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 and LPG suppliers, which increases the risks from an interruption in supply and transportation.
During Fiscal 2018, AmeriGas Propane purchased approximately 87% 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 LPG suppliers. For example, during Fiscal 2018, UGI International’s business in the United Kingdom purchased over 90% of its LPG needs from two suppliers and, in Italy, over 50% of UGI International’s supply was sourced from a single supplier. If supplies from UGI International’s principal LPG sources are interrupted, then the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and our earnings could be adversely affected. 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. Moreover, acquisitions may require antitrust and other regulatory clearances. We may have to offer commitments (such as agreements not to compete for certain businesses) or divest assets to obtain clearance, which may adversely affect the overall economics of the transaction.
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.
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 PAPUC. The PAPUC, among other things, approves the rates that UGI Utilities may charge its utility customers, thus impacting the returns that UGI Utilities may earn on the assets that are dedicated to its operations. We expect that UGI Utilities will periodically file requests with the PAPUC to increase base rates charged to customers. If UGI Utilities 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 PAPUC, particularly when necessary to cover increased costs, UGI Utilities’ 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 of these and other incidents, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business, including regulatory investigations, claims, lawsuits and other proceedings. 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. Moreover, defense and settlement costs may be substantial, even with respect to claims and investigations that have no merit. If we cannot resolve these matters favorably, our business, financial condition, results of operations and future prospects may be materially adversely affected.
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 the international level, many nations have agreed to limit emissions of GHGs pursuant to the United National Framework Convention on Climate Change, also known as the ‘‘Kyoto Protocol.’’ Further, as a result of commitments made at the UN
climate conference in Durban, South Africa in December 2011, certain members of the international community negotiated a treaty at the December 2015 Conference of Parties in Paris. The Paris Agreement, which entered into force in November 2016, requires developed countries to set targets for emissions reductions once the Paris Agreement is adopted by those countries within their respective national or federal law.
In the EU, there is a commitment to cut CO2 emissions by at least 40% by 2030 and EU member states have implemented a range of subsidies and incentives to achieve the EU’s climate change goals. Further, emissions are regulated via a number of means, including the European Union Emissions Trading System (‘‘EU ETS’’). The EU ETS is a trading system across the EU for industrial emissions. The EU ETS is expected to become progressively more stringent over time, including by reducing the number of allowances to emit GHGs. Further, in the EU, legislative proposals were made in 2017 to further reduce emissions from new cars. The proposed target is a 30% reduction by 2030.
In recent years, a number of jurisdictions have also imposed or discussed imposing bans on internal combustion engines in motor vehicles for the purpose of reducing GHG emissions, and these bans could expand to additional jurisdictions in the future. In the EU, legislative proposals were made in 2017 to further reduce emissions from new cars. The proposed target is a 30% reduction by 2030. The proposed scheme would also provide incentives for accelerating the uptake of zero- and low-emission vehicles. Manufacturers achieving a share of zero- and low-emission vehicles, exceeding the proposed benchmark level of 15% in 2025 and 30% in 2030, would be rewarded. Such proposals and the general push for electrification could reduce demand for LPG powered vehicles, although they have lower emissions than vehicles powered by gasoline and diesel.
Significant increases in cost of compliance for environmental certifications could materially impact our financial condition and results of operations.
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:
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costs and difficulties in staffing and managing international operations;
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potentially adverse tax consequences, including restrictions on repatriating earnings, potential increases to corporate income taxes and the threat of “double taxation”;
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fluctuations in currency exchange rates, which can affect demand for our products, increase our costs and adversely affect our profitability and reported results;
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regulatory requirements and changes in regulatory requirements, including European competition laws that may adversely affect the terms of contracts with customers, including with respect to exclusive supply rights, and stricter regulations applicable to the storage and handling of LPG;
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new and inconsistently enforced industry regulatory requirements, which can have an adverse effect on our competitive position;
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tariffs and other trade barriers;
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difficulties in enforcing contractual rights;
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longer payment cycles;
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local political and economic conditions;
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internal control and risk management practices and policies; and
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potential violations of federal regulatory requirements, including anti-bribery, anti-corruption, and anti-money laundering law, economic sanctions, the Foreign Corrupt Practices Act of 1977, as amended, and EU regulatory requirements, including the GDPR and Sapin II.
In particular, certain legal and regulatory risks are associated with international business operations. We are subject to various anti-corruption, economic sanctions and trade compliance laws, rules and regulations. For example, the U.S. government imposes restrictions and prohibitions on transactions in certain foreign countries, including restrictions directed at oil and gas activities in Russia, imposed in 2014 and amended in 2017. U.S. laws also prohibit the improper offer, payment, promise to pay, or authorization of the payment of money or anything of value to any foreign official or political party, or to any person, knowing that all or a portion of it will be used to influence a foreign official in his or her official duties or to secure an improper advantage. Ensuring compliance with all relevant laws, rules and regulations is a complex task. Violation of one or more of these laws, rules or
regulations could lead to loss of import or export privileges, civil or criminal penalties for us or our employees, or potential reputational harm, which could have a material adverse effect on earnings, cash flows and financial condition.
Changes in data privacy and data protection laws and regulations, particularly in Europe, or any failure to comply with 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 EU and elsewhere could impact our processing of personal and sensitive information of our employees, vendors and customers. The EU adopted the GDPR, which became effective in May of 2018. The GDPR expands the current EU data protections laws to all companies processing data of EU residents.
The GDPR requires companies to satisfy strict 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 require deletion of data about themselves. Although there is a consistency mechanism in the GDPR, data protection authorities from different EU member states may interpret and apply the GDPR somewhat differently, and the GDPR also permits EU member states to create supplemental national laws, which increases the complexity of compliance. Failure to comply with GDPR requirements could result in penalties of up to €20 million or 4% of worldwide revenue, whichever is greater, for serious breaches. While we have invested significant time and resources in preparing for and complying with the GDPR, the GDPR and other similar laws and regulations (including potential new data privacy laws and regulations in the U.S.), 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, 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 conditions 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, and for agricultural purposes such as crop drying, 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 typically been sold during these months. There can be no assurance that normal winter weather in our market areas will occur in the future.
In addition, our agricultural customers use LPG for purposes other than heating, including for crop drying, and unfavorable weather conditions, such as lack of precipitation, may impact the demand for LPG. Moreover, harsh weather conditions may at times impede the transportation and delivery of LPG, or restrict our ability to obtain LPG from suppliers. Spikes in demand caused by weather or other factors can stress the supply chain and limit our ability to obtain additional quantities of LPG. Changes in LPG supply costs are normally passed through to customers, but time lags (between when we purchase the LPG and when the customer purchases the LPG) may result in significant gross margin fluctuations that could adversely affect our results of operations.
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. Additionally, EU and local laws and regulations may require mandatory conservation measures, which would reduce the demand for our energy products. The EU is in the process of revising a directive on energy performance of buildings, with the goal to create a clear path towards a low and zero-emission building stock in the EU by 2050, which is underpinned by national roadmaps to decarbonize buildings. The EU is also adopting further measures to decarbonize electricity generation in order to reduce dependence on fossil fuel imports and achieve its climate change objectives. Over time, these various measures will impact fossil fuel consumption in Europe. 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 LPG and natural gas, changes in the market price of LPG and natural gas can create margin payment obligations for us and expose us to an increased liquidity risk. In addition, increased demand for domestically produced LPG and natural gas overseas may, depending on production volumes in the U.S., result in higher domestic LPG prices and expose us to additional liquidity risks.
Our potential to increase revenues may be affected by the decline in retail volumes of LPG and our ability to retain and grow our customer base.
The retail LPG distribution industry in the U.S. and many of the European countries in which we operate is mature and has been declining over the past several years, with no or modest growth (or decline) 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. and expansion in Europe, 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. Acquisitions in the U.S. and Europe may require merger control filings with the Federal Trade Commission and the European Commission, as applicable, and commitments or divestments of assets may be required to obtain clearance. Such commitments or divestments may influence the overall economics of the transaction.
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, including as a result of overpressurization of or damage to natural gas pipelines. Operation of UGI Utilities’ transmission and distribution systems below our expectations may result in lost revenues or increased expenses, including higher maintenance costs, civil litigation and the risk of regulatory penalties.
The risk of natural disasters and catastrophic events, including terrorism, may adversely affect the economy and the price and availability of LPG, other refined fuels and natural gas.
Natural disasters and catastrophic events, such as fires, earthquakes, explosions, floods, tornadoes, hurricanes, terrorist attacks, political unrest and other similar occurrences, may adversely impact the price and availability of LPG (including propane), other refined fuels and natural gas, which could adversely impact our financial condition and 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. A natural disaster or 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 LPG, fuel oil and natural gas, and our infrastructure facilities could be direct or indirect targets. A natural disaster or 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 a natural disaster or terrorism could also affect our ability to raise capital. We have opted to purchase insurance coverage for natural disasters and 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 natural disasters or 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, or 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 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 LPG distribution businesses compete for customers against suppliers of electricity, fuel oil and natural gas. Electricity is a major competitor of LPG but, except in France, is generally more expensive than LPG on a Btu equivalent basis for space heating, water heating and cooking. However, in Europe and elsewhere, climate change policies favoring electricity from renewable energy sources (“RES”) may cause changes in current relative price relationships. Moreover, 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 LPG but is currently more expensive than LPG as well as a less environmentally attractive energy source. Historically, however, fuel oil has been less expensive than LPG. Furnaces and appliances that burn LPG 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 LPG. Except for certain industrial and commercial applications, LPG 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 LPG. 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 LPG. As long as natural gas remains a less expensive energy source than LPG, our LPG 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 marketing, 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. The EU has committed to cut CO2 emissions by at least 40% by 2030 and EU member states have implemented a range of subsidies and incentives to achieve the EU’s climate change goals. 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 PAPUC 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:
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the discovery of presently unknown conditions;
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changes in environmental laws and regulations;
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judicial rejection of our legal defenses to third-party claims; or
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the insolvency of other responsible parties at the sites at which we are involved.
Moreover, if we discover additional contaminated sites, we could be required to incur material costs, which would reduce our net income.
We also may be unable to timely respond to changes within the energy and utility sectors that may result from regulatory initiatives to further increase competition within our industry. Such regulatory initiatives may create opportunities for additional competitors to grow their business or 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 fluctuations in response to changes in supply or other market conditions. We have no control over supplies, commodity prices or market conditions. Consequently, the unit price of the LPG that our subsidiaries and other distributors and 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. We also purchase a portion of our supplies in the spot market. Because our subsidiaries’ profitability is sensitive to changes in wholesale LPG supply costs, it will be adversely affected if we cannot pass on increases in the cost of LPG to our customers, or if there is a delay in passing on such cost increases. 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.
We offer our customers various fixed-price LPG programs, and a significant number of our customers utilize our fixed-price programs. In order to manage the price risk from offering these services, we utilize our physical inventory position, supplemented by forward commodity transactions with various third parties having terms and volumes substantially the same as our customer’s contracts, but there can be no assurance that such measures will be effective. In periods of high LPG price volatility, the fixed-price programs create exposure to over or under-supply positions as the demand from customers may significantly exceed or fall short of supply procured. In addition, if LPG prices decline significantly subsequent to customers signing up for a fixed-price program, there is a risk that customers will default on their commitments, adversely affecting our results of operations.
Economic recession, volatility in the stock market and the low interest rate environment may negatively impact our pension liability.
Economic recession, volatility in the stock market and the low interest rate environment have had a significant impact on our pension liability and funded status. Declines in the stock or bond market and valuation of stocks or bonds, combined with continued low interest rates, could further impact our pension liability and funded status and increase the amount of required contributions to our pension plans.
The adoption of financial reform legislation by the United States Congress and related regulations may have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.
Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Act”) in 2010, which contains comprehensive financial reform legislation. Our derivative hedging activities are subject to Title VII of the Act, which regulates the over-the-counter derivatives market and entities that participate in that market. The Act requires the Commodity Futures Trading Commission (“CFTC”) and other regulators to implement the Act’s provisions, including rules regarding mandatory clearing, trade execution and margin requirements. We expect to qualify for and rely upon an end-user exception from mandatory clearing and trade execution requirements for swaps entered into to hedge our commercial risks. Separately, unclear swap margin requirements do not apply to entities benefiting from the end-user exception. While most rules and regulations required to be issued by the CFTC under the Act have been finalized, 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, costs imposed upon our counterparties may increase the cost of our doing business in the derivatives markets to the extent such costs are passed on 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. The CFTC has re-proposed position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied. The CFTC has also finalized a related aggregation rule that requires market participants to aggregate their positions with certain other persons under common ownership and control, unless an exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position limit rule and its finalized companion rule on aggregation may have an impact on our ability to hedge exposure to price fluctuation of certain commodities. In addition to the CFTC federal position limit regime, designated contract markets also have established position limit and accountability regimes. We may have to modify trading decisions or liquidate positions to avoid exceeding such limits or at the direction of the exchange to comply with accountability levels. Further, any such position limit regime, whether imposed at the federal level or at the DCM level may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.
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.
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.
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, less favorable 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.
We may not be able to collect on the accounts of our customers.
We depend on the viability of our customers for collections of accounts receivable and notes receivable. Moreover, our businesses sell LPG to numerous retail customers, and as we grow our businesses through acquisitions, our retail customer base is expected to significantly expand. There can be no assurance that our customers will not experience financial difficulties in the future or that we will be able to collect all of our outstanding accounts receivable or notes receivable and any such nonpayment by our customers could adversely affect our business.
We depend on our intellectual property and failure to protect that intellectual property could have an adverse effect on us.
We seek trademark protection for our brands in each of our businesses, and we invest significant resources in developing our business brands. Failure to maintain our trademarks and brands could adversely affect our customer-facing businesses and our operational results.
Our ability to obtain sufficient quantities of LPG is dependent on transportation facilities and providers.
Spikes in demand caused by weather or other factors can limit our access to port terminals and other transportation and storage facilities, disrupt transportation and limit our ability to obtain sufficient quantities of LPG. A significant increase in port and similar fees and fuel prices may also adversely affect our transportation costs and business. Transportation providers (rail and truck) in some circumstances have limited ability to provide additional resources in times of peak demand. Moreover, our transportation providers maintaining a staff of qualified truck drivers is critical to the success of our business. Regulatory requirements and an improvement in the economy could reduce the number of eligible drivers or require us to pay higher transportation fees as our transportation providers seek to pass on additional labor costs associated with attracting and retaining drivers.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
With the exception of those matters set forth in Note 15 to Consolidated Financial Statements included in Item 15 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.
ITEM 4. MINE SAFETY DISCLOSURES
None.
EXECUTIVE OFFICERS
Information regarding our executive officers is included in Part III of this Report and is incorporated in Part I by reference.
PART II:
ITEM 5.
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.
Dividends
Quarterly dividends per common share on our Common Stock were paid in Fiscal 2018 and Fiscal 2017 as follows:
Record Holders
On November 13, 2018, UGI had 6,165 holders of record of Common Stock.
Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth information with respect to the Company’s repurchases of its Common Stock during the quarter ended September 30, 2018.
(1) Shares of UGI Corporation Common Stock are repurchased through an extension of a previous share repurchase program announced by the Company on January 25, 2018. The UGI Board of Directors authorized the repurchase of up to 8 million shares of UGI Corporation Common Stock over a four-year period expiring in January 2022.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
(a)
Fiscal 2018 results include impacts from the Tax Cuts and Jobs Act (“TCJA”) in the U.S. See Notes 6 and 8 to Consolidated Financial Statements for additional information.
(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 (1) 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
on such derivative instruments); (2) Finagaz integration and acquisition expenses; (3) losses on extinguishments of debt; (4) impairment of Partnership tradenames and trademarks; and (5) remeasurement impacts on deferred income tax balances resulting from the TCJA in the U.S. and changes in French tax rates 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.
ITEM 7.
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 for Fiscal 2018, Fiscal 2017 and Fiscal 2016, 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 peak heating-season months of October through March. Accordingly, our results of operations, after adjusting for the effects of gains and losses on derivative instruments not associated with current period transactions as further discussed below under “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share,” 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 financial measures not in accordance with accounting principles generally accepted in the United States of America (“GAAP”), 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 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. 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 associated with our European operations. For further information, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” below and Note 21 to Consolidated Financial Statements.
Executive Overview
Net Income Attributable to UGI Corporation by Business Unit (GAAP)
(a)
Fiscal 2018 net income attributable to UGI Corporation by business unit reflects the impacts of the TCJA in the U.S., and UGI International’s Fiscal 2018 and Fiscal 2017 net income also reflects the impacts of tax legislation in France. See “Impact of Tax Reform” below and Note 6 to Consolidated Financial Statements.
