 | 123,017 | $ | 50.90 | |||||||||||
Forfeited | (7,768 | ) | $ | 41.33 | — | $ | — | (7,768 | ) | $ | 41.33 | |||||||||
Vested | — | $ | — | 131,409 | $ | 33.67 | (131,409 | ) | $ | 33.67 | ||||||||||
Unit awards paid | (178,450 | ) | $ | 32.47 | (178,450 | ) | $ | 32.47 | — | $ | — | |||||||||
UGI Stock Units: | ||||||||||||||||||||
Granted (a) | 42,079 | $ | 47.25 | 34,979 | $ | 46.44 | 7,100 | $ | 51.23 | |||||||||||
Unit awards paid | (19,410 | ) | $ | 18.69 | (19,410 | ) | $ | 18.69 | — | $ | — | |||||||||
September 30, 2017 | 978,834 | $ | 28.83 | 660,886 | $ | 23.93 | 317,948 | $ | 41.10 | |||||||||||
(a) | Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2016 and Fiscal 2015 were 52,493 and 39,801, respectively. |
F-45
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
During Fiscal 2017, Fiscal 2016 and Fiscal 2015, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:
2017 | 2016 | 2015 | |||||||||
UGI Performance Unit awards: | |||||||||||
Number of original awards granted | 178,450 | 308,362 | 294,300 | ||||||||
Fiscal year granted | 2014 | 2013 | 2012 | ||||||||
Payment of awards: | |||||||||||
Shares of UGI Common Stock issued, net of shares withheld for taxes | 138,985 | 209,592 | 188,418 | ||||||||
Cash paid | $ | 10.9 | $ | 13.9 | $ | 13.3 | |||||
UGI Stock Unit awards: | |||||||||||
Number of original awards granted | 43,699 | 51,037 | 67,419 | ||||||||
Payment of awards: | |||||||||||
Shares of UGI Common Stock issued, net of shares withheld for taxes | 15,990 | 39,422 | 44,034 | ||||||||
Cash paid | $ | 0.3 | $ | 0.7 | $ | 0.8 | |||||
During Fiscal 2017, Fiscal 2016 and Fiscal 2015, we granted UGI Unit awards representing 185,379, 230,653 and 180,724 shares, respectively, having weighted-average grant date fair values per Unit of $50.08, $33.04 and $38.20, respectively.
As of September 30, 2017, there was a total of approximately $8.4 of unrecognized compensation cost associated with 978,834 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.9 years. The total fair values of UGI Units that vested during Fiscal 2017, Fiscal 2016 and Fiscal 2015 were $7.1, $9.7 and $15.3, respectively. As of September 30, 2017 and 2016, total liabilities of $13.1 and $18.5, respectively, associated with UGI Unit awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.
At September 30, 2017, 10,851,819 shares of Common Stock were available for future grants under the 2013 OICP, and up to 4,116 shares of Common Stock were available for future grants of stock options under the 2004 OECP.
AmeriGas Partners Equity-Based Compensation Plans and Awards. Under the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. (“2010 Propane Plan”), the General Partner may award to employees and non-employee directors grants of AmeriGas Partners Units (comprising “AmeriGas Stock Units” and “AmeriGas Performance Units”), options, phantom units, unit appreciation rights and other Common Unit-based awards. The total aggregate number of Common Units that may be issued under the 2010 Propane Plan is 2,800,000. The exercise price for options may not be less than the fair market value on the date of grant. Awards granted under the 2010 Propane Plan may vest immediately or ratably over a period of years, and options can be exercised no later than ten years from the grant date. In addition, the 2010 Propane Plan provides that Common Unit-based awards may also provide for the crediting of Common Unit distribution equivalents to participants’ accounts.
AmeriGas Stock Unit and AmeriGas Performance Unit awards entitle the grantee to AmeriGas Partners Common Units or cash once the service condition is met and, with respect to AmeriGas Performance Units, subject to market performance conditions, and for certain awards granted on or after January 1, 2015, actual net customer acquisition and retention performance. Recipients of AmeriGas Performance Unit awards are awarded a target number of AmeriGas Performance Units. The number of AmeriGas Performance Units ultimately paid at the end of the performance period (generally three years) may be higher or lower than the target number, or it may be zero. For that portion of Performance Unit awards whose ultimate payout is based upon market-based conditions (as further described below), the number of awards ultimately paid is based upon AmeriGas Partners’ Total Unitholder Return (“TUR”) percentile rank relative to entities in a master limited partnership peer group (“Alerian MLP Group”) and, for certain AmeriGas Performance Unit awards granted in January 2014, based upon AmeriGas Partners’ TUR relative to the two other publicly traded propane master limited partnerships in the Alerian MLP Group (“Propane MLP Group”). For Performance Unit awards granted on or after January 1, 2015, the number of AmeriGas Performance Units ultimately paid is based upon AmeriGas Partner’s TUR percentile rank relative to entities in the Alerian MLP Group as modified by AmeriGas Partners’ performance relative to the Propane MLP Group.
With respect to AmeriGas Performance Unit awards subject to measurement compared with the Alerian MLP Group, grantees may receive from 0% to 200% of the target award granted. For such grants issued on or after January 1, 2013, if AmeriGas
F-46
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Partners’ TUR is below the 25th percentile compared to the peer group, the grantee will not be paid. At the 25th percentile, the employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70%; at the 50th percentile, 100%; at the 60th percentile, 125%; at the 75th percentile, 162.5%; and at the 90th percentile or above, 200%. The actual amount of the award is interpolated between these percentile rankings. For such grants issued on or after January 1, 2015, the amount ultimately paid shall be modified based upon AmeriGas Partners’ TUR ranking relative to the Propane MLP Group over the performance period (“MLP Modifier”). Such modification ranges from 70% to 130%, but in no event shall the amount ultimately paid, after such modification, exceed 200% of the target award grant.
With respect to AmeriGas Performance Unit awards granted in January 2014 subject to measurement compared with the Propane MLP Group, grantees were eligible to receive 150% of the target award if AmeriGas Partners’ TUR exceeded the TUR of all the other members in the Propane MLP Group. Otherwise there would be no payout of such AmeriGas Performance Units. If one of the other two members of the Propane MLP Group ceased to exist as a publicly traded company or declares bankruptcy (“MLP Event”) and depending upon the timing of such MLP Event, the ultimate amount of such AmeriGas Performance Unit awards to be issued pursuant to the January 2014 grant, and the amount of distribution equivalents to be paid, would depend upon AmeriGas Partners’ TUR rank relative to (1) the Alerian MLP Group for the entire performance period; (2) the Alerian MLP Group for the entire performance period and the Propane MLP Group (through the date of the MLP Event); or (3) the Propane MLP Group through the date of the MLP Event. For those performance awards granted on or after January 1, 2015, that are subject to the MLP Modifier, if an MLP Event were to occur during the performance period such MLP Modifier would be based upon AmeriGas Partners’ TUR rank as determined in (1),(2) or (3) above, as appropriate.
With respect to AmeriGas Performance Unit awards granted in January 2015 whose payout is based upon net customer gain and retention performance, grantees may ultimately receive between 0% and 200% of the target award based upon the annual actual net customer gain and retention performance as adjusted for the net customer gain and retention performance over the three-year performance period. With respect to AmeriGas Performance Unit awards granted in January 2016 and 2017 whose payout is based upon net customer gain and retention performance, grantees may ultimately receive between 0% and 200% of the target award based upon the actual net customer gain and retention performance over the entire three-year performance period.
Common Unit distribution equivalents are paid in cash only on AmeriGas Performance Units that eventually vest. Generally, except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
Under GAAP, AmeriGas Performance Units awards that are subject to market-based conditions are equity awards that, if settled in Common Units, result in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of AmeriGas Performance Units subject to market-based conditions are estimated using a Monte Carlo valuation model. The fair value associated with the target award, which will be paid in Common Units, is accounted for as equity and the fair value of the award over the target, as well as all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability. For purposes of valuing AmeriGas Performance Unit awards that are subject to market-based conditions, expected volatility is based on the historical volatility of Common Units over a three-year period. The risk-free interest rate is based on the rates on U.S. Treasury bonds at the time of grant. Volatility for all entities in the peer group is based on historical volatility. The expected term of the AmeriGas Performance Unit awards is three years based on the performance period. AmeriGas Performance Unit awards whose ultimate payout is based upon net customer acquisition and retention performance measures are recorded as expense when it is probable all or a portion of the award will be paid. The fair value associated with the target award is the market price of the Common Units on the date of grant. The fair value of the award over the target, as well as all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability.
