ITEM 1A. RISK FACTORS
There are many factors that may affect our business and results of operations. Additional discussion regarding factors that may affect our business and operating results is included elsewhere in this Report.
Decreases in the demand for our energy products and services because of warmer-than-normal heating season weather may adversely affect our results of operations.
Because many of our customers rely on our energy products and services to heat their homes and businesses, our results of operations are adversely affected by warmer-than-normal heating season weather. Weather conditions have a significant impact on the demand for our energy products and services for both heating and agricultural purposes. Accordingly, the volume of our energy products sold is at its highest during the peak heating season of October through March and is directly affected by the severity of the winter weather. For example, historically, approximately 60% to 70% of AmeriGas Partners’ annual retail propane volume and Antargaz’ annual retail LPG volume, and 60% to 65% of Gas Utility’s natural gas throughput (the total volume of gas sold to or transported for customers within our distribution system) has been sold during these months. There can be no assurance that normal winter weather in our market areas will occur in the future.
Our holding company structure could limit our ability to pay dividends or debt service.
We are a holding company whose material assets are the stock of our subsidiaries. Our ability to pay dividends on our common stock and to pay principal and accrued interest on our debt, if any, depends on the payment of dividends to us by our principal subsidiaries, AmeriGas, Inc., UGI Utilities, Inc. and UGI Enterprises, Inc. (including Antargaz). Payments to us by those subsidiaries, in turn, depend upon their consolidated results of operations and cash flows. The operations of our subsidiaries are affected by conditions beyond our control, including weather, competition in national and international markets we serve, the costs and availability of propane, butane, natural gas, electricity, and other energy sources and capital market conditions. The ability of our subsidiaries to make payments to us is also affected by the level of indebtedness of our subsidiaries, which is substantial, and the restrictions on payments to us imposed under the terms of such indebtedness.
Our profitability is subject to LPG pricing and inventory risk.
The retail LPG business is a “margin-based” business in which gross profits are dependent upon the excess of the sales price over the LPG supply costs. LPG is a commodity, and, as such, its unit price is subject to volatile fluctuations in response to changes in supply or other market conditions. We have no control over these market conditions. Consequently, the unit price of the LPG that our subsidiaries and other marketers purchase can change rapidly over a short period of time. Most of our domestic LPG product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major U.S. storage points such as Mont Belvieu, Texas or Conway, Kansas. Most of our international LPG supply contracts are based on internationally quoted market prices. Because our subsidiaries’ profitability is sensitive to changes in wholesale propane supply costs, it will be adversely affected if we cannot pass on increases in the cost of propane to our customers. Due to competitive pricing in the industry, our subsidiaries may not be able to pass on product cost increases to our customers when product costs rise rapidly, or when our competitors do not raise their product prices. Finally, market volatility may cause our subsidiaries to sell LPG at less than the price at which they purchased it, which would adversely affect our operating results.
Energy efficiency and technology advances, as well as price induced customer conservation, may result in reduced demand for our energy products and services.
The trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, may reduce the demand for energy products. Prices for LPG and natural gas are subject to volatile fluctuations in response to changes in supply and other market conditions. During periods of high energy commodity costs, our prices generally increase, which may lead to customer conservation and attrition. A reduction in demand could lower our revenues and, therefore, lower our net income and adversely affect our cash flows. State and/or federal regulation may require mandatory conservation measures, which would reduce the demand for our energy products. We cannot predict the materiality of the effect of future conservation measures or the effect that any technological advances in heating, conservation, energy generation or other devices might have on our operations.
Volatility in credit and capital markets may restrict our ability to grow, increase the likelihood of defaults by our customers and counterparties and adversely affect our operating results.
The volatility in credit and capital markets may create additional risks to our businesses in the future. We are exposed to financial market risk (including refinancing risk) resulting from, among other things, changes in interest rates and conditions in the credit and capital markets. Developments in the credit markets during the past few years increase our possible exposure to the liquidity, default and credit risks of our suppliers, counterparties associated with derivative financial instruments and our customers. Although we believe that current financial market conditions, if they were to continue for the foreseeable future, will not have a significant impact on our ability to fund our existing operations, such market conditions could restrict our ability to grow through acquisitions, could limit the scope of major capital projects if access to credit and capital markets is limited, or adversely affect our operating results.