(b)
Corporate & Other includes net after-tax gains on commodity derivative instruments not associated with current-period transactions of $68.1 million, $51.2 million and $29.9 million in Fiscal 2018, Fiscal 2017 and Fiscal 2016, respectively. Corporate & Other also includes after-tax unrealized gains (losses) on certain foreign currency derivative instruments of $19.6 million and $(13.9) million in Fiscal 2018 and Fiscal 2017, respectively. See Note 21 to Consolidated Financial Statements for a discussion of amounts included in Corporate & Other.
Fiscal 2018 Financial Review
Our Fiscal 2018 operating results reflect temperatures based upon heating degree days that were normal, or slightly warmer than normal, in each of our business units’ service territories. Compared to Fiscal 2017, average temperatures in our domestic business units were significantly colder, while temperatures in our UGI International business in Europe were slightly warmer. After two
consecutive years of significantly warmer-than-normal weather in the U.S., the return of more normal weather in Fiscal 2018 enabled us to demonstrate the earnings potential of our existing businesses and our recent acquisitions and investments. Our Fiscal 2018 net income attributable to UGI also reflects the enactment of the TCJA.
Our net income attributable to UGI as determined in accordance with GAAP was $718.7 million, equal to $4.06 per diluted share, compared with $436.6 million, equal to $2.46 per diluted share, in Fiscal 2017. The significantly higher GAAP net income attributable to UGI and diluted earnings per share reflects, among other things, the remeasurement impacts on our deferred income tax assets and liabilities from the TCJA and changes in French income tax rates enacted in early Fiscal 2018. The higher Fiscal 2018 GAAP net income attributable to UGI and diluted earnings per share also reflect higher net gains on certain derivative instruments not associated with current-period transactions. Our adjusted net income attributable to UGI for Fiscal 2018 was $485.6 million, equal to $2.74 per diluted share, a 20% increase over Fiscal 2017’s adjusted net income and adjusted diluted earnings per share. Our Fiscal 2018 GAAP and adjusted net income attributable to UGI and GAAP and adjusted diluted earnings per share were records for the Company. For further information on our non-GAAP financial measures “adjusted net income attributable to UGI Corporation” and “adjusted diluted earnings per share,” including reconciliations of these measures to the most directly comparable GAAP measures, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” below. While the 20% increase in our adjusted results reflects the beneficial effects of the more favorable weather and the current-year benefits of the lower U.S. federal tax rate, it also reflects contributions from recent natural gas infrastructure investments relating to our growing network in the Marcellus Shale in Pennsylvania, growth initiatives at each of our business units and a base rate increase at UGI Utilities.
While average weather at each of our business units in Fiscal 2018 was normal, or slightly warmer than normal, each of our businesses responded well to significant variability in weather patterns during the Fiscal 2018 heating season. In our domestic operations, cold weather arrived later than normal with temperatures in October and November averaging nearly 10% warmer than normal. Extremely cold weather arrived in late December and early January in the U.S. This cold weather resulted in record peak day sendout at our Gas Utility for several consecutive days during the first week in January. In addition, our Midstream & Marketing business saw the return of price volatility and cold weather opportunities which favorably impacted capacity management and peaking margin. February temperatures in the U.S. were significantly warmer than normal but turned colder in mid-March through April, with April 2018 being the coldest in more than 20 years. At our UGI International business in Europe, retail LPG volumes early in Fiscal 2018 were reduced by an unfavorable fall crop drying season and temperatures that were warmer than normal. Our UGI International volumes benefited later in the heating season as a result of extremely cold weather in February and March, as many parts of Europe experienced cold and snow not experienced in decades.
As previously mentioned, our Fiscal 2018 results also include incremental earnings from recent investments, business acquisitions and organic growth. These incremental earnings include the full-year operation of the Sunbury Pipeline, incremental earnings from our Texas Creek natural gas gathering system, increases in peaking contracts and higher electricity generation volumes and unit margins at Midstream & Marketing; customer growth and the PNG rate case at UGI Utilities; continued growth in our ACE and National Accounts programs at AmeriGas Propane; and the DVEP and UniverGas acquisitions at UGI International.
Impact of Tax Reform
Our Fiscal 2018 results reflect the impacts of two significant tax law changes: the TCJA in the U.S. and December 2017 tax legislation in France (the “December 2017 French Finance Bills”). Among other things, the TCJA reduces the U.S. federal income tax rate from 35% to 21% effective January 1, 2018, creates a territorial tax system with a one-time mandatory “toll tax” on previously un-repatriated foreign earnings, and allows for immediate capital expensing of certain qualified property, which for UGI Utilities and certain FERC-regulated assets will be eliminated beginning in Fiscal 2019. The December 2017 French Finance Bills increased the Fiscal 2018 corporate income tax rate in France to 39.4% from 34.4%, but includes measures to reduce the corporate income tax rate, over time, to 25.8% effective for fiscal years starting after January 1, 2022 (Fiscal 2023).
As a result of the TCJA and the December 2017 French Finance Bills, during Fiscal 2018 we adjusted our deferred income tax assets and liabilities to remeasure our existing U.S. and French deferred income tax assets and liabilities at the new tax rates in the U.S. and France. The net adjustment to our deferred income tax assets and liabilities resulting from the TCJA reduced our Fiscal 2018 income tax expense by $166.3 million equal to $0.93 per diluted share. Due to the effects of utility ratemaking, most of the reduction in UGI Utilities’ deferred income tax assets and liabilities was not recognized immediately in income tax expense but has been reflected in regulatory assets and liabilities in accordance with utility ratemaking. The net adjustment to our deferred income tax assets and liabilities in France resulting from the December 2017 French Finance Bills reduced our Fiscal 2018 income tax expense by $12.1 million equal to $0.07 per diluted share. On a combined basis, these remeasurement adjustments to our deferred income tax assets and liabilities reduced our Fiscal 2018 income taxes, and increased our net income attributable to UGI, by $178.4 million or $1.01 per diluted share. Although these remeasurement adjustments decreased our income tax expense and increased our GAAP net income, we have eliminated these remeasurement adjustments from our non-GAAP adjusted results.
In addition to the remeasurement adjustments related to our U.S. and French income tax assets and liabilities, our income tax expense for Fiscal 2018 was further reduced by approximately $52.1 million (equal to $0.30 per diluted share) principally as a result of our lower Fiscal 2018 blended U.S. income tax rate of 24.5% compared to 35% previously. However, the impact of this decrease in income taxes was partially offset by the after-tax reduction in UGI Utilities’ revenues resulting from a May 2018 PAPUC Order. In accordance with this Order, UGI Utilities reduced its revenues by $24.1 million, and established an associated regulatory liability, related to $17.1 million (equal to $0.10 per diluted share) of tax benefits resulting from the change in the federal tax rate from 35% to 21% for the period January 1, 2018 through June 30, 2018. After adjusting for this reduction in UGI Utilities’ revenues, the impact of the TCJA increased Fiscal 2018 earnings (excluding the remeasurement effects previously mentioned) by $35.0 million (equal to $0.20 per diluted share). This Fiscal 2018 current-period benefit from the TCJA in the U.S. was reduced by a modest $0.6 million increase in Fiscal 2018 current-period income taxes in France resulting from the higher Fiscal 2018 French income tax rate.
In addition to the requirement to establish a regulatory liability for the tax benefits resulting from the TCJA for the period January 1, 2018 to June 30, 2018, the PAPUC also ordered each regulated utility currently not in a general base rate case proceeding to reduce their rates through a reconcilable negative surcharge applied to bills rendered on or after July 1, 2018. The negative surcharge will remain in place until the effective date of new rates established in the utility’s next general base rate proceeding. This negative surcharge effectively offsets the effects of the TCJA on income taxes at UGI Utilities until such effects are considered in future rate proceedings. The impact of the negative surcharge on net income for the period July 1, 2018 to September 30, 2018, was not material.
For further information on the TCJA, the December 2017 French Finance Bills, the regulatory impacts on UGI Utilities resulting from the TCJA and the actions of the PAPUC, see Notes 6 and 8 to Consolidated Financial Statements.
Strategic Initiatives
During Fiscal 2018, we continued to make significant strategic and operational progress in support of our long-term goals. AmeriGas Propane continued to drive costs out of the business through operating efficiencies, the application of technology solutions, and organizational management initiatives. Through continued expansion and enhancement of technology initiatives, AmeriGas Propane continued to reduce distribution costs and optimize delivery routing to increase the efficiency of its distribution model. AmeriGas Propane experienced a significant increase in the number of customer accounts registered for online capabilities and has developed and deployed other technology-enabled methods to communicate with customers. Volumes from the ACE cylinder program in Fiscal 2018 were the highest on record reflecting an increase in the number of retail locations including locations offering 24/7 automated self-service vending machines, and the National Account program’s performance in Fiscal 2018 benefited from double-digit volume growth due in large part to more normal winter weather and customer growth.
During Fiscal 2018, UGI International completed the integration of Finagaz acquired in May 2015 on time, achieving higher-than-expected synergies. In addition, UGI International integrated three smaller businesses acquired in late Fiscal 2017 and early Fiscal 2018, including LPG distribution businesses in Sweden and Italy as well as DVEP, a leading energy marketer in the Netherlands. In addition, UGI International centralized its European supply and commodity hedging functions in France, continued to build-out its cylinder distribution model including vending machines and expansion of retail chain customers, and executed the start-up of a natural gas marketing business in the United Kingdom. We also made significant progress on the implementation of the newly enacted European data privacy regulation, the Global Data Protection Regulation, across our European operations.
During Fiscal 2018, Midstream & Marketing acquired a midstream gas gathering system, Texas Creek, which included 60 miles of natural gas gathering lines, and acquired the Endless Mountain natural gas gathering system. Both of these gathering systems operate in the Marcellus Shale in northern Pennsylvania. Midstream & Marketing also acquired a 44 megawatt natural gas turbine adding capacity to the Hunlock site. In addition to these and other strategic asset acquisitions, Midstream & Marketing completed the Steelton LNG storage and vaporization unit, which is an important component of satisfying growing peak-day demand, and achieved several important milestones on the PennEast pipeline project including receipt of the FERC certificate of public convenience and necessity in January 2018.
UGI Utilities added over 14,000 new residential and commercial heating customers during Fiscal 2018 with conversions accounting for the majority of the additions. In January, UGI Utilities filed a base rate request for the Electric Division. New rates for Electric Utility went into effect in late October 2018. UGI Utilities continued to invest in its distribution system deploying nearly $340 million in capital, including approximately $185 million for replacement and betterment, and received regulatory approval for the merger of UGI Utilities’ three utility companies effective October 1, 2018. During Fiscal 2018, UGI Utilities also completed the design of UNITE Phase 2, its Enterprise Resource Planning (“ERP”) system, and made substantial progress on the build phases of the project. UGI Utilities also made significant progress toward the completion of its new corporate headquarters building, which is expected to be completed in the spring of Fiscal 2019.
At the UGI Corporation level, we implemented the first phase of a global human resource management tool for our domestic entities, made significant progress on a new enterprise performance management and reporting tool; and developed a global IT security framework.
Financing Transactions and Liquidity
In October 2017, UGI Utilities entered into a $125 million unsecured variable-rate term loan due through October 2022 with a group of banks. Proceeds from the Utilities Term Loan were used by UGI Utilities to repay revolving credit agreement borrowings and for general corporate purposes. We have entered into an interest rate swap that will fix the underlying interest rate on this debt at approximately 3% beginning September 30, 2019. In December 2017, AmeriGas Propane, L.P. (“AmeriGas OLP”) entered into the Second Amended and Restated Credit Agreement that provides for borrowings up to $600 million (including a $150 million sublimit for letters of credit) and expires in December 2022. Also in December 2017, UGI International, LLC entered into a secured multicurrency revolving facility with a group of banks providing for borrowings up to €300 million through 2020. As further described below, this revolving facility was replaced with a new revolving credit facility in October 2018 as part of the UGI International refinancing transaction.
On October 25, 2018, UGI International, LLC, a wholly owned second-tier indirect subsidiary of UGI Corporation, completed a significant refinancing transaction and (i) issued €350 million of 3.25% bonds due November 2025 through an underwritten private placement, (ii) borrowed €300 million under its 2018 UGI International Credit Facilities Agreement term loan facility, and (iii) entered into a €300 million multicurrency revolving credit facility. The €300 million term loan is due, and the new multicurrency revolving facility expires, in October 2023. The proceeds from the term loan and the 3.25% bonds plus cash on hand were used to repay UGI France’s and Flaga’s term loans ahead of schedule. For additional information on this refinancing, see “Financial Condition and Liquidity” below and Note 5 to Consolidated Financial Statements.
We believe each of our business units has sufficient liquidity to fund business operations during Fiscal 2019 (see “Financial Condition and Liquidity” below).
Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share
Adjusted Net Income Attributable to UGI Corporation by Business Unit (Non-GAAP)
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 (1) 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 on such derivative instruments); (2) Finagaz integration expenses; (3) losses on extinguishments of debt; (4) impairments of Partnership tradenames and trademarks; and (5) remeasurement impacts on income tax balances resulting from the enactments of the TCJA and French Finance Bills.
UGI does not designate its commodity and certain foreign currency derivative instruments as hedges under 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 unsettled commodity and certain foreign currency derivative instruments and, to a much lesser extent, certain realized gains and losses on settled commodity derivative instruments that are not associated with current-period transactions. 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 or losses will be largely offset by gains or losses on anticipated future energy commodity transactions or mitigate volatility in anticipated future earnings. For further information on the Company’s accounting for commodity and certain foreign currency derivative instruments, see Notes 2 and 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, to adjusted diluted earnings per share, to reflect the adjustments referred to above for Fiscal 2018, Fiscal 2017 and Fiscal 2016.
(a)
Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates.
(b)
Includes the effects of rounding.
Results of Operations
The following analyses compare the Company’s results of operations for (1) Fiscal 2018 with Fiscal 2017 and (2) Fiscal 2017 with Fiscal 2016.
Fiscal 2018 Compared with Fiscal 2017
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:
(a)
Fiscal 2018 net income attributable to UGI Corporation includes income (loss) from remeasurement adjustments to tax-related accounts as a result of the enactment of the TCJA as follows:
In addition to the remeasurement adjustments above, Fiscal 2018 income tax expense was reduced by an additional $52.1 million principally due to a lower federal income tax rate in Fiscal 2018 as a result of the TCJA.
(b)
Fiscal 2018 includes after-tax impairment charge of $14.5 million as a result of the plan to discontinue use of certain Partnership tradenames and trademarks.
(c)
Fiscal 2017 includes net after-tax loss of $9.6 million from extinguishments of debt.
(d)
Fiscal 2018 includes beneficial impact of a $12.1 million remeasurement adjustment to net deferred income tax liabilities associated with the enactment of the December 2017 French Finance Bills. Fiscal 2017 includes beneficial impact of a $29.0 million remeasurement adjustment to net deferred income tax liabilities associated with a change in French income tax rate and an income tax settlement refund of $6.7 million, plus interest, in France. In addition to these remeasurement adjustments, Fiscal 2018 also reflects the current-year negative impact of the December 2017 French Finance Bills which decreased Fiscal 2018 net income attributable to UGI by approximately $0.6 million.
(e)
Includes after-tax integration expenses associated with Finagaz of $18.5 million and $26.2 million for Fiscal 2018 and Fiscal 2017, respectively.
(f)
Fiscal 2018 includes reduction in net income of $17.1 million to reflect the establishment of a regulatory liability and associated deferred income taxes from tax savings incurred during the period January 1, 2018 to June 30, 2018 as a result of the TCJA.
(g)
Includes net after-tax gains on commodity derivative instruments not associated with current-period transactions of $68.1 million and $51.2 million for Fiscal 2018 and Fiscal 2017, respectively. Also includes after-tax unrealized gains (losses) on certain foreign currency derivative instruments of $19.6 million and $(13.9) million for Fiscal 2018 and Fiscal 2017, respectively.
(h)
Fiscal 2017 includes a $7.1 million after-tax loss associated with the impairment of a cost basis investment.
N.M. - Variance is not meaningful.
(a)
Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2018 and Fiscal 2017 excludes net pre-tax gains of $12.5 million and $31.1 million, respectively, on commodity derivative instruments not associated with current-period transactions.
(b)
Operating and administrative expenses in Fiscal 2017 include a $7.5 million environmental accrual associated with the site of a former manufactured gas plant (“MGP”) obtained in a prior-year acquisition (see Note 15 to Consolidated Financial Statements).