The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards subject to market-based conditions and related compensation costs:
Grants Awarded in Fiscal Year | |||||
2017 | 2016 | 2015 | |||
Risk-free rate | 1.5% | 1.3% | 0.9% | ||
Expected life | 3 years | 3 years | 3 years | ||
Expected volatility | 21.7% | 20.6% | 19.2% | ||
Dividend yield | 7.8% | 10.7% | 6.8% | ||
F-47
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The General Partner granted awards under the 2010 Propane Plan representing 67,563, 73,080 and 80,336 Common Units in Fiscal 2017, Fiscal 2016 and Fiscal 2015, respectively, having weighted-average grant date fair values per Common Unit subject to award of $52.37, $37.93 and $61.00, respectively. At September 30, 2017, 2,287,879 Common Units were available for future award grants under the 2010 Propane Plan.
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2017:
Total | Vested | Non-Vested | ||||||||||||||||||
Number of AmeriGas Partners Common Units Subject to Award | Weighted Average Grant Date Fair Value (per Unit) | Number of AmeriGas Partners Common Units Subject to Award | Weighted Average Grant Date Fair Value (per Unit) | Number of AmeriGas Partners Common Units Subject to Award | Weighted Average Grant Date Fair Value (per Unit) | |||||||||||||||
September 30, 2016 | 210,549 | $ | 47.24 | 55,622 | $ | 45.67 | 154,927 | $ | 47.80 | |||||||||||
AmeriGas Performance Units: | ||||||||||||||||||||
Granted | 49,225 | $ | 54.24 | 633 | $ | 54.45 | 48,592 | $ | 54.24 | |||||||||||
Forfeited | (9,151 | ) | $ | 48.76 | — | $ | — | (9,151 | ) | $ | 48.76 | |||||||||
Vested | — | $ | — | 40,933 | $ | 42.55 | (40,933 | ) | $ | 42.55 | ||||||||||
Awards paid | (44,732 | ) | $ | 41.53 | (44,732 | ) | $ | 41.53 | — | $ | — | |||||||||
AmeriGas Stock Units: | ||||||||||||||||||||
Granted | 18,338 | $ | 47.33 | 12,738 | $ | 48.06 | 5,600 | $ | 45.66 | |||||||||||
Vested | — | $ | — | 6,800 | $ | 46.13 | (6,800 | ) | $ | 46.13 | ||||||||||
Awards paid | (6,005 | ) | $ | 43.64 | (6,005 | ) | $ | 43.64 | — | $ | — | |||||||||
September 30, 2017 | 218,224 | $ | 50.03 | 65,989 | $ | 47.31 | 152,235 | $ | 51.21 | |||||||||||
During Fiscal 2017, Fiscal 2016 and Fiscal 2015, the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows:
2017 | 2016 | 2015 | |||||||||
AmeriGas Performance Unit awards: | |||||||||||
Number of Common Units subject to original awards granted | 53,800 | 44,800 | 55,750 | ||||||||
Fiscal year granted | 2014 | 2013 | 2012 | ||||||||
Payment of awards: | |||||||||||
AmeriGas Partners Common Units issued, net of units withheld for taxes | 29,489 | 23,017 | — | ||||||||
Cash paid | $ | 2.9 | $ | 1.7 | $ | — | |||||
AmeriGas Stock Unit awards: | |||||||||||
Number of Common Units subject to original awards granted | 32,658 | 20,336 | 42,532 | ||||||||
Payment of awards: | |||||||||||
AmeriGas Partners Common Units issued, net of units withheld for taxes | 3,932 | 9,272 | 21,509 | ||||||||
Cash paid | $ | 0.1 | $ | 0.4 | $ | 0.8 | |||||
As of September 30, 2017, there was a total of approximately $1.7 of unrecognized compensation cost associated with 218,224 Common Units subject to award that is expected to be recognized over a weighted-average period of 1.7 years. The total fair values of Common Unit-based awards that vested during Fiscal 2017, Fiscal 2016 and Fiscal 2015 were $2.1, $2.0 and $2.6, respectively. As of September 30, 2017 and 2016, total liabilities of $2.5 and $3.5 associated with Common Unit-based awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” in the Consolidated Balance Sheets. It is the Partnership’s practice to issue new AmeriGas Partners Common Units for the portion of any Common Unit-based awards paid in AmeriGas Partners Common Units.
F-48
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 14 — Partnership Distributions
The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash (as defined in the Partnership Agreement) for such quarter. Available Cash generally means:
1. | all cash on hand at the end of such quarter, plus |
2. | all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter, less |
3. | the amount of cash reserves established by the General Partner in its reasonable discretion. |
The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the next four quarters.
Distributions of Available Cash are made 98% to limited partners and 2% to the General Partner (representing a 1% General Partner interest in AmeriGas Partners and 1.01% interest in AmeriGas OLP) until Available Cash exceeds the Minimum Quarterly Distribution of $0.55 and the First Target Distribution of $0.055 per Common Unit (or a total of $0.605 per Common Unit). When Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner will receive a greater percentage of the total Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common Unit to limited partners exceeds $0.605.
During Fiscal 2017, Fiscal 2016 and Fiscal 2015, the Partnership made quarterly distributions to Common Unitholders in excess of $0.605 per limited partner unit. As a result, the General Partner has received a greater percentage of the total Partnership distribution than its aggregate 2% general partner interest in AmeriGas OLP and AmeriGas Partners. During Fiscal 2017, Fiscal 2016 and Fiscal 2015, the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $52.7, $47.4 and $39.3, respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2017, Fiscal 2016 and Fiscal 2015 of $43.5, $38.2 and $30.4, respectively.
Note 15 — Commitments and Contingencies
Commitments
Leases
We lease various buildings and other facilities and vehicles, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $99.5 in Fiscal 2017, $102.0 in Fiscal 2016 and $86.1 in Fiscal 2015.
Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows:
2018 | 2019 | 2020 | 2021 | 2022 | After 2022 | ||||||||||||||||||
AmeriGas Propane | $ | 70.0 | $ | 61.7 | $ | 56.5 | $ | 48.9 | $ | 40.7 | $ | 110.3 | |||||||||||
UGI Utilities | 7.5 | 6.0 | 4.4 | 2.7 | 0.8 | 0.2 | |||||||||||||||||
UGI International | 11.2 | 8.1 | 6.6 | 4.7 | 3.2 | 3.2 | |||||||||||||||||
Other | 2.3 | 2.0 | 1.9 | 0.9 | 0.5 | 0.6 | |||||||||||||||||
Total | $ | 91.0 | $ | 77.8 | $ | 69.4 | $ | 57.2 | $ | 45.2 | $ | 114.3 | |||||||||||
UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units
On November 7, 2017, UGI entered into a Standby Equity Commitment Agreement (the “Commitment Agreement”) with AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make up to $225 of capital contributions to the Partnership through July 1, 2019 (the “Commitment Period”). UGI’s capital contributions may be made from time to time during the Commitment Period upon request of the Partnership.
In consideration for any capital contributions made pursuant to the Commitment Agreement, the Partnership will issue to UGI or a wholly owned subsidiary new Class B Common Units representing limited partner interests in the Partnership (“Class B Units”). The Class B Units will be issued at a price per unit equal to the 20-day volume-weighted average price of the Partnership’s common units (“Common Units”) prior to the date of the Partnership’s related capital call. The Class B Units will be entitled to
F-49
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
cumulative quarterly distributions at a rate equal to the annualized Common Unit yield at the time of the applicable capital call, plus 130 basis points. The Partnership may choose to make the distributions in cash or in the form of additional Class B Units. While outstanding, the Class B Units will not be subject to any incentive distributions from the Partnership.