Economic recession, volatility in the stock market and the low interest rate environment may negatively impact our pension liability.
Economic recession, volatility in the stock market and the low interest rate environment have had a significant impact on our pension liability and funded status. Declines in the stock or bond market and valuation of stocks or bonds, combined with continued low interest rates, could further impact our pension liability and funded status and increase the amount of required contributions to our pension plans.
The adoption of financial reform legislation by the United States Congress and related regulations may have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.
Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act in 2010, which contains comprehensive financial reform legislation. That act imposes regulation on the over-the-counter derivatives market and entities that participate in that market. The act requires the Commodities Futures Trading Commission (“CFTC”), the U.S. Securities and Exchange Commission (“SEC”) and other regulators to implement the act’s provisions. Some rules and regulations under the act have been finalized but additional rules and regulations have yet to be adopted. While the effect on the Company of existing and future rules and regulations under the act cannot be determined at this time, it is possible that the rules and regulations under the act may increase our cost of using derivative instruments to hedge risks associated with our business or may reduce the availability of such instruments to protect against risks we encounter. Increased costs may arise from any new margin, clearing and trade-execution requirements imposed upon individual transactions, as well as from new capital, reporting, recordkeeping, compliance and business conduct requirements imposed upon our counterparties to the extent those costs are passed through to us. Position limits may be imposed that could further limit our ability to hedge risks. To the extent new rules and regulations require more collateral or margin for individual transactions, our available liquidity may be adversely affected. Additionally, new rules and regulations may restrict our ability to monetize or restructure existing derivative contracts and require us to restructure portions of our energy marketing and trading business. Accordingly, our business and operating results may be adversely affected if, as a result of the act and the rules and regulations promulgated under the act, we are forced to reduce or modify our current use of derivatives.
Supplier defaults may have a negative effect on our operating results.
When the Company enters into fixed-price sales contracts with customers, it typically enters into fixed-price purchase contracts with suppliers. Depending on changes in the market prices of products compared to the prices secured in our contracts with suppliers of LPG, natural gas and electricity, a default of one or more of our suppliers under such contracts could cause us to purchase those commodities at higher prices, which would have a negative impact on our operating results.
We are dependent on our principal propane suppliers, which increases the risks from an interruption in supply and transportation.
During Fiscal 2013, AmeriGas Propane purchased over 90% of its propane needs from twenty suppliers. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, our earnings could be affected. Additionally, in certain areas, a single supplier may provide more than 50% of AmeriGas Propane’s propane requirements. Disruptions in supply in these areas could also have an adverse impact on our earnings. Our international businesses are similarly dependent upon their suppliers. There is no assurance that our international businesses will be able to continue to acquire sufficient supplies of LPG to meet demand at prices or within time periods that would allow them to remain competitive.
Changes in commodity market prices may have a significant negative effect on our liquidity.
Depending on the terms of our contracts with suppliers and some large customers, as well as our use of financial instruments to reduce volatility in the cost of LPG, electricity or natural gas, and for all of our contracts with the New York Mercantile Exchange, changes in the market price of LPG, electricity and natural gas can create margin payment obligations for the Company or one of its subsidiaries and expose us to significant liquidity risks.
Our operations may be adversely affected by competition from other energy sources.
Our energy products and services face competition from other energy sources, some of which are less costly for equivalent energy value. In addition, we cannot predict the effect that the development of alternative energy sources might have on our operations.
Our propane businesses compete for customers against suppliers of electricity, fuel oil and natural gas. Electricity is a major competitor of propane and, except in France, is currently more expensive than propane for space heating, water heating and cooking. The convenience of electricity makes it an attractive energy source for consumers. Fuel oil is also a major competitor of propane and is generally more expensive than propane. Furnaces and appliances that burn propane will not operate on fuel oil and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new equipment. Our customers generally have an incentive to switch to fuel oil only if fuel oil becomes significantly less expensive than propane. Except for certain industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is generally a significantly less expensive source of energy than propane. The gradual expansion of natural gas distribution systems in our service areas has resulted, and may continue to result, in the availability of natural gas in some areas that previously depended upon propane. As long as natural gas remains a less expensive energy source than propane, our propane business will lose customers in each region into which natural gas distribution systems are expanded. In France, the state-owned natural gas monopoly, Gaz de France, has in the past extended France’s natural gas grid. In addition, due to the prevalence of nuclear electric generation in France, the cost of electricity is generally less expensive than that of LPG, particularly when the cost to install new equipment to convert to LPG is considered.