(c)
Fiscal 2018 reflects $75.0 million impairment charge associated with a plan to discontinue the use of certain Partnership tradenames and trademarks (see Note 11 to Consolidated Financial Statements).
(d)
Partnership Adjusted EBITDA should not be considered as an alternative to net income (loss) (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).
(e)
Fiscal 2017 reflects 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 reduced Partnership Adjusted EBITDA by $8.8 million and reduced operating income by $7.7 million.
(f)
Amounts for Fiscal 2017 reflect an adjustment to correct depreciation expense associated with prior periods which reduced operating income by $7.5 million.
(g)
Operating income reflects certain operating and administrative expenses of the General Partner.
(h)
Deviation from average heating degree days for the 15-year period 2002-2016 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.
N.M. - Variance is not meaningful.
AmeriGas Propane’s retail gallons sold during Fiscal 2018 were 3.3% higher than in Fiscal 2017. Average temperatures based upon heating degree days during Fiscal 2018 were 0.3% colder than normal and 13.0% colder than Fiscal 2017.
AmeriGas Propane retail propane revenues increased $337.9 million during Fiscal 2018 reflecting the effects of higher average retail selling prices ($267.5 million) and higher retail volumes sold ($70.4 million). Wholesale propane revenues increased $24.4 million reflecting the effects of higher average wholesale selling prices ($13.5 million) and higher wholesale volumes sold ($10.9 million). Average daily wholesale propane commodity prices during Fiscal 2018 at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 36% higher than such prices during Fiscal 2017. Other revenues in Fiscal 2018 were slightly higher than in the prior year principally reflecting higher service and ancillary revenues. AmeriGas Propane cost of sales increased $311.8 million principally reflecting the effects on propane cost of sales of higher average propane product costs ($266.1 million) and, to a much lesser extent, the effects of the higher retail and wholesale propane volumes sold ($39.6 million).
AmeriGas Propane total margin increased $57.7 million principally reflecting slightly higher retail propane total margin ($56.6 million) and slightly higher non-propane total margin ($1.1 million). The increase in retail propane total margin reflects the higher retail volumes sold and, to a much lesser extent, slightly higher average retail propane unit margins.
Partnership Adjusted EBITDA increased $54.2 million in Fiscal 2018 principally reflecting the effects of the higher total margin ($57.7 million) and higher other operating income ($12.5 million) partially offset by a $15.5 million increase in Partnership operating and administrative expenses (excluding the effects of the $7.5 million MGP accrual in the prior year). The increase in other operating income largely reflects the absence of an $8.8 million adjustment recorded in Fiscal 2017 to correct previously recorded gains on sales of fixed assets acquired with the Heritage Propane acquisition in 2012. The increase in Partnership operating and administrative expenses reflects, among other things, higher total compensation and benefits cost ($20.4 million), principally
higher labor, overtime and incentive compensation costs associated with the increased activity and improved performance; higher vehicle expenses ($10.6 million); and higher outside services expense ($6.3 million). These increases in operating expenses were partially offset by lower general insurance and self-insured casualty and liability expense and, to a lesser extent, lower provisions for uncollectible accounts and travel and entertainment expenses.
AmeriGas Propane operating income decreased $8.1 million in Fiscal 2018 as the $57.7 million increase in Partnership total margin, the higher other operating income ($12.5 million) and a decrease in depreciation and amortization expense ($4.8 million) were more than offset by the $75.0 million impairment of Partnership tradenames and trademarks and an $8.0 million increase in operating and administrative costs (including the effects of the $7.5 million MGP accrual in the prior year).
During Fiscal 2017, AmeriGas Partners recognized a pre-tax loss of $59.7 million ($9.6 million after-tax loss attributable to UGI) associated with early extinguishments of debt. For further information, see Note 5 to Consolidated Financial Statements.
(a)
Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2018 and Fiscal 2017 excludes net pre-tax gains of $92.8 million and $19.0 million, respectively, on commodity derivative instruments not associated with current-period transactions.
(b)
Reflects impacts of Finagaz integration expenses for Fiscal 2018 and Fiscal 2017 of $30.5 million and $39.9 million, respectively.
(c)
Income before income taxes for Fiscal 2018 and Fiscal 2017 excludes net pre-tax unrealized gains (losses) on certain foreign currency derivative contracts of $28.9 million and $(23.8) million, respectively.
(d)
Deviation from average heating degree days for the 15-year period 2002-2016 at locations in our UGI International service territories.
Average temperatures during Fiscal 2018 were approximately 5.3% warmer than normal and 5.9% warmer than Fiscal 2017. Total retail gallons sold during Fiscal 2018 were higher reflecting incremental LPG retail gallons sold from our October 2017 acquisition of UniverGas. Our existing businesses’ retail volumes were slightly lower than the prior year as slightly higher bulk sales late in the heating season were offset by the effects of warmer weather and lower crop-drying volumes early in Fiscal 2018. During Fiscal 2018, average wholesale prices for propane and butane in northwest Europe were approximately 23% and 19% higher than in Fiscal 2017, respectively.
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 2018 and Fiscal 2017, the average unweighted euro-to-dollar translation rates were approximately $1.19 and $1.11, respectively, and the average unweighted British pound sterling-to-dollar translation rates were approximately $1.35 and $1.27, respectively. Although the euro and British pound sterling were stronger during Fiscal 2018 and affect the comparison of line item amounts presented in the table above, the beneficial impact of the stronger currencies on net income was substantially offset by net losses on foreign currency exchange contracts.
UGI International revenues increased $806.3 million during Fiscal 2018 reflecting approximately $439 million of combined incremental revenues from UniverGas and DVEP, higher LPG selling prices and the translation effects on our existing businesses’ revenues of the stronger euro and British pound sterling. The higher LPG selling prices reflect in large part the effects of higher LPG product costs. UGI International cost of sales increased $684.8 million during Fiscal 2018 reflecting approximately $381 million of incremental cost of sales associated with UniverGas and DVEP, the effects on cost of sales from the higher average LPG commodity costs, and the translation effects of the stronger euro and British pound sterling.
The increase in total margin principally reflects the translation effects of the stronger euro and British pound sterling on margin (approximately $80 million), incremental margin from UniverGas and DVEP ($58 million), and slightly higher natural gas margin from our existing energy marketing business. These increases in margin were partially offset by slightly lower total margin from our existing retail LPG business reflecting in large part lower Fiscal 2018 income on foreign currency exchange contracts. Total margin from our existing natural gas business increased approximately $4.9 million reflecting higher subscription fee margin partially offset by lower average unit margins during Fiscal 2018.
The $27.4 million increase in UGI International operating income principally reflects the previously mentioned $121.5 million increase in total margin partially offset by a $77.0 million increase in operating and administrative expenses and a $23.2 million increase in depreciation and amortization expense. The increase in operating and administrative expenses principally reflects the translation effects of the stronger euro and British pound sterling on local currency expenses (approximately $45.0 million) and approximately $39 million of incremental expenses from UniverGas and DVEP. Our existing businesses’ local currency operating and administrative expenses, excluding Finagaz integration costs, were slightly lower than the prior year as lower compensation and benefits expense and lower tank and cylinder repair costs were largely offset by higher compliance costs associated with energy conservation and operational safety requirements and slightly higher distribution costs. Operating and administrative expenses in Fiscal 2018 and Fiscal 2017 include $30.5 million and $39.9 million of Finagaz integration costs, respectively. The increase in depreciation and amortization principally reflects incremental amounts associated with UniverGas and DVEP ($9.9 million) and the translation effects of the stronger currencies. UGI International income before income taxes increased $13.8 million principally reflecting the previously mentioned $27.4 million increase in UGI International operating income reduced by higher realized losses on foreign currency exchange contracts ($12.7 million) and slightly higher interest expense due to the effects of the stronger euro.
(a)
Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2018 and Fiscal 2017 excludes net pre-tax (losses) gains of $(1.4) million and $55.7 million, respectively, on commodity derivative instruments not associated with current-period transactions.
Temperatures across Midstream & Marketing’s energy marketing territory were approximately 1.5% warmer than normal during Fiscal 2018 but approximately 12.0% colder than Fiscal 2017. Midstream & Marketing’s Fiscal 2018 revenues were $300.5 million higher reflecting higher natural gas ($210.6 million) and retail power marketing ($15.0 million) revenues; higher revenues from midstream assets ($62.4 million), principally higher natural gas gathering, peaking, and capacity management revenues; and higher electric generation revenues ($13.1 million). The increase in natural gas revenues principally reflects the effects of higher natural gas volumes from colder Fiscal 2018 temperatures, customer growth and slightly higher average natural gas prices. The increase in capacity management and peaking revenues reflects the effects of colder weather in late December and January, higher capacity values, and with respect to peaking revenues, an increase in the number of peaking contracts. The higher natural gas gathering revenues principally reflects incremental revenues from the Sunbury Pipeline and from the Texas Creek natural gas gathering assets acquired on October 31, 2017. Electric generation revenues reflect higher volumes generated principally from the Hunlock natural-gas fired generation station and higher average selling prices. Midstream & Marketing cost of sales was $1,090.8 million in Fiscal 2018 compared to $856.7 million in Fiscal 2017, an increase of $234.1 million, principally reflecting higher natural gas and retail power cost of sales primarily a result of the higher natural gas and retail power volumes and higher average natural gas costs.
Midstream & Marketing total margin increased $66.4 million in Fiscal 2018 reflecting higher total margin from our midstream assets ($57.1 million), principally the result of higher natural gas gathering, capacity management and peaking total margin, and higher electricity generation total margin ($6.9 million). Fiscal 2018 total margin from natural gas marketing was about equal to Fiscal 2017 as slightly higher natural gas marketing volumes sold was offset by slightly lower average unit margins. The higher natural gas gathering total margin reflects incremental margin from the Sunbury Pipeline and, to a much lesser extent, higher margin from the recent expansion of our natural gas gathering assets including the Texas Creek natural gas gathering assets. The increase in capacity management and peaking total margin reflects in large part the effects of extremely cold weather primarily in late December and in January, higher capacity values and, with respect to peaking margin, a year-over-year increase in the
number of peaking contracts. The higher electricity generation total margin reflects higher electric generation volumes principally at our Hunlock Station generating facility and higher electricity unit margins.
The increase in Midstream & Marketing operating income principally reflects the previously mentioned increase in total margin ($66.4 million) partially offset by higher operating and administrative expenses ($18.4 million), higher depreciation expense ($8.1 million), and a decrease in other operating income primarily reflecting the absence of AFUDC income associated with the Sunbury Pipeline project recorded in Fiscal 2017 ($5.2 million). The $18.4 million increase in operating and administrative expenses reflects higher compensation and benefits expense and higher expenses associated with greater peaking, LNG and natural gas gathering activities, while the increase in depreciation expense principally reflects incremental depreciation from the expansion of our natural gas pipeline, natural gas gathering, LNG and peaking assets. The $34.9 million increase in income before income taxes in Fiscal 2018 principally reflects the higher operating income ($34.7 million) and slightly higher AFUDC income associated with our PennEast pipeline equity investment partially offset by slightly higher interest expense.
(a)
Gas Utility’s Fiscal 2018 revenues, total margin, operating income and income before income taxes were reduced by $24.1 million to record the effects of income tax savings that accrued during the period January 1, 2018 to June 30, 2018, in accordance with a PAPUC Order issued May 17, 2018, related to the TCJA (see Notes 6 and 8 to Consolidated Financial Statements). Although UGI Utilities’ income before income taxes for Fiscal 2018 was negatively impacted by this $24.1 million reduction in revenues, the impact on UGI Utilities’ net income was offset by a reduction in Fiscal 2018 income tax expense principally as a result of the lower federal income tax rate. The impact of the PAPUC Order on revenues for the period July 1, 2018 to September 30, 2018 was not material.
(b)
Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e., Electric Utility gross receipts taxes, of $5.0 million and $4.7 million during Fiscal 2018 and Fiscal 2017, respectively. For financial statement purposes, Electric Utility gross receipts taxes are included in “Operating and administrative expenses” on the Consolidated Statements of Income (but are excluded from operating and administrative expenses presented above).
(c)
Adjusted net income attributable to UGI Corporation is a non-GAAP measure. See “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” above for a reconciliation of UGI Utilities’ adjusted net income attributable to UGI Corporation to the most comparable GAAP measure.
(d)
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 2018 were 2.1% warmer than normal but 10.1% colder than Fiscal 2017. Gas Utility core market volumes increased 9.8 bcf (13.9%) reflecting, among other things, the effects of the colder weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 20.9 bcf principally reflecting higher large firm delivery service volumes 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 5.8% higher than Fiscal 2017, principally reflecting the effects of colder heating-season weather on heating-related sales, and the effects of warmer summer weather on air-conditioning sales.
UGI Utilities revenues increased $204.8 million reflecting a $195.7 million increase in Gas Utility revenues and a $9.1 million increase in Electric Utility revenues. In accordance with a PAPUC Order issued May 17, 2018, during Fiscal 2018 Gas Utility’s revenues were reduced by $24.1 million, and an associated regulatory liability was established, to record the effects of tax savings that accrued during the period January 1, 2018 to June 30, 2018 as a result of the TCJA. Excluding the impact on revenues from the PAPUC Order, Gas Utility revenues increased $218.8 million principally reflecting an increase in core market revenues ($143.0 million), higher off-system sales revenues ($54.6 million), and higher large firm delivery service revenues ($21.2 million).
The $143.0 million increase in Gas Utility core market revenues principally reflects the effects of the higher core market throughput ($70.7 million), higher average retail core market PGC rates ($61.4 million) and the increase in PNG base rates effective October 20, 2017 ($10.9 million). The increase in Electric Utility revenues principally reflects higher Electric Utility distribution system sales ($6.1 million) and higher average default service (“DS”) rates ($2.6 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 $522.9 million in Fiscal 2018 compared with $367.3 million in Fiscal 2017 principally reflecting higher Gas Utility cost of sales ($149.3 million) and higher Electric Utility cost of sales ($6.3 million). The higher Gas Utility cost of sales principally reflects higher average retail core market PGC rates ($61.4 million), higher cost of sales associated with Gas Utility off-system sales ($54.6 million), and higher retail core-market volumes ($26.8 million). The higher Electric Utility cost of sales reflects the higher electricity sales.
UGI Utilities total margin increased $48.9 million principally reflecting higher total margin from Gas Utility core market customers ($53.9 million) and higher large firm delivery service total margin ($15.8 million) partially offset by the reduction in margin resulting from the PAPUC’s May 17, 2018 Order regarding the effects of the TCJA. The increase in Gas Utility core market margin principally reflects the higher core market throughput ($44.6 million) and the increase in PNG base rates effective October 20, 2017 ($9.3 million). Electric Utility total margin increased $2.4 million principally reflecting the higher distribution system sales.
UGI Utilities operating income increased $9.2 million principally reflecting the increase in total margin ($48.9 million) partially offset by higher operating and administrative expenses ($21.4 million), greater depreciation expense ($12.3 million) associated with increased distribution system and IT capital expenditure activity, and lower other operating income ($6.1 million). The increase in UGI Utilities operating and administrative expenses principally reflects higher uncollectible accounts expense ($9.9 million), higher contractor and outside services expenses ($5.0 million), higher IT maintenance and consulting expenses ($4.0 million) and higher compensation and benefits expenses ($2.6 million). The decrease in other operating income principally reflects the absence of $5.8 million of income from an environmental insurance settlement recorded in Fiscal 2017. UGI Utilities income before income taxes increased $6.5 million reflecting the increase in UGI Utilities operating income ($9.2 million) partially offset by higher interest expense.
Although UGI Utilities pre-tax income increased a modest $6.5 million (3.5%) in Fiscal 2018 due to the impact on revenues from the PAPUC Order regarding income tax savings for the period January 1, 2018 to June 30, 2018, UGI Utilities adjusted net income attributable to UGI increased $24.9 million (21.5%). UGI Utilities Fiscal 2018 adjusted net income reflects the benefits of a $23.4 million decrease in current-year income taxes principally as a result of the lower federal income tax rate in Fiscal 2018.
Interest Expense and Income Taxes
Our consolidated interest expense during Fiscal 2018 was $230.1 million, $6.6 million higher than the $223.5 million of interest expense recorded during Fiscal 2017. The higher interest expense principally reflects the effects of higher long-term debt outstanding at UGI Utilities, higher average short-term borrowings and higher short-term interest rates, and the effects of the stronger euro on UGI International interest expense. These increases were partially offset by lower average interest rates on long-term debt at AmeriGas Propane and lower average debt outstanding at UGI International.