At any time after five years from the initial issuance of the Class B Units, holders may elect to convert all or any portion of the Class B Units they own into Common Units on a one-for-one basis, and at any time after six years from the initial issuance of the Class B Units, the Partnership may elect to convert all or any portion of the Class B Units into Common Units if (i) the closing trading price of the Common Units is greater than 110% of the applicable purchase price for the Class B Units and (ii) the Common Units are listed or admitted for trading on a National Securities Exchange. Upon certain events involving a change of control and immediately prior to a liquidation or winding up of the Partnership, the Class B Units will automatically convert into Common Units on a one-for-one basis.
Contingencies
Environmental Matters
UGI Utilities
From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility. UGI Utilities also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania.
Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered a consent order and agreement (“COA”) with the DEP to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG, and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2.5, $1.8 and $1.1, for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018 and 2019, respectively. At September 30, 2017 and 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $54.3 and $55.1, respectively. UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 8).
We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to UGI Utilities’ results of operations because UGI Utilities, CPG and PNG receive ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.
From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by a former subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At September 30, 2017 and 2016, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material.
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UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
AmeriGas Propane
AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that the DEC had placed property purportedly owned by AmeriGas OLP in Saranac Lake, New York on the New York State Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by the DEC disclosed contamination related to a former MGP. At that time, AmeriGas OLP reviewed the study and researched the history of the site, including the extent of AmeriGas OLP’s ownership. In its written response to the DEC in early 2009, AmeriGas OLP disputed DEC’s contention it was a potentially responsible party (“PRP”) as it did not operate the MGP and appeared to only own a portion of the site. The DEC did not respond to the 2009 communication. In March 2017, the DEC communicated to AmeriGas OLP that the DEC had previously issued three Records of Decision (“RODs”) related to the site and requested additional information regarding AmeriGas OLP’s purported ownership. The selected remedies identified in the RODs total approximately $27.7. To AmeriGas OLP’s knowledge, the DEC has not yet commenced implementation of the remediation plan but remediation is currently expected to commence in 2018. AmeriGas OLP responded to the DEC’s March 2017 request for ownership information, renewing its challenge to designation as a PRP and identifying potential defenses. In October 2017, the DEC identified a third party PRP with respect to the site. Based on our evaluation of the available information, during Fiscal 2017, the Partnership accrued an environmental remediation liability of $7.5 related to the site, which amount is included in “Operating and administrative expenses” on the Consolidated Statements of Income. Our share of the actual remediation costs could be significantly more or less than the accrued amount.
Other Matters
Purported Class Action Lawsuits. Between May and October of 2014, more than 35 purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI Corporation and a competitor by certain of their direct and indirect customers. The class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade their common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws. The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes.
On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Division of the United States District Court for the Western District of Missouri (“District Court”). In July 2015, the District Court dismissed all claims brought by direct customers. In June 2017, the United States Court of Appeals for the Eighth Circuit (“Eighth Circuit”) ruled en banc to reverse the dismissal by the District Court, which had previously been affirmed by a panel of the Eighth Circuit. In September 2017, we filed a Petition for a Writ of Certiorari to the U.S. Supreme Court appealing the decision of the Eighth Circuit.
In July 2015, the District Court also dismissed all claims brought by the indirect customers other than those for injunctive relief. The indirect customers filed an amended complaint with the District Court claiming injunctive relief and state law claims under Wisconsin, Maine and Vermont law. In September 2016, the District Court dismissed the amended complaint in its entirety. The indirect customers appealed this decision to the Eighth Circuit; such appeal was subject to a stay pending the en banc review of the direct purchasers’ claims. In light of the Eighth Circuit decision with respect to the direct purchasers’ claims, the briefing schedule in respect of the indirect purchaser appeal will now resume. On July 21, 2016, several new indirect customer plaintiffs filed an antitrust class action lawsuit against the Partnership in the Western District of Missouri. The new indirect customer class action lawsuit was dismissed in September 2016 and certain indirect customer plaintiffs appealed the decision, consolidating their appeal with the indirect customer appeal still pending in the Eighth Circuit. Now that the Eighth Circuit ruled on the direct purchasers’ claims, the stay has been lifted for the indirect claims and the parties submitted briefs in October 2017 to the Eighth Circuit and are waiting the court’s ruling.
We are unable to reasonably estimate the impact, if any, arising from such litigation. We believe we have strong defenses to the claims and intend to vigorously defend against them.
In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial statements.
F-51
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 16 — Fair Value Measurements
Recurring Fair Value Measurements
The following table presents, on a gross basis, our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2, as of September 30, 2017 and 2016:
Asset (Liability) | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
September 30, 2017: | |||||||||||||||
Derivative instruments: | |||||||||||||||
Assets: | |||||||||||||||
Commodity contracts | $ | 27.2 | $ | 76.9 | $ | — | $ | 104.1 | |||||||
Foreign currency contracts | $ | — | $ | 12.2 | $ | — | $ | 12.2 | |||||||
Liabilities: | |||||||||||||||
Commodity contracts | $ | (27.7 | ) | $ | (11.4 | ) | $ | — | $ | (39.1 | ) | ||||
Foreign currency contracts | $ | — | $ | (38.2 | ) | $ | — | $ | (38.2 | ) | |||||
Cross-currency swaps | $ | — | $ | (2.9 | ) | $ | — | $ | (2.9 | ) | |||||
Interest rate contracts | $ | — | $ | (2.3 | ) | $ | — | $ | (2.3 | ) | |||||
Non-qualified supplemental postretirement grantor trust investments (a) | $ | 35.6 | $ | — | $ | — | $ | 35.6 | |||||||
September 30, 2016 | |||||||||||||||
Derivative instruments: | |||||||||||||||
Assets: | |||||||||||||||
Commodity contracts | $ | 28.9 | $ | 26.0 | $ | — | $ | 54.9 | |||||||
Foreign currency contracts | $ | — | $ | 17.8 | $ | — | $ | 17.8 | |||||||
Liabilities: | |||||||||||||||
Commodity contracts | $ | (76.8 | ) | $ | (21.8 | ) | $ | — | $ | (98.6 | ) | ||||
Foreign currency contracts | $ | — | $ | (2.4 | ) | $ | — | $ | (2.4 | ) | |||||
Interest rate contracts | $ | — | $ | (3.9 | ) | $ | — | $ | (3.9 | ) | |||||
Cross-currency swaps | $ | — | $ | (0.5 | ) | $ | — | $ | (0.5 | ) | |||||
Non-qualified supplemental postretirement grantor trust investments (a) | $ | 33.0 | $ | — | $ | — | $ | 33.0 | |||||||
(a) | Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 7). |
The fair values of our Level 1 exchange-traded commodity futures and option contracts and non-exchange-traded commodity futures and forward contracts are based upon actively quoted market prices for identical assets and liabilities. The remainder of our derivative instruments are designated as Level 2. The fair values of certain non-exchange-traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 that are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts, foreign currency contracts and cross-currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. There were no transfers between Level 1 and Level 2 during the periods presented.
F-52
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Other Financial Instruments
The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2017 and 2016 were as follows:
2017 | 2016 | ||||||
Carrying amount | $ | 4,211.9 | $ | 3,832.3 | |||
Estimated fair value | $ | 4,346.8 | $ | 4,052.3 | |||
Financial instruments other than derivative instruments, such as short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk arising from concentrations of trade accounts receivable is limited because we have a large customer base that extends across many different U.S. markets and a number of foreign countries. For information regarding concentrations of credit risk associated with our derivative instruments, see Note 17. Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value. See Note 2 for additional information on this investment.
Note 17 — Derivative Instruments and Hedging Activities
We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk, (2) interest rate risk, and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies, which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Although our commodity derivative instruments extend over a number of years, a significant portion of our commodity derivative instruments economically hedge commodity price risk during the next twelve months. For information on the accounting for our derivative instruments, see Note 2.
Commodity Price Risk
Regulated Utility Operations
Natural Gas
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge PGC. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. Gains and losses on Gas Utility’s natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 8).
Electricity
Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At September 30, 2017 and 2016, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.
In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or
F-53
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 8).