Our natural gas businesses compete primarily with electricity and fuel oil, and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of fuel utilization equipment. There can be no assurance that our natural gas revenues will not be adversely affected by this competition.
Our ability to increase revenues is adversely affected by the decline of the retail LPG industry.
The retail LPG distribution industry in the U.S. and each of the European countries in which we operate is mature and has been declining over the past several years in the United States, with no or modest growth in total demand foreseen. Given this forecast, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability to grow within the LPG industry is dependent on our ability to acquire other retail distributors and to achieve internal growth, which includes expansion of the domestic ACE and National Accounts programs in the U.S., as well as the success of our sales and marketing programs designed to attract and retain customers. Any failure to retain and grow our customer base would have an adverse effect on our business, financial condition and results of operations.
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 United States and in international markets. We may choose to finance future acquisitions with debt, equity, cash or a combination of the three. We can give no assurances that we will find attractive acquisition candidates in the future, that we will be able to acquire such candidates on economically acceptable terms, that we will be able to finance acquisitions on economically acceptable terms, that any acquisitions will not be dilutive to earnings or that any additional debt incurred to finance an acquisition will not affect our ability to pay dividends.
In addition, the restructuring of the energy markets in the United States and internationally, including the privatization of government-owned utilities and the sale of utility-owned assets, is creating opportunities for, and competition from, well-capitalized competitors, which may affect our ability to achieve our business strategy.
To the extent we are successful in making acquisitions, such acquisitions involve a number of risks. These risks include, but are not limited to, the assumption of material liabilities, the diversion of management’s attention from the management of daily operations to the integration of operations, difficulties in the assimilation and retention of employees and difficulties in the assimilation of different cultures and practices and internal controls, as well as in the assimilation of broad and geographically
dispersed personnel and operations. The failure to successfully integrate acquisitions could have an adverse effect on our business, financial condition and results of operations.
Expanding our midstream asset business by constructing new facilities subjects us to risks.
One of the ways we seek to grow our midstream asset business is by constructing new pipelines and gathering systems, expanding our LNG facility and improving our gas storage facilities. These construction projects involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. These projects may not be completed on schedule, or at all, or at the anticipated costs. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. We may construct facilities to capture anticipated future growth in production and demand in an area in which anticipated growth and demand does not materialize. As a result, there is the risk that new and expanded facilities may not be able to attract enough customers to achieve our expected investment returns, which could have a material adverse effect on our business, financial condition and results of operations.
Our need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase our costs and limit our revenue growth, which may result in reduced earnings.
While we generally refer to our Gas Utility and Electric Utility segments as our “regulated segments,” there are many governmental regulations that have an impact on our businesses. 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.
Regulators may not allow timely recovery of costs for UGI Utilities and its Subsidiaries in the future, which may adversely affect our results of operations.
In our Gas Utility and Electric Utility segments, our distribution operations are subject to regulation by the PUC. The PUC, among other things, approves the rates that UGI Utilities and its subsidiaries, PNG and CPG, may charge their utility customers, thus impacting the returns that UGI Utilities and its subsidiaries may earn on the assets that are dedicated to those operations. We expect that UGI Utilities will periodically file requests with the PUC to increase base rates that each company charges customers. If UGI Utilities is required in a rate proceeding to reduce the rates it charges its utility customers, or if UGI Utilities is unable to obtain approval for timely rate increases from the PUC, 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, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. There can be no assurance that our insurance will be adequate to protect us from all material expenses related to pending and future claims or that such levels of insurance will be available in the future at economical prices.
We may be unable to respond effectively to competition, which may adversely affect our operating results.