As previously mentioned, our consolidated income taxes for Fiscal 2018 were significantly impacted by the enactment of the TCJA in the U.S. and the December 2017 French Finance Bills. Our effective tax rate for Fiscal 2018 reflects the effects of deferred income tax asset and liability remeasurement adjustments resulting from the TCJA and the December 2017 French Finance Bills, which adjustments reduced Fiscal 2018 income tax expense by $178.4 million, and the lower blended U.S. federal income tax rate of 24.5% compared with 35% in Fiscal 2017. The effective income tax rate in Fiscal 2017 reflects the impact of a December 2016 change in the French corporate income tax rate for future years which reduced consolidated income tax expense by $29.0 million and, to a much lesser extent, the effects of an income tax settlement refund of $6.7 million, plus interest, in France.
Fiscal 2017 Compared with Fiscal 2016
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:
(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.
(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.
(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.
N.M. - Variance is not meaningful.
(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 commodity derivative instruments not associated with current-period transactions.
(b)
Partnership operating and administrative expenses in Fiscal 2017 include a $7.5 million environmental accrual associated with the site of a former MGP obtained in a prior-year acquisition (see Note 15 to Consolidated Financial Statements).
(c)
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).
(d)
Fiscal 2017 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 reduced Partnership Adjusted EBITDA by $8.8 million and reduced operating income by $7.7 million.
(e)
Fiscal 2017 reflects an adjustment to correct depreciation expense associated with prior periods which reduced operating income by $7.5 million.
(f)
Operating income reflects operating and administrative expenses of the General Partner.
(g)
Deviation from average heating degree days for the 15-year period 2002-2016 based upon national weather statistics provided by 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.
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 ($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 ($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.
(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)
LPG 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. LPG 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 15-year period 2002-2016 at locations in our UGI International service territories.
Average temperatures during Fiscal 2017 at UGI International were 0.7% colder than normal and 9.7% colder than Fiscal 2016. Total LPG 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 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.
(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 12.1% warmer than normal but 2.2% colder than in the prior year. Midstream & Marketing’s 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 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.
(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. Electric Utility gross receipt taxes are included in “Operating and administrative expenses” on the Consolidated Statements of Income (but are excluded from operating and administrative expenses presented above).
(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. 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 DS rates ($0.5 million) and lower transmission revenue ($0.4 million). 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 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 ($19.6 million) and higher depreciation 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 was lower in Fiscal 2017 compared with Fiscal 2016. The lower effective tax rate in Fiscal 2017 principally reflects (1) the remeasurement of our net deferred income 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 Fiscal 2017 income taxes 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 2 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.
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 $452.6 million at September 30, 2018, compared with $558.4 million at September 30, 2017. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30, 2018 and 2017, UGI had cash and cash equivalents of $194.3 million and $291.1 million, respectively, a substantial portion of which is 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, 2018, our 27% effective ownership interest in the Partnership consisted of approximately 24.7 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 2018, Fiscal 2017 and Fiscal 2016, the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner interest in the Partnership totaled $54.9 million, $52.7 million and $47.4 million, respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2018, Fiscal 2017 and Fiscal 2016 of $45.3 million, $43.5 million and $38.2 million, respectively (see Note 14 to Consolidated Financial Statements).
During Fiscal 2018, Fiscal 2017 and Fiscal 2016, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:
Cash dividends and other cash payments received from UGI International were lower in Fiscal 2018 due to the use of cash for the acquisition of UniverGas.
Dividends and Distributions
On April 24, 2018, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.26 per Common Share, equal to $1.04 on an annualized basis. The dividend rate reflects an approximately 4% increase from the previous quarterly rate of $0.25. The new quarterly dividend rate was effective with the dividend payable on July 1, 2018, to shareholders of record on June 15, 2018.
During Fiscal 2018, the General Partner’s Board of Directors approved, and AmeriGas Partners paid, quarterly distributions on AmeriGas Partners Common Units at a rate of $0.95 per Common Unit, equal to $3.80 per Common Unit for Fiscal 2018.
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 permitted the execution of the share repurchase program over a four-year period, which expired in January 2018. On January 25, 2018, UGI’s Board of Directors authorized an extension of the share repurchase program for up to 8 million shares of UGI Corporation Common Stock for an additional four-year period expiring in January 2022. Pursuant to
such authorizations, during Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Company purchased on the open market 1.2 million, 0.9 million and 1.25 million shares at a total purchase price of $59.8 million, $43.3 million and $47.6 million, respectively.
Long-term Debt and Credit Facilities
The Company’s debt outstanding at September 30, 2018 and 2017, comprises the following:
Long-term Debt
UGI International. In December 2017, Flaga repaid $9.2 million principal amount of its then-existing $59.1 million U.S. dollar denominated variable-rate term loan due September 2018. Concurrently, Flaga entered into an amendment to the aforementioned term loan, which amended the previous agreement to extend the maturity of the term loan to April 2020 (“Flaga U.S. Dollar Term Loan”). Prior to its repayment in October 2018 (see “Subsequent Event - UGI International Refinancing” below), borrowings under the Flaga U.S. Dollar Term Loan bore interest at the one-month LIBOR rate plus a margin of 1.125%. Flaga effectively fixed the LIBOR component of the interest rate, and effectively fixed the U.S. dollar value of the interest and principal payments payable under the Flaga U.S. Dollar Term Loan, by entering into a cross-currency swap arrangement with a bank.
UGI Utilities. In October 2017, UGI Utilities entered into a $125 million unsecured variable-rate term loan agreement (the “Utilities Term Loan”) with a group of banks. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement borrowings and for general corporate purposes. The Utilities Term Loan is payable in equal quarterly installments of $1.6 million, commencing in March 2018, with the balance of the principal being due and payable in full on October 30, 2022. 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. In July 2018, UGI Utilities entered into a forward-starting pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on Utilities Term Loan borrowings at approximately 3.00% through July 2022. This forward-starting interest rate swap commences September 30, 2019.
Subsequent Event - UGI International Refinancing
On October 18, 2018, UGI International, LLC, a wholly owned second-tier subsidiary of UGI, entered into a five-year unsecured Senior Facilities Agreement with a consortium of banks consisting of (1) a €300 million variable-rate term loan which was drawn on October 25, 2018, and (2) a €300 million senior unsecured multicurrency revolving facility agreement (together, the “2018 UGI International Credit Facilities Agreement”). The 2018 UGI International Credit Facilities Agreement matures on October 18, 2023. Term loan 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 zero. The margin on term loan borrowings, which ranges from 1.55% to 3.20%, is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. The initial margin on term loan borrowings is 1.70%. UGI International, LLC has entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on term loan borrowings at 0.34%. Under the multicurrency revolving credit facility agreement, UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus a margin ranging from 1.20% to 2.85%. Loans made in U.S. dollars will bear interest at the associated LIBOR rate plus a margin ranging from 1.45% to 3.10%. The margin on revolving facility borrowings is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined.
On October 25, 2018, UGI International, LLC issued in an underwritten private placement €350 million principal amount of 3.25% senior unsecured notes due November 1, 2025 (the “UGI International 3.25% Senior Notes”). The UGI International 3.25% Senior Notes rank equal in right of payment with indebtedness issued under the 2018 UGI International Credit Facilities Agreement.
The net proceeds from the UGI International 3.25% Senior Notes and the UGI International Credit Facilities Agreement variable-rate term loan plus cash on hand were used on October 25, 2018 (1) to repay €540 million outstanding principal of UGI France SAS’s variable-rate term loan under its 2015 Senior Facilities Agreement due April 2020; €45.8 million of outstanding principal of Flaga’s variable-rate term loan due October 2020; and $49.9 million of outstanding principal of Flaga’s U.S. dollar variable-rate term loan due April 2020, plus accrued and unpaid interest, and (2) for general corporate purposes.
For further information on these transactions and the Company’s other 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. UGI International principally uses borrowings under credit agreements and cash on hand to satisfy its 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. Borrowings under the credit facilities and the Energy Services, LLC Receivables Facility are classified as “Short-term borrowings” on the Consolidated Balance Sheets.
AmeriGas Partners. In December 2017, AmeriGas Partners entered into the Second Amended and Restated Credit Agreement (“AmeriGas Credit Agreement”) with a group of banks. The AmeriGas Credit Agreement amends and restates a previous credit agreement. The AmeriGas Credit Agreement provides for borrowings up to $600 million (including a $150 million sublimit for letters of credit) and expires in December 2022. The AmeriGas Credit Agreement permits AmeriGas to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin. The applicable margin on base rate borrowings ranges from 0.50% to 1.75%, and the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.75%.
UGI International. In December 2017, UGI International, LLC entered into a secured multicurrency revolving facility agreement (the "2017 UGI International Credit Agreement") with a group of banks providing for borrowings up to €300 million through April 2020. Under the 2017 UGI International Credit Agreement, UGI International, LLC could borrow in euros or U.S. dollars. During Fiscal 2018, there were no borrowings made under this facility. Upon entering into the 2018 UGI International Credit Facilities Agreement, we terminated (1) the 2017 UGI International Credit Agreement; (2) UGI France SAS’s revolving credit facility under its 2015 Senior Facilities Agreement; and (3) Flaga’s credit facility agreement.
UGI Utilities. In September 2018, UGI Utilities entered into an Increasing Lender Commitment and Acceptance (the “Commitment and Acceptance”) under UGI Utilities’ revolving credit agreement. The Commitment and Acceptance increased the amount of loan commitments under this revolving credit agreement to $450 million, from $300 million previously (including a $100 million sublimit for letters of credit), expiring in March 2020. All other terms of UGI Utilities’ revolving credit agreement remained unchanged.
Information about the Company’s principal credit agreements (excluding Energy Services, LLC’s Receivables Facility, which is discussed below) as of September 30, 2018 and 2017, is presented in the tables below.
(a)
Facility terminated on October 25, 2018, concurrent with entering into the 2018 UGI International Credit Facilities Agreement.
(b)
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.
(c)
On September 21, 2018, UGI Utilities entered into the Commitment and Acceptance, which increased the total capacity under this facility to $450 million.
The average daily and peak short-term borrowings under the Company’s principal credit agreements during Fiscal 2018 and Fiscal 2017 are as follows:
Energy Services, LLC also has a Receivables Facility with an issuer of receivables-backed commercial paper. On October 26, 2018, the expiration date of the Receivables Facility was extended to October 25, 2019. 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, 2018, the outstanding balance of trade receivables was $65.0 million of which $2.0 million was sold to the bank. At September 30, 2017, the outstanding balance of trade receivables was $44.8 million of which $39.0 million was sold to the bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Consolidated Balance Sheet. During Fiscal 2018 and Fiscal 2017, peak sales of receivables were $68.0 million and $49.0 million, respectively, and average daily amounts sold were $11.3 million and $14.0 million, respectively.
For detailed information on the Company’s short-term borrowings, see Note 5 to Consolidated Financial Statements.
Cash Flows
Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the fourth and first fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest.
Operating Activities:
Year-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 2018, Fiscal 2017 and Fiscal 2016 were $1,085.3 million, $964.4 million and $969.7 million, respectively. Cash flows from operating activities before changes in operating working capital were $1,219.7 million in Fiscal 2018, $1,133.0 million in Fiscal 2017 and $926.6 million in Fiscal 2016. The higher cash flow from operating activities before changes in operating working capital principally reflects improved year-over-year operating results. Changes in operating working capital (used) provided operating cash flow of $(134.4) million in Fiscal 2018, $(168.6) million in Fiscal 2017 and $43.1 million in Fiscal 2016. 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 2018 and Fiscal 2017 reflects, in large part, the net impact of increases in LPG and natural gas prices on accounts receivable, inventories and accounts payable. The higher cash used to fund changes in operating working capital in Fiscal 2018 also reflects federal income tax overpayments resulting from TCJA regulations released late in Fiscal 2018 regarding bonus depreciation for utility assets. In addition, cash flow from changes in operating working capital in Fiscal 2018 include net overcollections of UGI Utilities purchased gas and electricity costs of $31.0 million in Fiscal 2018, compared with net refunds of such costs of $15.4 million and $22.7 million in Fiscal 2017 and Fiscal 2016, respectively.
Investing Activities:
Investing activity cash flow is principally affected by cash expenditures for property, plant and equipment; cash paid for acquisitions of businesses and assets; 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 $574.4 million in Fiscal 2018, $638.9 million in Fiscal 2017 and $563.8 million in Fiscal 2016. Cash payments for property, plant and equipment were higher in Fiscal 2017 compared with Fiscal 2018 and Fiscal 2016 reflecting in large part higher Midstream & Marketing capital expenditures associated with the Sunbury Pipeline project. Net cash used for acquisitions of businesses and assets in Fiscal 2018 principally reflects the October 2017 acquisition of UniverGas at UGI International, and the acquisition of the Texas Creek natural gas gathering assets, a smaller natural gas gathering system and a power generation asset at Midstream & Marketing. Fiscal 2017 reflects net cash paid for acquisitions at AmeriGas Propane and UGI International including the acquisition of DVEP in August 2017. Net cash paid for acquisitions of businesses in Fiscal 2016 includes business acquisitions at AmeriGas Propane and UGI International. Changes in restricted cash, primarily cash in futures brokerage accounts, provided cash from investing activities of $0.7 million in Fiscal 2018, $6.1 million in Fiscal 2017 and $53.7 million in Fiscal 2016. 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.
In October 2017, UGI Utilities issued $125 million of unsecured notes and used the proceeds to reduce short-term borrowings and for general corporate purposes. Repayments of debt during Fiscal 2018 include UGI International’s repayments of approximately $82 million of term-loan debt at UGI France SAS and Flaga, and UGI Utilities’ repayments of $40 million of maturing Medium-Term Notes. 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 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 the effects of increases in quarterly dividend and distribution rates.
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 2018, Fiscal 2017 and Fiscal 2016. We also provide amounts we expect to spend in Fiscal 2019. We expect to finance a substantial portion of our Fiscal 2019 capital expenditures from cash generated by operations, borrowings under credit facilities and cash on hand.
The higher levels of UGI Utilities capital expenditures in Fiscal 2018 and Fiscal 2017, as well as those estimated for Fiscal 2019, reflect greater main replacement and system improvement capital expenditures, increases in new business capital expenditures and expected investments in new IT projects. The higher level of Midstream & Marketing capital expenditures estimated for Fiscal 2019 primarily reflect expected investments in new midstream assets and new IT projects.
Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2018. 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, 2018:
(a)
Based upon stated maturity dates for debt outstanding at September 30, 2018. Principal repayments relating to the UGI France Senior Facilities term loan due through April 2020; the Flaga variable-rate term loan due October 2020; and the Flaga U.S. dollar variable-rate term loan due April 2020, are included in the table above. These term loans were repaid on October 25, 2018 with net proceeds from the issuance of the UGI International 3.25% Senior Notes due November 2025 and the UGI International Credit Facilities Agreement due October 2023 (see “Subsequent Event - UGI International Refinancing” above and Note 5 to Consolidated Financial Statements).
(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 the September 30, 2018 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, 2018, principally comprise regulatory liabilities (see Note 8 to Consolidated Financial Statements); refundable tank and cylinder deposits (as further described in Note 2 to Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”); litigation, property and casualty liabilities and obligations under environmental remediation agreements (see Note 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 2019 are not expected to be material. Required minimum contributions to the U.S. Pension Plan in years beyond Fiscal 2019 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, 2018, the maximum potential amount of future payments under lease guarantees assuming the leased equipment was deemed worthless was approximately $55 million.
UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units
On November 7, 2017, UGI entered into the 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 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. There have been no capital contributions made to the Partnership under the Commitment Agreement.
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 $531.7 million and $498.0 million at September 30, 2018 and 2017, respectively. At September 30, 2018 and 2017, 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 $79.5 million and $141.2 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 2018 was $13.0 million. Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2019 is expected to be approximately $6.0 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, 2018, we have recorded after-tax charges to UGI Corporation’s stockholders’ equity of $11.0 million and recorded regulatory assets totaling $87.1 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 2018, Fiscal 2017 and Fiscal 2016, we did not enter into any related-party transactions that had a material effect on our financial condition, results of operations or cash flows.
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
Utilities Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and MDPSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. After receiving all necessary Federal Energy Regulatory Commission (“FERC”), MDPSC, and PAPUC approvals, CPG and PNG were merged into UGI Utilities effective October 1, 2018. Consistent with the MDPSC order issued July 25, 2018, and the PAPUC order issued September, 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type schedules for limited future ratemaking purposes.
Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution revenues by $9.2 million, which was later reduced by Electric Utility to $7.7 million to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $3.2 million annual base distribution rate increase for Electric Utility, effective October 27, 2018. As part of the final order, Electric Utility is required to provide customers with a one-time $0.2 million billing credit associated with 2018 TCJA tax benefits.