Non-utility Operations
LPG
In order to manage market price risk associated with the Partnership’s fixed-price programs, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic businesses and our UGI International operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. The Partnership from time to time enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. Also, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of propane.
Natural Gas
In order to manage market price risk relating to fixed-price sales contracts for natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and forward contracts and Intercontinental Exchange (“ICE”) natural gas basis swap contracts. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas. UGI International also uses natural gas futures and forward contracts to economically hedge market price risk associated with fixed-price sales contracts with its customers.
Electricity
In order to manage market price risk relating to fixed-price sales contracts for electricity, Midstream & Marketing enters into electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. From time to time, Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. UGI International also uses electricity futures and forward contracts to economically hedge market price risk associated with fixed-price sales and purchase contracts for electricity.
Interest Rate Risk
France SAS’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. France SAS and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor and LIBOR rates of interest on their variable-rate term loans. The France SAS swaps were originally executed in Fiscal 2015, at which time such swaps were designated in a cash flow hedging relationship associated with €600 notional amount of term loan debt issued in conjunction with the Totalgaz Acquisition. In March 2016, France SAS amended the terms of its pay-fixed, receive-variable interest rate swap agreements associated with the €600 term loan debt to purchase a 0% floor that is identical to the 0% floor embedded in France SAS’ term loan debt. In conjunction with the amendments, in March 2016, France SAS paid its interest rate swap counterparties €7.7, which amount substantially equaled the interest rate swaps’ fair value. Concurrent with the amendments to the interest rate swaps, the swaps were simultaneously de-designated and re-designated as cash flow hedges of future anticipated interest payments associated with the €600 term loan debt. The amended swaps fix the underlying euribor rate on the €600 term loan at 0.18%.
Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for interest rate swaps and IRPAs as cash flow hedges. On March 31, 2016, concurrent with the pricing of UGI Utilities’ Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities settled all of its then-existing IRPA contracts associated with such debt at a loss of $36.0. Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs was recorded in AOCI and is being recognized in interest expense as the associated future interest expense impacts earnings.
F-54
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
At September 30, 2017 and 2016, we had no unsettled IRPAs. At September 30, 2017, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3.5.
Foreign Currency Exchange Rate Risk
Forward Foreign Currency Exchange Contracts
In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March. We account for these foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At September 30, 2017, the amount of net losses associated with currency rate risk expected to be reclassified into earnings during the next twelve months based upon current fair values is $0.9.
Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. The fair value of these forward foreign currency contracts are recorded as assets or liabilities on the Consolidated Balance Sheets. Changes in the fair value of these foreign currency exchange contracts are recorded in “Losses on foreign currency contracts, net” on the Consolidated Statements of Income.
From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our UGI International euro-denominated net investments. We account for these foreign currency exchange contracts as net investment hedges. At September 30, 2017 and 2016, there were no unsettled net investment hedges outstanding.
Cross-currency Swaps
From time to time, Flaga enters into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of U.S. dollar-denominated debt. These cross-currency hedges include initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also include interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designate these cross-currency swaps as cash flow hedges.
At September 30, 2017, the amount of net losses associated with such cross-currency swaps expected to be reclassified into earnings during the next twelve months is not material.
F-55
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Quantitative Disclosures Related to Derivative Instruments
The following table summarizes by derivative type the gross notional amounts related to open derivative contracts at September 30, 2017 and 2016 and the final settlement date of the Company's open derivative transactions as of September 30, 2017, excluding those derivatives that qualified for the NPNS exception:
Notional Amounts (in millions) | ||||||||||||
Type | Units | Settlements Extending Through | 2017 | 2016 | ||||||||
Commodity Price Risk: | ||||||||||||
Regulated Utility Operations | ||||||||||||
Gas Utility NYMEX natural gas futures and option contracts | Dekatherms | September 2018 | 14.8 | 18.4 | ||||||||
FTRs contracts | Kilowatt hours | May 2018 | 101.2 | 58.3 | ||||||||
Non-utility Operations | ||||||||||||
LPG swaps & options | Gallons | March 2020 | 325.5 | 396.9 | ||||||||
Natural gas futures, forward and pipeline contracts (a) | Dekatherms | December 2021 | 75.9 | 71.1 | ||||||||
Natural gas basis swap contracts | Dekatherms | March 2022 | 104.2 | 118.3 | ||||||||
NYMEX natural gas storage | Dekatherms | March 2019 | 1.9 | 1.9 | ||||||||
NYMEX propane storage | Gallons | March 2018 | 0.3 | — | ||||||||
Electricity long forward and futures contracts (a) | Kilowatt hours | May 2021 | 4,440.3 | 761.2 | ||||||||
Electricity short forward and futures contracts | Kilowatt hours | May 2021 | 447.0 | 264.6 | ||||||||
Interest Rate Risk: | ||||||||||||
Interest rate swaps | Euro | October 2020 | € | 645.8 | € | 645.8 | ||||||
Foreign Currency Exchange Rate Risk: | ||||||||||||
Forward foreign currency exchange contracts | USD | September 2020 | $ | 424.8 | $ | 314.3 | ||||||
Cross-currency swaps | USD | September 2018 | $ | 59.1 | $ | 59.1 | ||||||
(a) | Amounts in 2017 include derivative contracts held by a natural gas and electricity marketing business in the Netherlands acquired in Fiscal 2017. |
Derivative Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2017 and 2016, restricted cash in brokerage accounts totaled $10.3 and $15.6, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss we would incur if these counterparties failed to perform according to the terms of their contracts, based upon the gross fair values of the derivative instruments, was not material at September 30, 2017. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At September 30, 2017, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
F-56
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Offsetting Derivative Assets and Liabilities
Derivative assets and liabilities are presented net by counterparty on the Consolidated Balance Sheets if the right of offset exists. We offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions.
In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on the Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.
F-57
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Fair Value of Derivative Instruments
The following table presents the Company’s derivative assets and liabilities by type, as well as the effects of offsetting, as of September 30, 2017 and 2016:
2017 | 2016 | ||||||
Derivative assets: | |||||||
Derivatives designated as hedging instruments: | |||||||
Foreign currency contracts | $ | 3.2 | $ | 17.8 | |||
Derivatives subject to PGC and DS mechanisms: | |||||||
Commodity contracts | 1.7 | 4.5 | |||||
Derivatives not designated as hedging instruments: | |||||||
Commodity contracts | 102.4 | 50.4 | |||||
Foreign currency contracts | 9.0 | — | |||||
111.4 | 50.4 | ||||||
Total derivative assets – gross | 116.3 | 72.7 | |||||
Gross amounts offset in the balance sheet | (35.7 | ) | (35.0 | ) | |||
Cash collateral received | (8.3 | ) | (0.3 | ) | |||
Total derivative assets – net | $ | 72.3 | $ | 37.4 | |||
Derivative liabilities: | |||||||
Derivatives designated as hedging instruments: | |||||||
Foreign currency contracts | $ | (5.5 | ) | $ | (2.4 | ) | |
Cross-currency contracts | (2.9 | ) | (0.5 | ) | |||
Interest rate contracts | (2.3 | ) | (3.9 | ) | |||
(10.7 | ) | (6.8 | ) | ||||
Derivatives subject to PGC and DS mechanisms: | |||||||
Commodity contracts | (1.5 | ) | (0.5 | ) | |||
Derivatives not designated as hedging instruments: | |||||||
Commodity contracts | (37.6 | ) | (98.1 | ) | |||
Foreign currency contracts | (32.7 | ) | — | ||||
(70.3 | ) | (98.1 | ) | ||||
Total derivative liabilities – gross | (82.5 | ) | (105.4 | ) | |||
Gross amounts offset in the balance sheet | 35.7 | 35.0 | |||||
Total derivative liabilities – net | $ | (46.8 | ) | $ | (70.4 | ) | |
F-58
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Effects of Derivative Instruments
The following tables provide information on the effects of derivative instruments on the Consolidated Statements of Income and changes in AOCI and noncontrolling interests for Fiscal 2017, Fiscal 2016 and Fiscal 2015:
Gain (Loss) Recognized in AOCI | Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income | Location of Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income | |||||||||||||||||||||||
2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||||||
Commodity contracts | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (2.2 | ) | Cost of sales | |||||||||||
Foreign currency contracts | 0.2 | 3.6 | 26.0 | 17.8 | 17.2 | 9.7 | Cost of sales | ||||||||||||||||||
Cross-currency contracts | 0.5 | 0.1 | 5.4 | (0.1 | ) | 0.4 | 8.5 | Interest expense /other operating income, net | |||||||||||||||||
Interest rate contracts | 1.5 | (32.5 | ) | (6.6 | ) | (3.9 | ) | (4.5 | ) | (20.4 | ) | Interest expense | |||||||||||||
Total | $ | 2.2 | $ | (28.8 | ) | $ | 24.8 | $ | 13.8 | $ | 13.1 | $ | (4.4 | ) | |||||||||||
Gain (Loss) Recognized in Income | Location of Gain (Loss) Recognized in Income | |||||||||||
2017 | 2016 | 2015 | ||||||||||
Derivatives Not Designated as Hedging Instruments: | ||||||||||||
Commodity contracts | $ | 166.0 | $ | (65.0 | ) | $ | (375.8 | ) | Cost of sales | |||
Commodity contracts | (2.0 | ) | (2.2 | ) | 0.3 | Revenues | ||||||
Commodity contracts | 0.2 | (0.1 | ) | (0.8 | ) | Operating and administrative expenses / other operating income, net | ||||||
Foreign currency contracts | (23.8 | ) | — | — | Losses on foreign currency contracts, net | |||||||
Total | $ | 140.4 | $ | (67.3 | ) | $ | (376.3 | ) | ||||
For Fiscal 2017 and Fiscal 2015, the amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material. For Fiscal 2016 the amounts of derivative gains or losses representing ineffectiveness were losses of $5.5, which were recorded in “Other operating income, net,” on the Consolidated Statements of Income and are related to interest rate swap agreements at France SAS prior to their amendments in March 2016.