On August 31, 2017, the PAPUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for an $11.3 million base distribution rate increase for PNG (now the UGI North rate district of Gas Utility). The increase became effective October 20, 2017.
On October 14, 2016, the PAPUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27.0 million base distribution rate increase for UGI Gas (now the UGI South rate district of Gas Utility). The increase became effective on October 19, 2016.
Distribution System Improvement Charge. State legislation permits gas and electric utilities in Pennsylvania to recover a distribution system improvement charge (“DSIC”) on eligible capital investments as an alternative ratemaking mechanism providing for a more timely cost recovery of qualifying capital expenditures between base rate cases.
PNG and CPG received PAPUC 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 May 2017, the PAPUC 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. PNG’s DSIC has been reset to zero as a result of its most recent base rate case. The DSIC rate for PNG will resume under the UGI North rate district upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its most recent base rate case.
In November 2016, UGI Gas received PAPUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas began recovering revenue under the mechanism effective July 1, 2018, as it exceeded, during the third quarter of Fiscal 2018, the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.
Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017 explosion in Manor Township, Lancaster County, PA, that resulted in the death of one UGI Utilities’ employee and injuries to two other UGI Utilities’ employees
and one sewer authority employee, and destroyed two residences and damaged several other homes, the PAPUC Bureau of Investigation and Enforcement (“BIE”) filed a formal complaint at the PAPUC in which BIE alleges that UGI Utilities committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion, and requested that the PAPUC order UGI Utilities to pay approximately $2.1 million in civil penalties, which is the maximum allowable fine. On November 16, 2018, UGI Utilities filed its formal written answer contesting the BIE complaint.
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 now constituting UGI Gas and Electric Utility. Beginning in 2006 and 2008, UGI Utilities also owned and operated two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. CPG and PNG were merged into UGI Utilities effective October 1, 2018.
Prior to the Utilities Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, were subject to a consent order and agreement (“COA”) with the Pennsylvania Department of Environmental Protection (“PADEP”) to address the remediation of specified former MGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the merger, UGI Utilities, as the successor to CPG and PNG, is 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 and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap. The cost cap of the three COAs, in the aggregate, is $5.4 million. The three COAs are currently scheduled to terminate at the end of 2031, 2020 and 2020. At September 30, 2018 and 2017, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $51.0 million and $54.3 million, respectively. UGI Utilities has 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 receives 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, 2018 and 2017, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside 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 keep pace with such increases, 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 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 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 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 financial transmission rights (“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 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, the Utilities Term Loan and, prior to their repayment on October 25, 2018, 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 Utilities has entered into a forward-starting, amortizing, pay-fixed, receive-variable interest rate swap agreement commencing September 30, 2019. Prior to their repayment on October 25, 2018, UGI France SAS and Flaga, through the use of pay-fixed, receive-variable interest rate swaps, had fixed the underlying euribor interest rates on their euro-denominated term loans through all, or a substantial portion of, the periods such debt was outstanding. In addition, prior to its repayment on October 25, 2018, Flaga’s U.S. dollar-denominated loan had 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, 2018, 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 $545.2 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 2018 interest expense by approximately $5 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 $228 million at September 30, 2018. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of approximately $254 million at September 30, 2018.
As previously mentioned, in October 2018, UGI International entered into the 2018 UGI International Credit Facilities Agreement, which includes a $300 million variable-rate term loan maturing in October 2023. In November 2018, UGI International, LLC entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on 2018 UGI International Credit Facilities Agreement term loan borrowings at 0.34%. We have designated these forward-starting interest rate swaps as cash flow hedges.
As previously mentioned, in October 2017, UGI Utilities entered into a $125 million variable-rate Term Loan. In July 2018, UGI Utilities entered into a forward-starting, pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on UGI Utilities Term Loan borrowings at approximately 3.00% through July 2022. This forward-starting interest rate swap commences September 30, 2019. We have designated this forward-starting interest rate swap as a cash flow hedge.
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, 2018, 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, 2018, by approximately $140 million, which amount would be reflected in other comprehensive income. In October 2018, concurrent with entering into the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes, we designated borrowings under these agreements as net investment hedges.
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 and prior to its related loan repayment on October 25, 2018, Flaga entered 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 its U.S. dollar denominated variable-rate term loan. These cross-currency hedges included 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 included interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate.
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, 2018, restricted cash in brokerage accounts totaled $9.6 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, 2018. 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, 2018, 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, 2018. 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 prevailing market interest 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 commodity 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.
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.
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.
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, 2018, our goodwill totaled $3,160.4 million. We did not record any impairments of goodwill in Fiscal 2018, Fiscal 2017 or Fiscal 2016.
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 2018, Fiscal 2017 or Fiscal 2016.
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 no amount within a range of possible loss is a better estimate than any other amount within the range, liabilities recorded are based upon the low end of the 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 and estimated reserves are adjusted.
Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation by the PAPUC. 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 PAPUC, 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, 2018, our regulatory assets and regulatory liabilities totaled $301.0 million and $390.2 million, respectively. For additional information on regulatory assets and liabilities, see Notes 2 and 8 to Consolidated Financial Statements.
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 PAPUC 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, 2018, the net fair value of our derivative assets totaled $186.0 million and the net fair value of our derivative liabilities totaled $24.5 million.
Income Taxes. We use the asset and liability method of accounting for income taxes. Under this method, income tax expense is recognized for the amount of taxes payable or refundable for the current year and for deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. Positions taken by an entity in its tax returns must satisfy a more-likely-than-not recognition threshold assuming the positions will be examined by tax authorities with full knowledge of relevant information. We use assumptions, judgments and estimates to determine our current provision for income taxes. We also use assumptions, judgments and estimates to determine our deferred tax assets and liabilities and any valuation allowance to be recorded against a deferred tax asset. Our assumptions, judgments and estimates relative to the current provision for income tax give consideration to current tax laws, our interpretation of current tax laws and possible outcomes of current and future audits conducted by foreign and domestic tax authorities. Changes in tax law or our interpretation thereof and the resolution of current and future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. Our assumptions, judgments and estimates relative to the amount of deferred income taxes take into account estimates of the amount of future taxable income. Actual taxable income or future estimates of taxable income could render our current assumptions, judgments and estimates inaccurate. Changes in the assumptions, judgments and estimates mentioned above could cause our actual income tax obligations to differ significantly from our estimates. As of September 30, 2018, our net deferred tax liabilities totaled $980.9 million.
Recently Issued Accounting Pronouncements
See Note 3 to the Consolidated Financial Statements for a discussion of the effects of recently issued accounting guidance.
ITEM 7A.
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.
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 of this Report are incorporated herein by reference.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
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, 2018, were effective at the reasonable assurance level.
(b)
For “Management’s Annual Report on Internal Control Over Financial Reporting” see Item 8 of this Report (which information is incorporated herein by reference).
(c)
During the most recent fiscal quarter, no change in the Company’s internal control over financial reporting occurred that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
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, 2018.
Information
Captions of Proxy Statement
Incorporated by Reference
Item 10.
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.
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.
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.
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.
Item 14.
Principal Accounting Fees and Services
Our Independent Registered Public Accounting Firm
Equity Compensation Table
The following table sets forth information as of the end of Fiscal 2018 with respect to compensation plans under which our equity securities are authorized for issuance.
(1)
Represents 8,197,069 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 9,043,267 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 959,718 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
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.
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 (since 2005) 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 Greater Philadelphia and Southern New Jersey, the World Affairs Council of Philadelphia, the Greater Philadelphia Chamber of Commerce, the Satell Institute, and the Philadelphia Zoo, and as Trustee at the Saint Columbkille Partnership School.
Ted J. Jastrzebski
Mr. Jastrzebski is Chief Financial Officer of UGI Corporation (since May 2018). Mr. Jastrzebski also serves as Principal Financial Officer of AmeriGas Propane, Inc. (since September 18, 2018). From 2013 until 2018, Mr. Jastrzebski served as Executive Vice President and Chief Financial Officer of Qurate Retail Group, which is comprised of QVC, HSN, Cornerstone Brands, and Zulily. Previously, Mr. Jastrzebski held various positions at The Hershey Company, including Senior Vice President and President, Hershey Americas (2011 to 2013), Senior Vice President and President, Hershey International (2007 to 2010) and Vice President, Finance, Hershey International (2004 to 2007). Mr. Jastrzebski also served as Senior Vice President, Finance, IT and Administration and Chief Financial Officer of CARE (2002 to 2004) and as Vice President and Chief Financial Officer of Project Hope (1999 to 2002).
Robert F. Beard
Mr. Beard is Executive Vice President, Natural Gas (since September 18, 2018) and 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.
Roger Perreault
Mr. Perreault is Executive Vice President, Global LPG of UGI Corporation (since September 2018), President - UGI International, LLC (since December 2015), and a Director of AmeriGas Propane, Inc. (since October 1, 2018). Prior to joining UGI Corporation, Mr. Perreault held various positions at Air Liquide, an industrial gases company he joined in 1994, and served in various leadership positions from 2008 to 2014, including in a global role as President, Large Industries with international responsibilities and, prior to that, in a role with responsibility for Air Liquide’s North American large industries business. Prior to joining Air Liquide, Mr. Perreault was a chemical engineer and operations manager with I.C.I. in Quebec, Canada.
Hugh J. Gallagher
Mr. Gallagher is President and Chief Executive Officer (since September 2018) and a Director (since October 1, 2018) of AmeriGas Propane, Inc. Previously he served as Vice President - Finance and Chief Financial Officer of the General Partner (2013 to 2018). He has also served as Treasurer of both UGI Corporation and the General Partner (2011 to 2014), Director - Treasury Services and Investor Relations of UGI Corporation (2009 to 2011) and Director - Treasury Services (2007 to 2009) of UGI Corporation. He has also served as the General Partner’s Director - Business Development (2004 to 2007), Director of Financial Planning and Analysis (2000 to 2004), Financial Manager - Operations (1999 to 2000), Manager of Financial Reporting (1996 to 1999), and Team Leader - Financial Reporting (1995 to 1996). Mr. Gallagher joined UGI Corporation in 1990, serving in various finance and accounting roles of increasing responsibility.
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 Utilities, Inc. in 1985 as an accountant and has held various positions of increasing responsibility at UGI Utilities and UGI Energy Services, including Vice President - Assets and Supply and Chief Financial Officer.
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 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).
Ann P. Kelly
Ms. Kelly is Vice President, Chief Accounting Officer and Corporate Controller of UGI Corporation (since March 2018). She previously served as Assistant Treasurer of UGI Corporation (2016 to 2018) and Controller and Chief Accounting Officer of UGI Utilities, Inc. (2014 to 2016). Prior to joining UGI Utilities, Inc., Ms. Kelly held the position of Chief Financial Officer of JGM, Inc. (2013 to September 2014). She previously held roles of increasing responsibility in finance and accounting at Preferred Sands (February 2012 to July 2012), Exelon Generation (2007 to 2009 and 2010 to 2012), PECO Energy Company (2009 to 2010), Radnor Holdings Corporation (1997 to 2007), PricewaterhouseCoopers LLP (1994 to 1997) and Dean Witter Reynolds (1992 to 1994).
PART IV:
ITEM 15.
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, 2018 and 2017
Consolidated Statements of Income for the years ended September 30, 2018, 2017 and 2016
Consolidated Statements of Comprehensive Income for the years ended September 30, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the years ended September 30, 2018, 2017 and 2016
Consolidated Statements of Changes in Equity for the years ended September 30, 2018, 2017 and 2016
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, 2018, 2017 and 2016
We have omitted all other financial statement schedules because the required information is (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
(3)
List of Exhibits:
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
*
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.
EXHIBIT INDEX
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 20, 2018, 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/ Ted J. Jastrzebski
Chief Financial Officer (Principal Financial Officer)
Ted J. Jastrzebski
/s/ Ann P. Kelly
Vice President, Chief Accounting Officer and Corporate Controller (Principal Accounting Officer)
Ann P. Kelly
/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/ Alan N. Harris
Director
Alan N. Harris
/s/ Frank S. Hermance
Director
Frank S. Hermance
/s/ Anne Pol
Director
Anne Pol
/s/ James B. Stallings, Jr.
Director
James B. Stallings, Jr.
UGI CORPORATION AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2018
UGI CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
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.
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 public accounting firm and internal auditors. The Committee meets regularly, with and without management present, with the independent registered public 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”).
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, 2018, based on the COSO criteria. 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, 2018, as stated in their report, which appears herein.
/s/ John L. Walsh
Chief Executive Officer
/s/ Ted J. Jastrzebski
Chief Financial Officer
/s/ Ann P. Kelly
Chief Accounting Officer
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of UGI Corporation
Opinion on Internal Control over Financial Reporting
We have audited UGI Corporation and subsidiaries’ internal control over financial reporting as of September 30, 2018, 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). In our opinion, UGI Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of September 30, 2018, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of September 30, 2018 and 2017, 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, 2018, and the related notes and the financial statement schedules listed in the Index at Item 15(a) and our report dated November 20, 2018 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’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 are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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.
Definition and Limitations of Internal Control Over Financial Reporting
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.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
November 20, 2018
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of UGI Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of UGI Corporation and subsidiaries (the Company) as of September 30, 2018 and 2017, 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, 2018, and the related notes and the financial statement schedules listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2018, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of September 30, 2018, 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 20, 2018, expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2014.
Philadelphia, Pennsylvania
November 20, 2018
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
See accompanying Notes to Consolidated Financial Statements.
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
See accompanying Notes to Consolidated Financial Statements.
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of dollars)
See accompanying Notes to Consolidated Financial Statements.
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
See accompanying Notes to Consolidated Financial Statements.
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions of dollars, except per share amounts)
See accompanying Notes to Consolidated Financial Statements.
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 of Businesses and Assets
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, 2018, the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.0% 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”), through subsidiaries, conducts (1) an LPG distribution business throughout much of Europe and (2) an energy marketing business in France, Belgium, the Netherlands and the United Kingdom. These businesses are conducted principally through our subsidiaries, UGI France SAS (“UGI France”), Flaga GmbH (“Flaga”), AvantiGas Limited (“AvantiGas”), DVEP Investeringen B.V. (“DVEP”) and UniverGas Italia S.r.l. (“UniverGas”). We refer to our foreign operations collectively as “UGI International.”
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,
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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”) owns and operates a natural gas distribution utility business (“Gas Utility”) directly and, prior to their merger with and into UGI Utilities effective October 1, 2018 (see Note 8), through its wholly owned subsidiaries, UGI Penn Natural Gas, Inc. and UGI Central Penn Gas, Inc. The terms “PNG” and “CPG” are used herein as abbreviated references to UGI Penn Natural Gas, Inc. and UGI Central Penn Gas, Inc., respectively, or to their associated natural gas utilities. 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 (“PAPUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission (“MDPSC”). Electric Utility is subject to regulation by the PAPUC and the Federal Energy Regulatory Commission (“FERC”). 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.
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 totaled $147.2 and $120.4 at September 30, 2018 and 2017, respectively, and are included in “Other assets” on the Consolidated Balance Sheets.
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 120-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, 2018 and 2017 totaled $72.6 and $51.0, 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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 normal purchase and normal sale (“NPNS”) exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument, whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes.
Certain of our derivative instruments qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”), 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. We do not designate our commodity and certain foreign currency derivative instruments as hedges under GAAP. Changes in the fair values of these derivative instruments are reflected in net income. Gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. From time to time, we also enter into net investment hedges. 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.
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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
and losses on these contracts are recorded in “Gain (loss) on foreign currency contracts, net” on the Consolidated Statements of Income.
Cash flows from derivative instruments, other than certain cross-currency swaps and net investment hedges, if any, are included in cash flows from operating 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 flows from operating activities while cash flows from the currency portion of such hedges, if any, are included in cash flows from financing activities. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Consolidated Statements of Cash Flows.
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. Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise with the impact of subsequent changes in such rates reflected in the income statement. The functional currency of a significant portion of our international operations is the euro.
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 “Operating and administrative expenses” 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 and amortization” on the Consolidated Statements of Income.
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 Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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. At September 30, 2018 and 2017, such deferred investment tax credits totaled $2.6 and $2.9, respectively.
We record interest on underpayments and overpayments of income taxes, and income tax penalties, in “Income taxes” on the Consolidated Statements of Income. For Fiscal 2018, Fiscal 2017 and Fiscal 2016, interest income or expense recognized in “Income taxes” on the Consolidated Statements of Income was not material.
The Tax Cuts and Jobs Act (“TCJA”) was enacted on December 22, 2017, and includes a broad range of tax reform provisions affecting the Company, including, among other things, changes in the U.S. corporate income tax rate. The TCJA reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. We are subject to a 24.5% blended U.S. federal income tax rate for Fiscal 2018 because our fiscal year contains the effective date of the rate change from 35% to 21%. In accordance with GAAP, at the date of enactment of the TCJA our federal deferred income taxes, including deferred income taxes related to items included in AOCI, were remeasured based upon the new corporate income tax rate. For our non-utility businesses, existing deferred income tax assets or liabilities were adjusted for the reduction in the corporate income tax rate and the adjustment recorded in the provision for income taxes. Our utility businesses are also required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in income tax rates on deferred income tax balances will be recovered or refunded in future rates, our rate-regulated utility businesses record a regulatory asset or liability associated with these deferred income tax assets and liabilities. For additional information regarding the impact of the TCJA and associated regulatory effects, see Notes 6 and 8.
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 2018, Fiscal 2017 and Fiscal 2016:
(a)
For Fiscal 2018, Fiscal 2017 and Fiscal 2016, there were 0 shares, 146 shares and 38 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive.
Cash and Cash Equivalents
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.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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.
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at the lower of original cost or fair value, if impaired. 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”). We also include in property, plant and equipment costs associated with computer software we develop or obtain for use in our business. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition. When we retire or otherwise dispose of non-utility plant and equipment, we eliminate the associated cost and accumulated depreciation and recognize any resulting gain or loss in "Other operating income, net" on the Consolidated Statements of Income.
We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives. At September 30, 2018, estimated useful lives by asset type were as follows:
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 2018, 2017 and 2016 were as follows:
UGI Utilities’ information technology (“IT”) costs associated with major IT system installations, conversions and improvements, such as software training, data conversion, business process reengineering costs, preliminary project stage costs and cloud computing are deferred as a regulatory asset and included as a component of property, plant and equipment. As of September 30, 2018, approximately $6.3 of these costs have been deferred as a regulatory asset and have not yet been requested in a rate proceeding. UGI Utilities amortizes computer software and related IT system installation costs on a straight-line basis over expected periods of benefit not exceeding 15 years once the installed software is ready for its intended use.
We classify amortization of computer software and related IT system installation costs included in property, plant and equipment as depreciation expense. Depreciation expense totaled $396.5, $365.5 and $346.6 for Fiscal 2018, Fiscal 2017 and Fiscal 2016, respectively.
For property subject to cost of service rate regulation including substantially all of UGI Utilities depreciable utility plant and equipment, upon retirement 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 on the Consolidated Statements of Income.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Goodwill and Intangible Assets
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.
In April 2018, the Partnership’s senior management approved a plan to discontinue the use of certain tradenames and trademarks, primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane, over a period of approximately three years. As a result, during the third quarter of Fiscal 2018, the Partnership determined that these tradenames and trademarks no longer had indefinite lives and adjusted the carrying amounts of these tradenames and trademarks to their estimated fair values. During the third quarter of Fiscal 2018, the Partnership recorded a non-cash, pre-tax impairment charge of $75.0 which amount is reflected in “Impairment of Partnership tradenames and trademarks” on the Consolidated Statements of Income, and is amortizing the remaining fair value of these tradenames and trademarks of $7.9 over their estimated period of benefit of three years. For further information on these tradenames and trademarks, see Notes 11 and 16.
Goodwill. 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.
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 goodwill impairment losses at September 30, 2018 and 2017, and no provisions for goodwill impairments were recorded during Fiscal 2018, Fiscal 2017 or Fiscal 2016. For further information on our goodwill and intangible assets, see Note 11.
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 2018, Fiscal 2017 or Fiscal 2016.
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 2018 or Fiscal 2016.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 revolving credit facilities are classified as “Other assets” on our Consolidated Balance Sheets. Amortization of debt 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 UGI France of $272.0 and $279.9 at September 30, 2018 and 2017, 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. Under GAAP, if the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, such liabilities are discounted to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Utilities receives 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. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
return are recorded on the Consolidated Statements of Income. We account for forfeitures of share-based payments when they occur.
Effective October 1, 2016, we adopted Accounting Standards Update (“ASU”) No. 2016-09, “Improvements to Employee Share-Based Payments Accounting” (“ASU 2016-09”) which simplifies 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. As a result of the adoption of ASU 2016-09, beginning in Fiscal 2017 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 in the reporting period in which they occur, and 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 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. 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.
Note 3 - Accounting Changes
New Accounting Standards Adopted Effective October 1, 2018
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). The guidance provided under this ASU, 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. In addition, the new guidance requires enhanced disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers and requires, among other things, the disaggregation of revenues into categories that show how economic factors affect the nature, timing and uncertainty of revenues and cash flows. We adopted this ASU effective October 1, 2018, using the modified retrospective transition method.
The Company has completed 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. Although the impact of the adoption of the new revenue recognition guidance will not have a material impact on our financial statements, certain performance obligations associated the release of capacity contracts at UGI Utilities will be reflected on a gross, rather than net, basis beginning October 1, 2018 and revenues from certain other negotiated rate contracts will be reflected on a straight-line basis.
Cloud Computing Implementation Costs. In August 2018, the FASB issued ASU No. 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.” The new guidance requires a customer in a cloud computing arrangement that is a service contract to capitalize certain implementation costs as if the arrangement was an internal-use software project. These deferred implementation costs are expensed over the fixed, noncancelable term of the service arrangement plus any reasonably certain renewal periods. The new guidance also requires the entity to present the expense related to the capitalized implementation costs in the same income statement line as the hosting service fees; to classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments for hosting service fees; and to present the capitalized implementation costs in the balance sheet in the same line item in which prepaid hosting service fees are presented. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We adopted this ASU effective October 1, 2018, and applied the guidance prospectively to all implementation costs associated with cloud computing arrangements that are service contracts incurred after October 1, 2018.
Stranded Tax Effects in Accumulated Other Comprehensive Income. In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded tax effects in AOCI resulting from the remeasurement of deferred income taxes associated with items included in AOCI due to the enactment of the TCJA may be reclassified to retained earnings, at the election of the entity, in the period the ASU is adopted.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
We adopted this ASU effective October 1, 2018. The amount of stranded tax benefits reclassified from AOCI to retained earnings as of October 1, 2018 was not material.
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 income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization, when applicable. For entities subject to rate regulation, including UGI Utilities, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability. Upon adoption, UGI Utilities will capitalize the non-service cost components of postretirement benefit costs as a regulatory asset. The new guidance became effective for us on October 1, 2018 with a retrospective adoption for income statement presentation and a prospective adoption for capitalization. Other than the presentation of the non-service cost components on the statement of income, the adoption of this new guidance will not have a material impact on our consolidated financial statements.
Statement of Cash flows - Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” The guidance in this ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, as well as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. The amendments in the ASU are required to be adopted on a retrospective basis. We adopted this ASU effective October 1, 2018. Adoption of this new guidance will result in a change in presentation of restricted cash on the Consolidated Statement of Cash Flows; otherwise this guidance will not have a significant impact on our Consolidated Statement of Cash Flows and disclosures.
Other Accounting Principles Not Yet Adopted
Pension and Other Postretirement Benefit Costs Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. The amendments in this ASU are effective for interim and annual periods ending after December 15, 2020 (Fiscal 2021). The guidance shall be adopted retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted.
Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. The amendments in this ASU are effective for annual periods beginning after December 15, 2019 (Fiscal 2021). The guidance regarding removed and modified disclosures will be adopted on a retrospective basis and the guidance regarding new disclosures will be adopted on a prospective basis. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be 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 the Company for interim and annual periods beginning October 1, 2019 (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.
Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, 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 the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption. We will adopt ASU No. 2016-02, as updated, effective October 1, 2019 and expect to elect the proposed transition option which would allow the Company to maintain historical presentation for periods before October 1, 2019. The Company has completed a preliminary assessment for evaluating the impact of the guidance and anticipates that its adoption will result in a significant amount of right-of-use assets and lease liabilities for leases in effect at the adoption date. The Company has begun implementation activities including accumulating contracts and lease data in formats compatible with a new lease management system that will assist with the initial adoption of the standard.
Note 4 - Acquisitions of Businesses and Assets
Acquisitions of Businesses
During Fiscal 2018, UGI International acquired UniverGas, an LPG distribution business with operations in northern and central regions of Italy, and AmeriGas Propane acquired two retail propane distribution businesses. During Fiscal 2017, UGI International acquired DVEP, 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. The operating results of these businesses have been included in our operating results from their respective dates of acquisition.
Total cash paid and liabilities incurred in connection with these acquisitions were as follows:
(a)
UGI International Fiscal 2017 amount includes note payable to seller. AmeriGas Propane amounts principally comprise amounts payable under noncompete agreements.
Acquisitions of Assets
During Fiscal 2018, Midstream & Marketing acquired for cash 60 miles of natural gas gathering lines and related dehydration and compression equipment, and a smaller natural gas gathering system, both located in northern Pennsylvania. In addition, during Fiscal 2018, Midstream & Marketing acquired for cash a 44 megawatt natural gas-fired peaking turbine located on its Hunlock Station site in northeast Pennsylvania. Total cash consideration for these asset acquisitions totaled $70.3.
Note 5 - Debt
Significant Financing Activities
AmeriGas Propane. In December 2017, AmeriGas Partners entered into the Second Amended and Restated Credit Agreement (“AmeriGas OLP Credit Agreement”) with a group of banks. The AmeriGas OLP Credit Agreement amends and restates a previous credit agreement. The AmeriGas OLP Credit Agreement provides for borrowings up to $600 (including a $150 sublimit for letters of credit) and expires in December 2022. The AmeriGas OLP Credit Agreement permits AmeriGas to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas OLP Credit Agreement, plus a margin. The applicable margin on base rate borrowings ranges from 0.50% to 1.75%, and the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.75%. The aforementioned margins on borrowings are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (each as defined in the AmeriGas OLP Credit Agreement).
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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.
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:
UGI International. In December 2017, UGI International, LLC, a wholly owned subsidiary of UGI, entered into a secured multicurrency revolving facility agreement (the "2017 UGI International Credit Agreement") due April 2020 with a group of banks providing for borrowings up to €300. Upon entering into the 2018 UGI International Credit Facilities Agreement on October 25, 2018 (see “Subsequent Event - UGI International Refinancing” below), the 2017 UGI International Credit Agreement was terminated. Under the 2017 UGI International Credit Agreement, UGI International, LLC could borrow in euros or U.S. dollars. Loans made in euros bore interest at the associated euribor rate plus a margin ranging from 1.45% to 2.35%. Loans made in U.S. dollars bore interest at LIBOR plus a margin ranging from 1.70% to 2.60%. The aforementioned margins are dependent upon certain indebtedness at UGI International, LLC. There were no borrowings made under the 2017 UGI International Credit Agreement.
Also, in December 2017, Flaga repaid $9.2 of the outstanding principal amount of its then-existing $59.1 U.S. dollar denominated variable-rate term loan due September 2018. Concurrently, Flaga entered into an amendment to the aforementioned term loan, which amended the previous agreement to extend the maturity of the term loan to April 2020 (“Flaga U.S. Dollar Term Loan”). Prior to its repayment in October 2018 (see “Subsequent Event - UGI International Refinancing” below), borrowings under the Flaga U.S. Dollar Term Loan bore interest at the one-month LIBOR rate plus a margin of 1.125%. Flaga effectively fixed the LIBOR component of the interest rate, and effectively fixed the U.S. dollar value of the interest and principal payments payable under the Flaga U.S. Dollar Term Loan, by entering into a cross-currency swap arrangement with a bank.
UGI Utilities. In September 2018, UGI Utilities entered into an Increasing Lender Commitment and Acceptance (the “Commitment and Acceptance”) under its existing unsecured, revolving credit agreement. The Commitment and Acceptance increases the amount of loan commitments under UGI Utilities’ existing unsecured, revolving credit agreement to $450 from $300. All other terms of UGI Utilities’ existing unsecured, revolving credit agreement remain unchanged.
In October 2017, UGI Utilities entered into a $125 unsecured variable-rate term loan agreement (the “Utilities Term Loan”) with a group of banks. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement borrowings and for general corporate purposes. The Utilities Term Loan is payable in equal quarterly installments of $1.6, commencing in March 2018, with the balance of the principal being due and payable in full on October 30, 2022. 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 that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. In July 2018, UGI Utilities entered into a forward-starting pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on Utilities Term Loan borrowings at approximately 3.00% through July 2022. This forward-
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
starting interest rate swap commences September 30, 2019. We have designated this forward-starting interest rate swap as a cash flow hedge.
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. These senior notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt.
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:
(a)
At September 30, 2018 and 2017, 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 UGI France’s consolidated total net debt to EBITDA, each as defined. At September 30, 2018 and 2017, such margin was 1.75% and 1.90%, respectively. UGI France 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 September 30, 2018 and 2017, the effective interest rate on the term loan was approximately 1.93% and 2.08%, respectively. Principal
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
amounts outstanding under the term loan are due as follows: €60 due April 2019 and €480 due April 2020. This term loan was repaid on October 25, 2018, in conjunction with the UGI International refinancing transaction (see “Subsequent Event - UGI International Refinancing” below).
(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, 2018 and 2017, was 1.93% and 1.80%, respectively. This term loan was repaid on October 25, 2018, in conjunction with the UGI International refinancing transaction (see “Subsequent Event - UGI International Refinancing” below).
(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, 2018 and 2017, the effective interest rate on this term loan was 0.55% and 0.87%, respectively. This term loan was repaid on October 25, 2018, in conjunction with the UGI International refinancing transaction (see “Subsequent Event - UGI International Refinancing” below).
(e)
Borrowings bear interest at prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. UGI Utilities has entered into a forward-starting, pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on Utilities Term Loan borrowings at approximately 3.00% through July 2022, commencing September 30, 2019. The effective interest rate on this term loan at September 30, 2018, was 2.76%.
Scheduled principal repayments of long-term debt for each of the next five fiscal years ending September 30 are as follows:
(a)
Includes scheduled repayments as of September 30, 2018, relating to the UGI France Senior Facilities term loan; the Flaga variable-rate term loan; and the Flaga U.S. dollar variable-rate term loan. These term loans were repaid on October 25, 2018 with net proceeds from the issuance of the UGI International 3.25% Senior Notes due November 2025 and the term loan borrowings under the 2018 UGI International Credit Facilities Agreement due October 2023 and cash on hand (see “Subsequent Event - UGI International Refinancing” below).
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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, 2018 and 2017, is presented in the following table. Borrowings outstanding under these agreements are classified as “Short-term borrowings” on the Consolidated Balance Sheets.
N.A. - Not applicable.
(a)
The AmeriGas OLP Credit Agreement includes a $150 sublimit for letters of credit ($125 prior to its amendment in December 2017) 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 1.75%; the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.75%; and the facility fee ranges from 0.30% to 0.50%. The aforementioned margins and facility fees are dependent upon AmeriGas Partners’ ratio of debt to EBITDA, as defined.
(b)
The UGI International Credit Agreement permits UGI International, LLC to borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus a margin ranging from 1.45% to 2.35%. Loans made in U.S. dollars will bear interest at LIBOR plus a margin ranging from 1.70% to 2.60%. The aforementioned margins are dependent upon certain indebtedness at UGI International, LLC. This facility was terminated concurrent with entering into the 2018 UGI International Credit Facilities Agreement on October 25, 2018 (see “Subsequent Event - UGI International Refinancing” below.)
(c)
Borrowings under UGI France’s 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 UGI France’s ratio of consolidated total net debt to EBITDA, as defined. This facility was terminated concurrent with entering into the 2018 UGI International Credit Facilities Agreement on October 25, 2018 (see “Subsequent Event - UGI International Refinancing” below.)
(d)
Flaga’s 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. This facility was terminated concurrent with entering into the 2018 UGI International Credit Facilities Agreement on October 25, 2018 (see “Subsequent Event - UGI International Refinancing” below.)
(e)
Energy Services’ credit agreement includes a $50 sublimit for letters of credit and can be used for general corporate purposes of Energy Services and its subsidiaries. Energy Services may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined, does not exceed 3.00 to 1.00. Borrowings
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 ranges from 0.75% to 2.25%. The Energy Services credit agreement is guaranteed by certain subsidiaries of Energy Services.
(f)
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. On September 21, 2018, UGI Utilities entered into the Commitment and Acceptance which increased the total capacity under this facility to $450.