In May 2015, the Company prepaid term loans outstanding under Antargaz’ 2011 Senior Facilities Agreement. In conjunction with the prepayment, the Company also settled associated pay-fixed, receive-variable interest rate swaps, and discontinued cash flow hedge accounting treatment for such swaps. During Fiscal 2015, the Company recorded a pre-tax loss of $9.0 associated with the discontinuance of cash flow hedge accounting for the swaps, which amount is included in “Interest expense” on the Consolidated Statements of Income.
We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts that provide for the purchase and delivery, or sale, of energy products, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although certain of these contracts have the requisite elements of a derivative instrument, these contracts qualify for NPNS exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
F-59
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 18 — Accumulated Other Comprehensive Income (Loss)
Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and long-term intra-company transaction adjustments.
Changes in AOCI during Fiscal 2017, Fiscal 2016 and Fiscal 2015 are as follows:
Postretirement Benefit Plans | Derivative Instruments | Foreign Currency | Total | ||||||||||||
AOCI - September 30, 2014 | $ | (20.6 | ) | $ | (9.3 | ) | $ | 8.7 | $ | (21.2 | ) | ||||
Other comprehensive (loss) income before reclassification adjustments (after-tax) | (1.2 | ) | 16.8 | (114.1 | ) | (98.5 | ) | ||||||||
Amounts reclassified from AOCI and noncontrolling interests: | |||||||||||||||
Reclassification adjustments (pre-tax) | 2.2 | 4.4 | — | 6.6 | |||||||||||
Reclassification adjustments tax benefit | (0.8 | ) | (2.8 | ) | — | (3.6 | ) | ||||||||
Reclassification adjustments (after-tax) | 1.4 | 1.6 | — | 3.0 | |||||||||||
Other comprehensive income (loss) | 0.2 | 18.4 | (114.1 | ) | (95.5 | ) | |||||||||
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners | — | 2.1 | — | 2.1 | |||||||||||
Other comprehensive income (loss) attributable to UGI | 0.2 | 20.5 | (114.1 | ) | (93.4 | ) | |||||||||
AOCI - September 30, 2015 | $ | (20.4 | ) | $ | 11.2 | $ | (105.4 | ) | $ | (114.6 | ) | ||||
Other comprehensive loss before reclassification adjustments (after-tax) | (10.9 | ) | (16.5 | ) | (6.8 | ) | (34.2 | ) | |||||||
Amounts reclassified from AOCI: | |||||||||||||||
Reclassification adjustments (pre-tax) | 2.6 | (13.1 | ) | — | (10.5 | ) | |||||||||
Reclassification adjustments tax (benefit) expense | (0.4 | ) | 5.0 | — | 4.6 | ||||||||||
Reclassification adjustments (after-tax) | 2.2 | (8.1 | ) | — | (5.9 | ) | |||||||||
Other comprehensive loss attributable to UGI | (8.7 | ) | (24.6 | ) | (6.8 | ) | (40.1 | ) | |||||||
AOCI - September 30, 2016 | $ | (29.1 | ) | $ | (13.4 | ) | $ | (112.2 | ) | $ | (154.7 | ) | |||
Other comprehensive income before reclassification adjustments (after-tax) | 6.5 | 1.7 | 59.4 | 67.6 | |||||||||||
Amounts reclassified from AOCI: | |||||||||||||||
Reclassification adjustments (pre-tax) | 5.5 | (13.8 | ) | — | (8.3 | ) | |||||||||
Reclassification adjustments tax (benefit) expense | (2.1 | ) | 4.1 | — | 2.0 | ||||||||||
Reclassification adjustments (after-tax) | 3.4 | (9.7 | ) | — | (6.3 | ) | |||||||||
Other comprehensive income (loss) attributable to UGI | 9.9 | (8.0 | ) | 59.4 | 61.3 | ||||||||||
AOCI - September 30, 2017 | $ | (19.2 | ) | $ | (21.4 | ) | $ | (52.8 | ) | $ | (93.4 | ) | |||
For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 17.
F-60
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 19 — Other Operating Income, Net
Other operating income, net, comprises the following:
2017 | 2016 | 2015 | |||||||||
Finance charges | $ | 11.8 | $ | 15.2 | $ | 12.7 | |||||
AFUDC associated with pipeline projects | 5.5 | 3.3 | — | ||||||||
Interest and interest-related income | 1.7 | 0.2 | 0.8 | ||||||||
Utility non-tariff service income | 1.5 | 2.6 | 4.8 | ||||||||
Loss on private equity partnership investment | (11.0 | ) | — | — | |||||||
(Losses) gains on sales of fixed assets, net | (3.9 | ) | 3.3 | 11.1 | |||||||
Other, net | 4.9 | (2.2 | ) | 15.0 | |||||||
Total other operating income, net | $ | 10.5 | $ | 22.4 | $ | 44.4 | |||||
Note 20 — Quarterly Data (unaudited)
The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) which we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate primarily because of the seasonal nature of our businesses and the effects of unrealized gains and losses on commodity and certain foreign currency derivative instruments (see Note 17).
December 31, | March 31, | June 30, | September 30, | ||||||||||||||||||||||||
2016 (a)(b) | 2015 | 2017 (b)(c) | 2016 | 2017 (b) | 2016 (d) | 2017 (a)(c) | 2016 (d) | ||||||||||||||||||||
Revenues | $ | 1,679.5 | $ | 1,606.6 | $ | 2,173.8 | $ | 1,972.1 | $ | 1,153.5 | $ | 1,130.8 | $ | 1,113.9 | $ | 976.2 | |||||||||||
Operating income (loss) | $ | 466.2 | $ | 305.5 | $ | 513.2 | $ | 615.4 | $ | (2.8 | ) | $ | 155.7 | $ | 27.6 | $ | (88.6 | ) | |||||||||
(Loss) income from equity investees | $ | (0.2 | ) | $ | (0.1 | ) | $ | 2.3 | $ | — | $ | 0.9 | $ | — | $ | 1.3 | $ | (0.1 | ) | ||||||||
Loss on extinguishments of debt | $ | (33.2 | ) | $ | — | $ | (22.1 | ) | $ | — | $ | (4.4 | ) | $ | (37.1 | ) | $ | — | $ | (11.8 | ) | ||||||
Net income (loss) including noncontrolling interests | $ | 290.9 | $ | 167.9 | $ | 311.8 | $ | 408.0 | $ | (62.2 | ) | $ | 28.6 | $ | (16.7 | ) | $ | (115.7 | ) | ||||||||
Net income (loss) attributable to UGI Corporation | $ | 230.7 | $ | 114.6 | $ | 219.9 | $ | 233.2 | $ | (19.0 | ) | $ | 60.7 | $ | 5.0 | $ | (43.8 | ) | |||||||||
Earnings (loss) per common share attributable to UGI Corporation stockholders: | |||||||||||||||||||||||||||
Basic | $ | 1.33 | $ | 0.66 | $ | 1.27 | $ | 1.35 | $ | (0.11 | ) | $ | 0.35 | $ | 0.03 | $ | (0.25 | ) | |||||||||
Diluted | $ | 1.30 | $ | 0.65 | $ | 1.24 | $ | 1.33 | $ | (0.11 | ) | $ | 0.34 | $ | 0.03 | $ | (0.25 | ) | |||||||||
(a) | The quarter ended December 31, 2016 includes beneficial impact of adjustments to net deferred income tax liabilities associated with a change in French income tax rate which increased net income attributable to UGI Corporation by $27.4 or $0.15 per diluted share, and the impact of an income tax settlement refund in France which increased net income attributable to UGI Corporation by $6.7 or $0.04 per diluted share. The quarter ended September 30, 2017 includes the release of a valuation allowance against future uses of foreign tax credit carryforwards, which increased net income attributable to UGI Corporation by $7.6 or $0.04 per diluted share. |
(b) | The quarter ended December 31, 2016 includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $5.3 or $0.03 per diluted share. The quarter ended March 31, 2017 includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $3.6 or $0.02. The quarter ended June 30, 2017 includes loss on extinguishments of debt at AmeriGas Partners which increased net loss attributable to UGI Corporation by $0.7 or $0.01 per diluted share (see Note 5). |
(c) | The quarter ended March 31, 2017 includes impairment of a cost basis investment which decreased net income attributable to UGI Corporation by $4.5 or $0.03 per diluted share. The quarter ended September 30, 2017 includes impairment of a cost |
F-61
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
basis investment which decreased net income attributable to UGI Corporation by $2.6 or $0.02 per diluted share for the quarter ended September 30, 2017 (see Note 2).
(d) | The quarter ended June 30, 2016 includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share. The quarter ended September 30, 2016 includes loss on extinguishments of debt at AmeriGas Partners which increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5). |
Note 21 — Segment Information
Our operations comprise four reportable segments generally based upon products or services sold, geographic location and regulatory environment: (1) AmeriGas Propane; (2) UGI International; (3) Midstream & Marketing; and (4) UGI Utilities.
As a result of changes in the composition of information reported to our chief operating decision maker (“CODM”), effective October 1, 2016, we combined (1) our UGI France reportable segment with our Flaga & Other reportable segment, collectively referred to as “UGI International,” and (2) our Energy Services reportable segment with our Electric Generation reportable segment, collectively referred to as “Midstream & Marketing.” In accordance with GAAP, prior-period amounts have been restated to reflect these changes.
AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers in all 50 states. UGI International derives its revenues principally from the distribution of LPG to retail customers in France and in northern, central and eastern European countries. In addition, UGI International operates natural gas marketing businesses in France, Belgium and the United Kingdom and markets natural gas and electricity in the Netherlands. Midstream & Marketing derives its revenues principally from the sale of natural gas and, to a lesser extent, electricity, LPG and fuel oil as well as revenues and fees from storage, pipeline transportation and natural gas production activities primarily in the Mid-Atlantic region of the U.S. Midstream & Marketing also derives revenues from the sale of electricity through PJM, a regional electricity transmission organization in the eastern U.S., and, to a lesser extent, also from contracting services provided by HVAC to customers in portions of eastern and central Pennsylvania. UGI Utilities derives its revenues principally from the sale and distribution of natural gas to customers in eastern and central Pennsylvania and, to a lesser extent, from the sale and distribution of electricity in two northeastern Pennsylvania counties.
Corporate & Other principally comprise (1) net expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility, and UGI’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other includes net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) because such items are excluded from profit measures evaluated by our CODM in assessing our reportable segments’ performance or allocating resources. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company, and UGI corporate headquarters’ assets.
The accounting policies of our reportable segments are the same as those described in Note 2. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization as adjusted for the effects of gains and losses on commodity derivative instruments not associated with current-period transactions and other gains and losses that competitors do not necessarily have (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies. Our CODM evaluates the performance of our other reportable segments principally based upon their income before income taxes excluding gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions, as previously mentioned.
No single customer represents more than ten percent of our consolidated revenues. In addition, all of our reportable segments’ revenues, other than those of UGI International, are derived from sources within the United States, and all of our reportable segments’ long-lived assets, other than those of UGI International, are located in the United States.
F-62
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Total | Elim- inations | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Corporate & Other (b) | |||||||||||||||||||||
2017 | |||||||||||||||||||||||||||
Revenues from external customers | $ | 6,120.7 | $ | — | $ | 2,453.5 | $ | 1,877.5 | $ | 943.0 | $ | 847.5 | $ | (0.8 | ) | ||||||||||||
Intersegment revenues | $ | — | $ | (222.7 | ) | (c) | $ | — | $ | — | $ | 178.2 | $ | 40.1 | $ | 4.4 | |||||||||||
Cost of sales | $ | 2,837.3 | $ | (218.3 | ) | (c) | $ | 1,002.9 | $ | 935.3 | $ | 856.7 | $ | 367.3 | $ | (106.6 | ) | ||||||||||
Operating income | $ | 1,004.2 | $ | 0.3 | $ | 355.3 | $ | 195.7 | $ | 139.2 | $ | 228.3 | $ | 85.4 | |||||||||||||
Income from equity investees | $ | 4.3 | $ | — | $ | — | $ | — | $ | 4.3 | (d) | $ | — | $ | — | ||||||||||||
Losses on foreign currency contracts, net | $ | (23.9 | ) | $ | — | $ | — | $ | (0.1 | ) | $ | — | $ | — | $ | (23.8 | ) | ||||||||||
Loss on extinguishments of debt | $ | (59.7 | ) | $ | — | $ | (59.7 | ) | $ | — | $ | — | $ | — | $ | — | |||||||||||
Interest expense | $ | (223.5 | ) | $ | — | $ | (160.2 | ) | $ | (20.6 | ) | $ | (2.1 | ) | $ | (40.2 | ) | $ | (0.4 | ) | |||||||
Income before income taxes | $ | 701.4 | $ | 0.3 | $ | 135.4 | $ | 175.0 | $ | 141.4 | $ | 188.1 | $ | 61.2 | |||||||||||||
Net income attributable to UGI | $ | 436.6 | $ | 0.1 | $ | 44.6 | $ | 158.6 | $ | 86.9 | $ | 116.0 | $ | 30.4 | |||||||||||||
Depreciation and amortization | $ | 416.3 | $ | (0.2 | ) | $ | 190.5 | $ | 117.4 | $ | 35.4 | $ | 72.3 | $ | 0.9 | ||||||||||||