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 2019. The Receivables Facility, as amended, provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November to April, and up to $75 of eligible receivables during the period May to October. Energy Services, 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 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 2018, Fiscal 2017 and Fiscal 2016, 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 2018, Fiscal 2017 and Fiscal 2016, as well as the balance of ESFC trade receivables at September 30, 2018, 2017 and 2016 follows:
(a)
At September 30, 2018 and 2017, the amounts of ESFC trade receivables sold to the bank were $2.0 and $39.0, 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 OLP Credit Agreement requires that AmeriGas OLP and AmeriGas Partners maintain ratios of total indebtedness to EBITDA, as defined, below certain thresholds. In addition, the Partnership must maintain a minimum ratio of EBITDA to interest expense, as defined and as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result therefrom, AmeriGas OLP is permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter.
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, 2018, 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”).
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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).
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.
Energy Services’ credit agreement requires that Energy Services 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, 2018, 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.
Subsequent Event - UGI International Refinancing
On October 18, 2018, UGI International, LLC, a wholly owned second-tier subsidiary of UGI, entered into a five-year unsecured Senior Facilities Agreement with a consortium of banks consisting of (1) a €300 variable-rate term loan which was drawn on October 25, 2018, and (2) a €300 senior unsecured multicurrency revolving facility agreement (together, the “2018 UGI International Credit Facilities Agreement”). The 2018 UGI International Credit Facilities Agreement matures on October 18, 2023. Term loan 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 zero. The margin on term loan borrowings, which ranges from 1.55% to 3.20%, is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. The initial margin on term loan borrowings is 1.70%. UGI International, LLC has entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on term loan borrowings at 0.34%. Under the multicurrency revolving credit facility agreement, UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus a margin ranging from 1.20% to 2.85%. Loans made in U.S. dollars will bear interest at the associated LIBOR rate plus a margin ranging from 1.45% to 3.10%. The margin on revolving facility borrowings is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined.
Restrictive covenants under the 2018 UGI International Credit Facilities Agreement include 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. In addition, The 2018 UGI International Credit Facilities Agreement requires a ratio of consolidated total net indebtedness to consolidated EBITDA, as defined, not to exceed 3.85 to 1.00.
On October 25, 2018, UGI International, LLC issued in an underwritten private placement €350 principal amount of 3.25% senior unsecured notes due November 1, 2025 (the “UGI International 3.25% Senior Notes”). The UGI International 3.25% Senior Notes rank equal in right of payment with indebtedness issued under the 2018 UGI International Credit Facilities Agreement.
The net proceeds from the UGI International 3.25% Senior Notes and the 2018 UGI International Credit Facilities Agreement variable-rate term loan plus cash on hand were used on October 25, 2018 (1) to repay €540 outstanding principal of UGI France’s variable-rate term loan under its 2015 Senior Facilities Agreement; €45.8 outstanding principal of Flaga’s variable-rate term loan; and $49.9 outstanding principal of Flaga’s U.S. dollar variable-rate term loan, plus accrued and unpaid interest, and (2) for general corporate purposes. Because these outstanding term loans were refinanced on a long-term basis in October 2018, we have classified €60 of such debt due in April 2019 as long-term debt on the September 30, 2018 Consolidated Balance Sheet. Upon entering into the 2018 UGI International Credit Facilities Agreement, we also terminated (1) the 2017 UGI International Credit Agreement, (2) UGI France SAS’s revolving credit facility under the 2015 Senior Facilities Agreement and (3) Flaga’s credit facility agreement. We have designated term loan borrowings under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes as net investment hedges.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 6 - Income Taxes
Income before income taxes comprises the following:
The provisions for income taxes consist of the following:
Federal income taxes for Fiscal 2018, Fiscal 2017 and Fiscal 2016 are net of foreign tax credits of $13.0, $40.9 and $25.6, respectively.
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:
On December 22, 2017, the TCJA was enacted into law. Among the significant changes resulting from the law, the TCJA reduced the U.S. federal income tax rate from 35% to 21%, effective January 1, 2018, created a territorial tax system with a one-time mandatory “toll tax” on previously un-repatriated foreign earnings, and allowed for immediate capital expensing of certain qualified property. It also applied restrictions on the deductibility of interest expense, eliminated bonus depreciation for regulated utilities and certain FERC-regulated property beginning in Fiscal 2019 and applied a broader application of compensation limitations.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
As a result of the TCJA, we reduced our net deferred income tax liabilities by $384.4 due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of the enactment of the TCJA on December 22, 2017. Because most of the reduction to UGI Utilities’ net deferred income taxes relates to regulated utility plant assets, most of UGI Utilities’ reduction in deferred income taxes is not being recognized immediately in income tax expense.
At September 30, 2018, the accounting for certain income tax effects of the TCJA with respect to existing deferred tax balances and the one-time transition tax reflect provisional amounts. We have made a reasonable estimate of the effects in accordance with U.S. Securities and Exchange Commission Staff Accounting Bulletin No. 118 and are still analyzing certain aspects of the TCJA and refining our calculations, which could potentially result in changes to our current estimates. Revisions to our estimates, if any, will be made by the first quarter of the fiscal year ending September 30, 2019.
In Fiscal 2018 we were subject to a blended federal tax rate of 24.5% because our fiscal year contains the effective date of the rate change from 35% to 21%. The effects of the tax law changes on current period results (excluding the remeasurement impact described above) decreased income tax by $52.1.
In order for UGI Utilities’ regulated utility plant assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred federal income taxes resulting from the remeasurement of deferred taxes on regulated utility plant be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. As a result of the TCJA, for Fiscal 2018, UGI Utilities initially recorded a net regulatory liability of $205.6 associated with excess deferred federal income taxes related to its regulated utility plant assets. This regulatory liability was increased, and a federal deferred income tax asset was recorded, in the amount of $83.6 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. This regulatory liability is being amortized to income tax expense over the remaining lives of the assets that gave rise to the excess deferred income taxes. For further information on this regulatory liability, see Note 8.
As further described in Note 8, on May 17, 2018, the PAPUC issued a Temporary Rates Order for all PAPUC-regulated utilities with regard to federal tax reform. Among other things, the Temporary Rates Order requires Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period January 1, 2018 through June 30, 2018, resulting from the change in the federal income tax rate from 35% to 21%. In accordance with the Temporary Rates Order, during Fiscal 2018, UGI Utilities reduced its revenues by $24.1 and recorded a regulatory liability in an equal amount. The total reduction of $24.1 primarily reflects (1) $17.1 of tax benefits accrued during the period January 1, 2018 to June 30, 2018, (2) $7.0 to reflect tax benefits expected to be generated by the future amortization of the regulatory liability and accrued interest.
In Fiscal 2017 and Fiscal 2016, earnings of the Company’s foreign subsidiaries were generally subject to U.S. taxation upon repatriation to the U.S. and the Company’s tax provisions reflected the related incremental U.S. tax except for certain foreign subsidiaries whose unremitted earnings were considered to be indefinitely reinvested. No deferred tax liability had been recognized with regard to remittance of those earnings because of the availability of U.S. foreign tax credits made it likely that no U.S. tax would be due if such earnings were repatriated. Upon enactment of TCJA, substantially all prior unrepatriated earnings were subjected to U.S. tax under the transition tax rules. The transition tax was immaterial to the Company and we generally expect to have the ability to repatriate prior unrepatriated earnings without material U.S. federal tax cost.
Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2018, Fiscal 2017 and Fiscal 2016, the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $4.2, $2.5 and $1.3, respectively.
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:
In December 2017, the French Parliament approved the Finance Bill for 2018 and the second amended Finance Bill for 2017 (collectively, the “December 2017 French Finance Bills”). One impact of the December 2017 French Finance Bills was an increase in the Fiscal 2018 corporate income tax rate in France from 34.4% to 39.4%. The December 2017 French Finance Bills also include measures to reduce the corporate income tax rate to 25.8%, effective for fiscal years starting after January 1, 2022 (Fiscal 2023).
As a result of the December 2017 French Finance Bills, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $12.1 to reflect the estimated impact of the corporate income tax rate reductions that will be implemented through Fiscal 2023. The Company’s Fiscal 2018 effective income tax rate reflects the impact of the higher Fiscal 2018 income tax rate in France as a result of the December 2017 French Finance Bills, which increased income tax expense for the year by approximately $0.6.
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, at that time reduced the French corporate income tax rate from the then-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 liabilities and recognized a deferred tax benefit of $29.0.
At September 30, 2018, foreign net operating loss carryforwards principally relating to Flaga, UGI International Holdings BV and certain subsidiaries of France SAS totaled $14.0, $2.5 and $23.3, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $168.9 and expire through 2038. We also have federal operating loss carryforwards of $19.7 for certain operations of AmeriGas Propane that expire through 2036. At September 30, 2018, deferred tax assets relating to operating loss carryforwards include $2.9 for Flaga, $8.0 for certain subsidiaries of France SAS, $0.7 for UGI International Holdings BV, $4.0 for AmeriGas Propane and $10.6 for certain other subsidiaries.
The valuation allowance for all deferred tax assets increased by $9.7 in Fiscal 2018 due to an increase of $7.6 to re-establish a full valuation allowance associated with future utilization of foreign tax credits, primarily due to impacts of TCJA and an increase in foreign operating loss carryforwards of $2.1. A valuation allowance of $9.6 exists for deferred tax assets related to certain subsidiaries of France SAS, and certain subsidiaries of Flaga and UGI International Holdings BV.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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. We have foreign tax credit carryforwards of approximately $106.1 expiring through 2028 resulting from the actual and planned repatriation of France SAS’s accumulated earnings since acquisition. 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 would expire before utilization and therefore reversed $7.6 of the then existing valuation allowance against these credits. The amount of the deferred tax asset considered realizable could be adjusted if estimates of future utilization 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 2014 tax year, our French tax returns are settled through the 2014 tax year, our Austrian tax returns are settled through 2016 and our other European tax returns are effectively settled for various years from 2009 to 2016. 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.
UGI Corporation and subsidiaries’ 2016 consolidated U.S. federal tax return is currently under examination by the Internal Revenue Service. UGI France and subsidiaries’ 2015, 2016 and 2017 tax returns are currently under examination by the French Tax Authority.
As of September 30, 2018, we have unrecognized income tax benefits totaling $11.5 including related accrued interest of $1.0. If these unrecognized tax benefits were subsequently recognized, $11.5 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:
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 certain 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, 2018 and 2017. 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.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
In Fiscal 2019, we estimate that we will amortize approximately $7.5 of net actuarial losses, primarily associated with the U.S. Pension Plan, and $0.2 of net prior service benefits 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).
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The ABOs for the U.S. Pension Plan were $572.8 and $605.2 as of September 30, 2018 and 2017, respectively.
Net periodic pension expense and other postretirement benefit cost include the following components:
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. 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 2018, Fiscal 2017 and Fiscal 2016, we made cash contributions to the U.S. Pension Plan of $15.1, $11.4 and $9.9, respectively. The minimum required contributions in Fiscal 2019 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 2019 are not expected to be material.
Expected payments for pension and other postretirement welfare benefits are as follows:
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:
A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 2018 other postretirement benefit cost or September 30, 2018, other postretirement benefit ABO.
We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans (“Supplemental Defined Benefit Plans”). At September 30, 2018 and 2017, the PBOs of these plans, including obligations for amounts held in grantor trusts, were $48.3 and $50.7, respectively. We recorded pre-tax costs for these plans of $4.3 in Fiscal 2018 (which amount includes a $2.1 settlement charge), $3.1 in Fiscal 2017 and $2.6 in Fiscal 2016. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $4.3 and $11.3 at September 30, 2018 and 2017, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.5 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2019. During Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Company made payments with respect to the Supplemental Defined Benefit Plans totaling $0.1, $1.3 and $0.4, respectively. 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 $34.3 and $31.8 at September 30, 2018 and 2017, 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 index mutual funds 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.
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
VEBA
Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and mid- and small-cap index mutual funds. 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 8.5% and 7.7% of U.S. Pension Plan assets at September 30, 2018 and 2017, respectively.
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, 2018 and 2017 are as follows:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
(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 $17.1 in Fiscal 2018, $15.1 in Fiscal 2017 and $14.3 in Fiscal 2016. 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 2018, Fiscal 2017 and Fiscal 2016 were not material. At September 30, 2018 and 2017, the total fair values of these grantor trust investment assets, which amounts are included in “Other assets” on the Consolidated Balance Sheets, were $6.5 and $3.6, respectively.
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:
(a)
Regulatory liabilities are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance Sheets.
(b)
Balance at September 30, 2018, comprises tax savings for the period January 1, 2018 to June 30, 2018, plus interest, resulting from the enactment of the TCJA (see “PAPUC Temporary Rates Order” below and Note 6).
(c)
Balance at September 30, 2018, comprises excess federal deferred income taxes resulting from the enactment of the TCJA (see “Excess federal deferred income taxes” below and Note 6).
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 Gas Utility expects to incur, primarily at manufactured gas plant (“MGP”) sites in Pennsylvania, in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (“PADEP”). Pursuant to base rate orders, Gas Utility receives ratemaking recognition of its 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, 2018, the
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
period over which Gas Utility expects 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 PAPUC ratemaking, removal costs include actual costs incurred associated with asset retirement obligations. Consistent with prior ratemaking treatment, Gas Utility expects to recover these costs over five years.
Postretirement benefit overcollections. This regulatory liability represents the difference between amounts recovered through rates by Gas Utility and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With respect to Gas Utility, 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 overcollections will be refunded to ratepayers over a 20-year period effective October 27, 2018.
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, 2018 and 2017 were $2.9 and $0.1, respectively.
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.
PAPUC Temporary Rates Order. By Secretarial Letter dated January 12, 2018, the PAPUC initiated a review into whether public utility rates should be adjusted to reflect the tax savings from the change in the federal income tax rate from 35% to 21% for the period beginning January 1, 2018. Thereafter, on March 15, 2018, the PAPUC entered a Temporary Rates Order that converted commission-approved rates of most large Pennsylvania public utilities, including Gas Utility, into “temporary rates” for a period of no more than 12 months while the PAPUC reviewed the data and comments in response to the Secretarial Letter.
On May 17, 2018, the PAPUC ordered each regulated utility currently not in a general base rate case proceeding, including UGI Gas, PNG and CPG, to reduce their rates through the establishment of a negative surcharge applied to bills rendered on or after July 1, 2018. The temporary negative surcharge will be reconciled at the end of each fiscal year to actual tax savings realized. The negative surcharge will remain in place until the effective date of new rates established in the utility’s next general base rate proceeding. For the merged Gas Utility, such negative surcharge will reduce base rate revenues by 5.78%, 3.90% and 8.19%, respectively, for the UGI South, UGI North and UGI Central rate districts.
In its May 17, 2018 Order, the PAPUC also required Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period beginning January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate. Gas Utility reduced its combined utility revenues by $24.1 and recorded a regulatory liability in an equal amount. The total reduction in revenues reflects (1) $17.1 of tax benefits accrued during the previously mentioned six-month period plus (2) $7.0 to reflect tax benefits expected to be generated by the future amortization of the regulatory liability. The rate treatment of this regulatory liability, plus accrued interest, for each of UGI Gas, PNG and CPG will be addressed in a future proceeding and the Company cannot predict the ultimate treatment of this liability. Like other similarly situated utilities, if Gas Utility has not filed a general base rate proceeding within three years of the Temporary Rates Order, Gas Utility will be required to file a petition to propose how to distribute the balance of these regulatory liabilities.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
For Pennsylvania utilities that were in a general base rate proceeding, including Electric Utility, no negative surcharge will apply. The tax benefits that accrue during the period January 1, 2018 through October 26, 2018, the date before Electric Utility’s base rate case became effective (see below) will be refunded to Electric Utility ratepayers through a one-time bill credit.
Excess federal deferred income taxes. This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 6). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess federal deferred income taxes resulting from the remeasurement be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess federal deferred income taxes, ranging from 1 year to approximately 65 years. This regulatory liability has been increased to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes and is being amortized and credited to tax expense.
Other. Other regulatory assets and liabilities comprise a number of deferred items including, among others, over or under refunds of tax benefits related to TCJA for periods after June 30, 2018, certain information technology costs, energy efficiency conservation costs and rate case expenses.
Other Regulatory Matters
Utilities Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and MDPSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged into UGI Utilities effective October 1, 2018. Consistent with the MDPSC order issued July 25, 2018, and the PAPUC order issued September, 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type schedules for limited future ratemaking purposes.
Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution revenues by $9.2, which was later reduced by Electric Utility to $7.7 to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $3.2 annual base distribution rate increase for Electric Utility, effective October 27, 2018. As part of the final order, Electric Utility is required to provide customers with a one-time $0.2 billing credit associated with 2018 TCJA tax benefits.