Noncontrolling interests’ net income | $ | 87.2 | $ | — | $ | 64.4 | $ | 0.2 | $ | — | $ | — | $ | 22.6 | |||||||||||||
Partnership Adjusted EBITDA (a) | $ | 551.3 | |||||||||||||||||||||||||
Total assets | $ | 11,582.2 | $ | (51.5 | ) | $ | 4,069.4 | $ | 3,132.0 | $ | 1,165.5 | $ | 2,994.0 | $ | 272.8 | ||||||||||||
Short-term borrowings | $ | 366.9 | $ | — | $ | 140.0 | $ | 17.9 | $ | 39.0 | $ | 170.0 | $ | — | |||||||||||||
Capital expenditures (including the effects of accruals) | $ | 624.3 | $ | — | $ | 98.1 | $ | 90.3 | $ | 117.5 | $ | 317.7 | $ | 0.7 | |||||||||||||
Investments in equity investees | $ | 59.1 | $ | — | $ | — | $ | 8.1 | $ | 51.0 | $ | — | $ | — | |||||||||||||
Goodwill | $ | 3,107.2 | $ | — | $ | 2,001.3 | $ | 912.2 | $ | 11.6 | $ | 182.1 | $ | — | |||||||||||||
2016 (f) | |||||||||||||||||||||||||||
Revenues from external customers | $ | 5,685.7 | $ | — | $ | 2,311.8 | $ | 1,868.8 | $ | 752.3 | $ | 751.4 | $ | 1.4 | |||||||||||||
Intersegment revenues | $ | — | $ | (133.9 | ) | (c) | $ | — | $ | — | $ | 114.3 | $ | 17.1 | $ | 2.5 | |||||||||||
Cost of sales | $ | 2,437.5 | $ | (131.5 | ) | (c) | $ | 864.8 | $ | 903.8 | $ | 602.2 | $ | 289.8 | $ | (91.6 | ) | ||||||||||
Operating income | $ | 988.0 | $ | 0.2 | $ | 356.3 | $ | 206.6 | $ | 146.7 | $ | 200.9 | $ | 77.3 | |||||||||||||
Loss from equity investees | $ | (0.2 | ) | $ | — | $ | — | $ | (0.2 | ) | $ | — | $ | — | $ | — | |||||||||||
Loss on extinguishments of debt | $ | (48.9 | ) | $ | — | $ | (48.9 | ) | $ | — | $ | — | $ | — | $ | — | |||||||||||
Interest expense | $ | (228.9 | ) | $ | — | $ | (164.1 | ) | $ | (24.4 | ) | $ | (2.1 | ) | $ | (37.6 | ) | $ | (0.7 | ) | |||||||
Income before income taxes | $ | 710.0 | $ | 0.2 | $ | 143.3 | $ | 182.0 | $ | 144.6 | $ | 163.3 | $ | 76.6 | |||||||||||||
Net income attributable to UGI | $ | 364.7 | $ | 0.1 | $ | 43.2 | $ | 111.6 | $ | 87.1 | $ | 97.4 | $ | 25.3 | |||||||||||||
Depreciation and amortization | $ | 400.9 | $ | (0.2 | ) | $ | 190.0 | $ | 112.4 | $ | 30.6 | $ | 67.3 | $ | 0.8 | ||||||||||||
Noncontrolling interests’ net income | $ | 124.1 | $ | — | $ | 75.9 | $ | — | $ | — | $ | — | $ | 48.2 | |||||||||||||
Partnership Adjusted EBITDA (a) | $ | 543.0 | |||||||||||||||||||||||||
Total assets | $ | 10,847.2 | $ | (136.6 | ) | $ | 4,071.8 | $ | 2,865.1 | $ | 1,038.2 | $ | 2,743.1 | $ | 265.6 | ||||||||||||
Short-term borrowings | $ | 291.7 | $ | — | $ | 153.2 | $ | 0.5 | $ | 25.5 | $ | 112.5 | $ | — | |||||||||||||
Capital expenditures (including the effects of accruals) | $ | 604.6 | $ | — | $ | 101.7 | $ | 99.9 | $ | 140.4 | $ | 262.5 | $ | 0.1 | |||||||||||||
Investments in equity investees | $ | 25.9 | $ | — | $ | — | $ | 8.5 | $ | 17.4 | $ | — | $ | — | |||||||||||||
Goodwill | $ | 2,989.0 | $ | — | $ | 1,978.3 | $ | 817.0 | $ | 11.6 | $ | 182.1 | $ | — | |||||||||||||
F-63
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Total | Elim- inations | AmeriGas Propane | UGI International | Midstream & Marketing | UGI Utilities | Corporate & Other (b) | |||||||||||||||||||||
2015 (f) | |||||||||||||||||||||||||||
Revenues from external customers | $ | 6,691.1 | $ | — | $ | 2,885.3 | $ | 1,808.5 | $ | 1,012.3 | $ | 981.9 | $ | 3.1 | |||||||||||||
Intersegment revenues | $ | — | $ | (213.6 | ) | (c) | $ | — | $ | — | $ | 151.3 | $ | 59.7 | $ | 2.6 | |||||||||||
Cost of sales | $ | 3,736.5 | $ | (209.8 | ) | (c) | $ | 1,340.0 | $ | 1,120.0 | $ | 854.6 | $ | 510.8 | $ | 120.9 | |||||||||||
Operating income (loss) | $ | 834.9 | $ | (0.9 | ) | $ | 427.6 | $ | 112.8 | $ | 182.6 | $ | 241.7 | $ | (128.9 | ) | |||||||||||
Loss from equity investees | $ | (1.2 | ) | $ | — | $ | — | $ | (1.2 | ) | $ | — | $ | — | $ | — | |||||||||||
Interest expense | $ | (241.9 | ) | $ | — | $ | (162.8 | ) | $ | (35.2 | ) | (e) | $ | (2.1 | ) | $ | (41.1 | ) | $ | (0.7 | ) | ||||||
Income (loss) before income taxes | $ | 591.8 | $ | (0.9 | ) | $ | 264.8 | $ | 76.4 | $ | 180.5 | $ | 200.6 | $ | (129.6 | ) | |||||||||||
Net income (loss) attributable to UGI | $ | 281.0 | $ | (0.6 | ) | $ | 61.0 | $ | 52.7 | $ | 107.5 | $ | 121.1 | $ | (60.7 | ) | |||||||||||
Depreciation and amortization | $ | 374.1 | $ | — | $ | 194.9 | $ | 86.9 | $ | 28.0 | $ | 63.5 | $ | 0.8 | |||||||||||||
Noncontrolling interests’ net income (loss) | $ | 133.0 | $ | — | $ | 167.9 | $ | (0.1 | ) | $ | — | $ | — | $ | (34.8 | ) | |||||||||||
Partnership Adjusted EBITDA (a) | $ | 619.2 | |||||||||||||||||||||||||
Total assets | $ | 10,514.2 | $ | (90.4 | ) | $ | 4,128.4 | $ | 2,860.9 | $ | 969.6 | $ | 2,506.0 | $ | 139.7 | ||||||||||||
Short-term borrowings | $ | 189.9 | $ | — | $ | 68.1 | $ | 0.6 | $ | 49.5 | $ | 71.7 | $ | — | |||||||||||||
Capital expenditures (including the effects of accruals) | $ | 475.4 | $ | — | $ | 102.0 | $ | 87.5 | $ | 88.0 | $ | 197.7 | $ | 0.2 | |||||||||||||
Investments in equity investees | $ | 16.2 | $ | — | $ | — | $ | 9.8 | $ | 6.4 | $ | — | $ | — | |||||||||||||
Goodwill | $ | 2,953.4 | $ | — | $ | 1,956.0 | $ | 803.7 | $ | 11.6 | $ | 182.1 | $ | — | |||||||||||||
(a) | The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: |
2017 | 2016 | 2015 | ||||||||||
Partnership Adjusted EBITDA | $ | 551.3 | $ | 543.0 | $ | 619.2 | ||||||
Depreciation and amortization | (190.5 | ) | (190.0 | ) | (194.9 | ) | ||||||
Interest expense | (160.2 | ) | (164.1 | ) | (162.8 | ) | ||||||
Loss on extinguishments of debt | (59.7 | ) | (48.9 | ) | — | |||||||
MGP environmental accrual | (7.5 | ) | — | — | ||||||||
Noncontrolling interest (i) | 2.0 | 3.3 | 3.3 | |||||||||
Income before income taxes | $ | 135.4 | $ | 143.3 | $ | 264.8 | ||||||
(i) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
(b) | Includes net pre-tax gains (losses) on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $82.0, $91.6 and $(119.1) in Fiscal 2017, Fiscal 2016 and Fiscal 2015, respectively. Fiscal 2017 also includes a pre-tax loss of $11.0 associated with the impairment of a cost basis investment (see Note 2). |
(c) | Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. |
(d) | Represents AFUDC associated with PennEast (see Note 2). |
(e) | Includes pre-tax costs of $10.3 associated with an extinguishment of debt (see Note 5). |
(f) | Restated to reflect the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments. |
F-64
UGI CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
BALANCE SHEETS
(Millions of dollars)
September 30, | |||||||
2017 | 2016 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 15.8 | $ | 4.8 | |||
Accounts receivable – related parties | 4.5 | 9.2 | |||||
Prepaid expenses and other current assets | 15.6 | 5.0 | |||||
Total current assets | 35.9 | 19.0 | |||||
Property, plant and equipment, net | 0.4 | — | |||||
Investments in subsidiaries | 3,119.7 | 2,825.7 | |||||
Other assets | 82.0 | 69.8 | |||||
Total assets | $ | 3,238.0 | $ | 2,914.5 | |||
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY | |||||||
Current liabilities: | |||||||
Accounts and notes payable | $ | 12.3 | $ | 11.4 | |||
Accrued liabilities | 5.9 | 4.4 | |||||
Total current liabilities | 18.2 | 15.8 | |||||
Noncurrent liabilities | 56.5 | 54.6 | |||||
Commitments and contingencies (Note 1) | |||||||
Common stockholders’ equity: | |||||||
Common Stock, without par value (authorized – 450,000,000 shares; issued – 173,987,691 and 173,894,141 shares, respectively) | 1,188.6 | 1,201.6 | |||||
Retained earnings | 2,106.7 | 1,834.1 | |||||
Accumulated other comprehensive loss | (93.4 | ) | (154.7 | ) | |||
Treasury stock, at cost | (38.6 | ) | (36.9 | ) | |||
Total common stockholders’ equity | 3,163.3 | 2,844.1 | |||||
Total liabilities and common stockholders’ equity | $ | 3,238.0 | $ | 2,914.5 | |||
Note 1 — Commitments and Contingencies:
In addition to the guarantees of Flaga’s debt as described in Note 5 to Consolidated Financial Statements, at September 30, 2017, UGI Corporation had agreed to indemnify the issuers of $88.9 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $500.0 of obligations to suppliers and customers of Energy Services, LLC and subsidiaries of which $432.5 of such obligations were outstanding as of September 30, 2017. UGI Corporation has guaranteed the floating to fixed rate interest rate swaps at Flaga, which obligations totaled $0.6 at September 30, 2017.
S-1
UGI CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
Year Ended September 30, | |||||||||||
2017 | 2016 | 2015 | |||||||||
Revenues | $ | — | $ | — | $ | — | |||||
Costs and expenses: | |||||||||||
Operating and administrative expenses | 46.3 | 45.7 | 48.7 | ||||||||
Other operating income, net (a) | (45.9 | ) | (45.3 | ) | (48.5 | ) | |||||
0.4 | 0.4 | 0.2 | |||||||||
Operating loss | (0.4 | ) | (0.4 | ) | (0.2 | ) | |||||
Intercompany interest income | — | 0.1 | 0.1 | ||||||||
Loss before income taxes | (0.4 | ) | (0.3 | ) | (0.1 | ) | |||||
Income tax (benefit) expense | (5.7 | ) | (4.0 | ) | 1.9 | ||||||
Income (loss) before equity in income of unconsolidated subsidiaries | 5.3 | 3.7 | (2.0 | ) | |||||||
Equity in income of unconsolidated subsidiaries | 431.3 | 361.0 | 283.0 | ||||||||
Net income attributable to UGI Corporation | $ | 436.6 | $ | 364.7 | $ | 281.0 | |||||
Other comprehensive income (loss) | 1.3 | (1.1 | ) | 0.1 | |||||||
Equity in other comprehensive income (loss) of unconsolidated subsidiaries | 60.0 | (39.0 | ) | (93.5 | ) | ||||||
Comprehensive income attributable to UGI Corporation | $ | 497.9 | $ | 324.6 | $ | 187.6 | |||||
Earnings per common share attributable to UGI Corporation stockholders: | |||||||||||
Basic | $ | 2.51 | $ | 2.11 | $ | 1.62 | |||||
Diluted | $ | 2.46 | $ | 2.08 | $ | 1.60 | |||||
Weighted - average common shares outstanding (thousands): | |||||||||||
Basic | 173,662 | 173,154 | 173,115 | ||||||||
Diluted | 177,159 | 175,572 | 175,667 | ||||||||
(a) | UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers the relative percentage of such items for each subsidiary to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to its subsidiaries. These billed expenses are classified as “Other operating income, net” in the Statements of Income above. |
S-2
UGI CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(Millions of dollars)
Year Ended September 30, | |||||||||||
2017 | 2016 | 2015 | |||||||||
NET CASH PROVIDED BY OPERATING ACTIVITIES (a) | $ | 253.2 | $ | 195.6 | $ | 277.2 | |||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||
Expenditures for property, plant and equipment | (0.4 | ) | — | — | |||||||
Net investments in unconsolidated subsidiaries | (40.7 | ) | (8.9 | ) | (104.8 | ) | |||||
Net cash used by investing activities | (41.1 | ) | (8.9 | ) | (104.8 | ) | |||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||
Payment of dividends on Common Stock | (168.9 | ) | (160.7 | ) | (153.5 | ) | |||||
Repurchases of UGI Common Stock | (43.3 | ) | (47.6 | ) | (34.1 | ) | |||||
Issuances of Common Stock | 11.0 | 24.5 | 16.8 | ||||||||
Other | 0.1 | — | (0.5 | ) | |||||||
Net cash used by financing activities | (201.1 | ) | (183.8 | ) | (171.3 | ) | |||||
Cash and cash equivalents increase | $ | 11.0 | $ | 2.9 | $ | 1.1 | |||||
Cash and cash equivalents: | |||||||||||
End of year | $ | 15.8 | $ | 4.8 | $ | 1.9 | |||||
Beginning of year | 4.8 | 1.9 | 0.8 | ||||||||
Increase | $ | 11.0 | $ | 2.9 | $ | 1.1 | |||||
(a) | Includes dividends received from unconsolidated subsidiaries of $241.9, $193.1 and $271.6 for the years ended September 30, 2017, 2016 and 2015, respectively. |
S-3
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)
Balance at beginning of year | Charged (credited) to costs and expenses | Other | Balance at end of year | |||||||||||||
Year Ended September 30, 2017 | ||||||||||||||||
Reserves deducted from assets in the consolidated balance sheet: | ||||||||||||||||
Allowance for doubtful accounts | $ | 27.3 | $ | 30.7 | $ | (31.1 | ) | (1) | $ | 26.9 | ||||||
Other reserves: | ||||||||||||||||
Deferred tax assets valuation allowance | $ | 114.3 | $ | (7.6 | ) | $ | 0.4 | (3) | $ | 107.1 | ||||||
Year Ended September 30, 2016 | ||||||||||||||||
Reserves deducted from assets in the consolidated balance sheet: | ||||||||||||||||
Allowance for doubtful accounts | $ | 29.7 | $ | 21.7 | $ | (24.1 | ) | (1) | $ | 27.3 | ||||||
Other reserves: | ||||||||||||||||
Deferred tax assets valuation allowance | $ | 131.3 | $ | (5.8 | ) | $ | (8.8 | ) | (3) | $ | 114.3 | |||||
(2.4 | ) | (4) | ||||||||||||||
Year Ended September 30, 2015 | ||||||||||||||||
Reserves deducted from assets in the consolidated balance sheet: | ||||||||||||||||
Allowance for doubtful accounts | $ | 39.1 | $ | 31.6 | $ | (39.6 | ) | (1) | $ | 29.7 | ||||||
(1.4 | ) | (2) | ||||||||||||||
Other reserves: | ||||||||||||||||
Deferred tax assets valuation allowance | $ | 59.2 | $ | 5.1 | $ | 66.1 | (3) | $ | 131.3 | |||||||
(2.6 | ) | (4) | ||||||||||||||
3.5 | (5) | |||||||||||||||
(1) | Uncollectible accounts written off, net of recoveries. |
(2) | Effects of currency exchange. |
(3) | Foreign tax credit valuation allowance adjustment. |
(4) | Decrease in unusable foreign operating loss carryforwards. |
(5) | Acquisitions |
S-4