On January 19, 2017, PNG (now the UGI North rate district of Gas Utility) filed a rate request with the PAPUC 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 PAPUC providing for an $11.3 PNG annual base distribution rate increase. On August 31, 2017, the PAPUC approved the Joint Petition and the increase became effective October 20, 2017.
On January 19, 2016, UGI Utilities (now the UGI South rate district of Gas Utility) filed a rate request with the PAPUC 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 PAPUC (“Joint Petition”). On October 14, 2016, the PAPUC 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. State legislation permits gas and electric utilities in Pennsylvania to recover a distribution system improvement charge (“DSIC”) on eligible capital investments as an alternative ratemaking mechanism providing for a more timely cost recovery of qualifying capital expenditures between base rate cases.
PNG and CPG received PAPUC 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 May 2017, the PAPUC 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. PNG’s DSIC has been
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
reset to zero as a result of its most recent base rate case. The DSIC rate for PNG will resume under the UGI North rate district upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its most recent base rate case.
In November 2016, UGI Gas received PAPUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas began recovering revenue under the mechanism effective July 1, 2018, as it exceeded, during the third quarter of Fiscal 2018, the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.
Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017, explosion in Manor Township, Lancaster County, PA, that resulted in the death of one UGI Utilities’ employee and injuries to two other UGI Utilities’ employees and one sewer authority employee, and destroyed two residences and damaged several other homes, the PAPUC Bureau of Investigation and Enforcement (“BIE”) filed a formal complaint at the PAPUC in which BIE alleges that UGI Utilities committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion, and requested that the PAPUC order UGI Utilities to pay approximately $2.1 in civil penalties, which is the maximum allowable fine. On November 16, 2018, UGI Utilities filed its formal written answer contesting the BIE complaint.
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:
At September 30, 2018, 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, 2018, 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, 2018 and 2017, comprising 2.3 billion cubic feet (“bcf”) and 2.3 bcf of natural gas, was $5.4 and $6.7, respectively.
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:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 11 - Goodwill and Intangible Assets
Changes in the carrying amount of goodwill by reportable segment are as follows:
Intangible assets comprise the following at September 30:
Amortization expense of intangible assets was $58.6, $50.8 and $54.3 for Fiscal 2018, Fiscal 2017 and Fiscal 2016, respectively. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2019 - $57.2; Fiscal 2020 - $55.8; Fiscal 2021 - $52.5; Fiscal 2022 - $49.5; Fiscal 2023 - $48.0.
In April 2018, a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with its January 2012 acquisition of Heritage Propane, was presented to the Partnership’s senior management. After considering the merits of the plan, the Partnership’s senior management approved a plan to discontinue the use of these tradenames and trademarks over a period of approximately three years. As a result, during the third quarter of Fiscal 2018, the Partnership determined that these tradenames and trademarks no longer had indefinite lives and adjusted the carrying amounts of these tradenames and trademarks to their estimated fair values of approximately $7.9. During the third quarter of Fiscal 2018, the Partnership recorded a non-cash, pre-tax impairment charge of $75.0 which amount is reflected in “Impairment of Partnership tradenames and trademarks” on the Consolidated Statements of Income, and is amortizing the remaining fair value of these tradenames and trademarks of $7.9 over their estimated period of benefit of three years. See Note 16 for further information on the determination of fair values for the affected tradenames and trademarks.
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. UGI had no shares of UGI Series Preferred Stock outstanding at September 30, 2018 or 2017.
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, 2018 and 2017, there were no shares of UGI Utilities Series Preferred Stock outstanding.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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. On January 25, 2018, UGI’s Board of Directors authorized an extension of the share repurchase program for up to 8,000,000 shares of UGI Corporation Common Stock for an additional four-year period. Pursuant to these authorizations, during Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Company purchased and placed in treasury stock 1,200,000, 900,000 and 1,250,000 shares at a total cost of $59.8, $43.3 and $47.6, respectively.
UGI Common Stock share activity for Fiscal 2016, Fiscal 2017 and Fiscal 2018 follows:
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 $22.5 ($15.7 after-tax), $19.3 ($11.8 after-tax) and $23.8 ($15.4 after-tax) in Fiscal 2018, Fiscal 2017 and Fiscal 2016, respectively.
UGI Equity-Based Compensation Plans and Awards. Under the UGI Corporation 2013 Omnibus Incentive Compensation Plan (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 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
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 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 2016, Fiscal 2017 and Fiscal 2018 follow:
Cash received from stock option exercises and associated tax benefits were $43.4 and $12.6, $17.7 and $9.6, and $27.3 and $14.9 in Fiscal 2018, Fiscal 2017 and Fiscal 2016, respectively. As of September 30, 2018, there was $7.9 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 2.1 years.
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2018:
UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $7.51 in Fiscal 2018, $7.62 in Fiscal 2017 and $4.87 in Fiscal 2016. These amounts were determined using a Black-
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 2018, Fiscal 2017 and Fiscal 2016 are as follows:
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”). 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%. 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 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:
The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $55.26 for Units granted in Fiscal 2018, $50.91 for Units granted in Fiscal 2017 and $32.64 for Units granted in Fiscal 2016.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The following table summarizes UGI Unit award activity for Fiscal 2018:
(a)
Total UGI Units includes UGI Stock Units issued to non-employee directors, which vest on the grant date, and UGI Performance Units and UGI Stock Units issued to retirement-eligible employees that vest on an accelerated basis. Total vested restricted units at September 30, 2018 and September 30, 2017 were 660,795 and 660,886, respectively.
(b)
Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2017 and Fiscal 2016 were 42,079 and 52,493, respectively.
During Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:
During Fiscal 2018, Fiscal 2017 and Fiscal 2016, we granted UGI Unit awards representing 196,114, 185,379 and 230,653 shares, respectively, having weighted-average grant date fair values per Unit of $53.36, $50.08 and $33.04, respectively.
As of September 30, 2018, there was a total of approximately $9.4 of unrecognized compensation cost associated with 959,718 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.8 years. The total fair values of UGI Units that vested during Fiscal 2018, Fiscal 2017 and Fiscal 2016 were $7.3, $7.1 and $9.7, respectively. As of September 30, 2018 and 2017, total liabilities of $18.8 and $13.1, respectively, associated with UGI Unit awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” on the Consolidated Balance Sheets.
At September 30, 2018, 9,043,267 shares of Common Stock were available for future grants under the 2013 OICP.
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Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 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 the other two members in the Propane MLP Group. Otherwise there would be no payout of such AmeriGas Performance Units. For those performance awards granted on or after January 1, 2015, that are subject to the MLP Modifier, if one of the other two members of the Propane MLP Group ceases to exist as a publicly traded company or declares bankruptcy (“MLP Event”) and depending upon the timing of such MLP Event, the ultimate amount of such AmeriGas Performance Unit awards to be issued, 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.
With respect to AmeriGas Performance Unit awards granted in January 2015 whose payout was based upon net customer gain and retention performance, grantees could 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 thereafter 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.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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:
The General Partner granted awards under the 2010 Propane Plan representing 84,811, 67,563 and 73,080 Common Units in Fiscal 2018, Fiscal 2017 and Fiscal 2016, respectively, having weighted-average grant date fair values per Common Unit subject to award of $50.05, $52.37 and $37.93, respectively. At September 30, 2018, 2,242,468 Common Units were available for future award grants under the 2010 Propane Plan.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2018:
(a)
Total units includes AmeriGas Stock Units issued to non-employee directors, which vest on the grant date, and AmeriGas Performance Units and AmeriGas Stock Units issued to retirement-eligible employees that vest on an accelerated basis. Total vested restricted units at September 30, 2018 and September 30, 2017 were 71,148 and 65,989, respectively.
During Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows:
As of September 30, 2018, there was a total of approximately $1.9 of unrecognized compensation cost associated with 236,762 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 2018, Fiscal 2017 and Fiscal 2016 were $2.2, $2.1 and $2.0, respectively. As of September 30, 2018 and 2017, total liabilities of $2.3 and $2.5 associated with Common Unit-based awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” on 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.
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 2018, Fiscal 2017 and Fiscal 2016, 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 2018, Fiscal 2017 and Fiscal 2016, the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $54.9, $52.7 and $47.4, respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2018, Fiscal 2017 and Fiscal 2016 of $45.3, $43.5 and $38.2, 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 $106.2 in Fiscal 2018, $99.5 in Fiscal 2017 and $102.0 in Fiscal 2016.
Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows:
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. There have been no capital contributions made to the Partnership under the Commitment Agreement.
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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
common units (“Common Units”) prior to the date of the Partnership’s related 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.
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. Beginning in 2006 and 2008, UGI Utilities also owned and operated two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. CPG and PNG were merged into UGI Utilities effective October 1, 2018 (“Utilities Merger”).
Prior to the Utilities Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, were subject to a consent order and agreement (“COA”) with the PADEP to address the remediation of specified former MGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the merger, UGI Utilities, as the successor to CPG and PNG, is 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 and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap. The cost cap of the three COAs, in the aggregate, is $5.4. The three COAs are currently scheduled to terminate at the end of 2031, 2020 and 2020. At September 30, 2018 and 2017, our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $51.0 and $54.3, respectively. UGI Utilities has 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 receives 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, 2018 and 2017, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material.
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. In 2008, the New York State Department of Environmental Conservation (“NYDEC”) notified AmeriGas OLP that the NYDEC 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 NYDEC disclosed contamination related to a former MGP. AmeriGas OLP responded to the NYDEC in 2009 to dispute the 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. In 2017, the NYDEC communicated to AmeriGas OLP that the NYDEC had previously issued three Records of Decision (“RODs”) related to remediation of the site totaling approximately $27.7 and requested additional information regarding AmeriGas OLP’s purported ownership. AmeriGas renewed its challenge to designation as a PRP and identified potential defenses. The NYDEC subsequently identified a third party PRP with respect to the site.
The NYDEC commenced implementation of the remediation plan in the spring of 2018. Based on our evaluation of the available information, the Partnership accrued an undiscounted environmental remediation liability of $7.5 related to the site during the third quarter of Fiscal 2017, 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, 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”). As of June 2018, as the result of rulings on a series of procedural filings, including petitions filed with the Eighth Circuit and the U.S. Supreme Court, both the federal and state law claims of the direct customer plaintiffs and the state law claims of the indirect customer plaintiffs have been remanded to the District Court. The decision of the District Court to dismiss the federal antitrust claims of the indirect customer plaintiffs was upheld by the Eighth Circuit. Motions are pending before the District Court regarding the indirect purchasers’ state law claims.
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.
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, 2018 and 2017:
(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. 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.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Nonrecurring Fair Value Measurements
As discussed in Note 11, in April 2018, the Partnership’s senior management approved a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane, over a period of approximately three years. This action required the Partnership to remeasure the fair values of these tradenames and trademarks based upon their remaining period of benefit. The Partnership used the relief from royalty method to estimate the fair values of the tradenames and trademarks, which method estimates our theoretical royalty savings from ownership of the tradenames and trademarks. Key assumptions used in this method include discount rates, royalty rates, growth rates and sales projections. These assumptions reflect current economic conditions, management expectations and projected future cash flows expected to be generated from these tradenames and trademarks. The Partnership has determined that the lowest level of the input that is significant to the fair value measurement are unobservable inputs that fall within Level 3 of the fair value hierarchy. As of the April 2018 measurement date, these tradenames and trademarks had an estimated fair value of $7.9.
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, 2018 and 2017 were as follows:
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 purchased gas costs. As permitted and agreed to by the PAPUC 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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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, 2018 and 2017, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.
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, AmeriGas Partners, certain other domestic businesses and our UGI International operations also use over-the-counter price swap 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 agreements to reduce the effects of short-term commodity price volatility. Also, Midstream & Marketing, from time to time, 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
The UGI Utilities Term Loan has an interest rate that is indexed to short-term market interest rates. UGI Utilities has entered into a forward starting, amortizing, pay-fixed, receive-variable interest rate swap agreement commencing September 30, 2019, that generally fixes the underlying variable interest rate on borrowings at 3.00% through July 2022. We have designated this interest rate swap as a cash flow hedge.
Prior to their repayment on October 25, 2018 (see Note 5), UGI France SAS’s and Flaga’s long-term debt agreements had interest rates that were generally indexed to short-term market interest rates. UGI France and Flaga entered into pay-fixed, receive variable interest rate swap agreements to hedge the underlying euribor rates and LIBOR rates of interest on this variable rate debt. These interest rate swaps were settled concurrent with the repayment of the UGI France and Flaga long-term debt. In November 2018, UGI International, LLC entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on 2018 UGI International Credit Facilities Agreement term loan borrowings at 0.34%.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The remainder of 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.
At September 30, 2018 and 2017, we had no unsettled IRPAs. At September 30, 2018, 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, 2018, the amount of net gains associated with these contracts expected to be reclassified into earnings during the next twelve months based upon current fair values is $1.1.
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 to 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 “Gain (loss) 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, 2018 and 2017, there were no unsettled net investment hedges outstanding. In October 2018, in connection with entering into the 2018 UGI International Credit Facilities Agreement and the UGI International Senior Notes, we designated the borrowings under these agreements as net investment hedges (see Note 5).
Cross-currency Swaps
Prior to its repayment on October 25, 2018 (see Note 5), Flaga entered 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 its U.S. dollar denominated variable-rate term loan. These cross-currency hedges included 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 included interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designated these cross-currency swaps as cash flow hedges.
At September 30, 2018, the amount of net gains associated with such cross-currency swaps expected to be reclassified into earnings during the next twelve months is not material.
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, 2018 and 2017 and the final settlement date of the Company's open derivative transactions as of September 30, 2018, excluding those derivatives that qualified for the NPNS exception:
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, 2018 and 2017, restricted cash in brokerage accounts totaled $9.6 and $10.3, 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, 2018. 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, 2018, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
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.
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, 2018 and 2017:
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 for Fiscal 2018, Fiscal 2017 and Fiscal 2016:
For Fiscal 2018 and Fiscal 2017, 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 UGI France SAS prior to their amendments in March 2016.
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 because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
Note 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.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Changes in AOCI during Fiscal 2018, Fiscal 2017 and Fiscal 2016 are as follows:
For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 17.
Note 19 - Other Operating Income, Net
Other operating income, net, comprises the following:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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).
(a)
The quarters ended December 31, 2017, March 31, 2018, June 30, 2018 and September 30, 2018, include the impact of adjustments to remeasure net deferred income tax liabilities associated with (1) the TCJA, including adjustments to provisional amounts, which increased (decreased) net income by $166.0, $5.3, $0.8 and $(5.8), respectively, and (2) the 2017 French Finance Bills which increased (decreased) net income by $17.3, $(3.7), $(0.1) and $(1.4), respectively (see Note 6).
(b)
The quarters ended December 31, 2016 and September 30, 2017, include the beneficial impact of adjustments to net deferred income tax liabilities associated with a change in the French income tax rate of $27.4 and $1.6, respectively (see Note 6).
(c)
Includes the impact of the impairment of Partnership tradenames and trademarks which decreased net income attributable to UGI by $14.5 (see Notes 11 and 16).
(d)
The quarters ended December 31, 2016, March 31, 2017 and June 30, 2017 include loss on extinguishments of debt at AmeriGas Partners which reduced net income attributable to UGI by $5.3, $3.6 and $0.7, respectively (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.
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 derives revenue from natural gas marketing businesses in France, Belgium and the United Kingdom and a natural gas and electricity marketing business 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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
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 Chief Operating Decision Maker (“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. The amounts of revenues and long-lived assets associated with our operations in France represent approximately 20% and 15% of the respective consolidated amounts.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
(a)
The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes:
(i)
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(b)
Includes net pre-tax gains on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $132.8, $82.0 and $91.6 in Fiscal 2018, Fiscal 2017 and Fiscal 2016, 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 impairment charge of $75.0 as a result of a plan to discontinue the use of certain Partnership tradenames and trademarks (see Note 11).
(f)
Fiscal 2018 results include impacts from the TCJA in the U.S. See Notes 6 and 8 for additional information.
UGI CORPORATION
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
BALANCE SHEETS
(Millions of dollars)
Note 1 - Commitments and Contingencies:
At September 30, 2018, UGI Corporation had agreed to indemnify the issuers of $70.3 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 $448.5 of such obligations were outstanding as of September 30, 2018.
S-1
UGI CORPORATION
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
(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.
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UGI CORPORATION
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(Millions of dollars)
(a)
Includes dividends received from unconsolidated subsidiaries of $190.5, $241.9 and $193.1 for the years ended September 30, 2018, 2017 and 2016, respectively.
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UGI CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)
(1)
Uncollectible accounts written off, net of recoveries.
(2)
Foreign tax credit valuation allowance adjustment.
(3)
Decrease in unusable foreign operating loss carryforwards.
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