We may be unable to timely respond to changes within the energy and utility sectors that may result from regulatory initiatives to further increase competition within our industry. Such regulatory initiatives may create opportunities for additional competitors to enter our markets and, as a result, we may be unable to maintain our revenues or continue to pursue our current business strategy.
Our net income and earnings will decrease if we are required to incur additional costs to comply with new governmental safety, health, transportation, tax and environmental regulations.
We are subject to extensive and changing international, federal, state and local safety, health, transportation, tax and environmental laws and regulations governing the storage, distribution and transportation of our energy products.
New regulations, or a change in the interpretation of existing regulations, could result in increased expenditures. In addition, for many of our operations, we are required to obtain permits from regulatory authorities. Failure to obtain or comply with these permits or applicable laws could result in civil and criminal fines or the cessation of the operations in violation.
Governmental regulations and policies in the United States and Europe may provide for subsidies or incentives to customers who use alternative fuels instead of carbon fuels. These subsidies and incentives may result in reduced demand for our energy products and services.
We are investigating and remediating contamination at a number of present and former operating sites in the U.S., including former sites where we or our former subsidiaries operated manufactured gas plants. We have also received claims from third parties that allege that we are responsible for costs to clean up properties where we or our former subsidiaries operated a manufactured gas plant or conducted other operations. Costs we incur to remediate sites outside of Pennsylvania cannot currently be recovered in PUC rate proceedings, and insurance may not cover all or even part of these costs. Our actual costs to clean up these sites may exceed our current estimates due to factors beyond our control, such as:
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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 the third-party claims; or
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the insolvency of other responsible parties at the sites at which we are involved.
In addition, if we discover additional contaminated sites, we could be required to incur material costs, which would reduce our net income.
Our operations, capital expenditures and financial results may be affected by regulatory changes and/or market responses to global climate change.
There continues to be concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global warming. While some states have adopted laws and regulations regulating the emission of GHGs for some industry sectors, there is currently no federal or regional legislation mandating the reduction of GHG emissions in the United States. Although Congress has not enacted federal climate change legislation, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs from motor vehicles and certain large stationary sources, and to require reporting of GHG emissions by certain regulated facilities on an annual basis. For the most part, our facilities are not currently subject to these regulations, but the potential increased costs of regulatory compliance and mandatory reporting by our customers and suppliers could have an effect on our operations or financial condition. The adoption of additional federal or state climate change legislation or regulatory programs to reduce emissions of GHGs could require us or our suppliers to incur increased capital and operating costs, with resulting impact on product price and demand. The impact of new legislation and regulations will depend on a number of factors, including (i) which industry sectors would be impacted, (ii) the timing of required compliance, (iii) the overall GHG emissions cap level, (iv) the allocation of emission allowances to specific sources, and (v) the costs and opportunities associated with compliance. At this time, we cannot predict the effect that climate change regulation may have on our business, financial condition or operations in the future.
Our international operations could be subject to increased risks, which may negatively affect our business results.
We currently operate LPG distribution businesses in Europe through our subsidiaries and we continue to explore the expansion of our international businesses. As a result, we face risks in doing business abroad that we do not face domestically. Certain aspects inherent in transacting business internationally could negatively impact our operating results, including:
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costs and difficulties in staffing and managing international operations;
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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, including the current financial downturn in the euro zone;
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potentially adverse tax consequences, including restrictions on repatriating earnings and the threat of “double taxation”;
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fluctuations in currency exchange rates, which can affect demand and increase our costs;
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internal control and risk management practices and policies;
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regulatory requirements and changes in regulatory requirements, including Norwegian, Swiss and EU competition laws that may adversely affect the terms of contracts with customers, including with respect to exclusive supply rights, and stricter regulations applicable to the storage and handling of LPG; and
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new and inconsistently enforced LPG industry regulatory requirements, which can have an adverse effect on our competitive position.
In addition, there is new proposed tax legislation in France that would limit Antargaz’ ability to deduct interest expense for tax purposes under certain financing structures. If adopted, the proposed legislation would be applied retroactively to tax years ending
on or after September 25, 2013. If the proposed tax legislation is adopted as currently drafted and our current financing structure at Antargaz remains unchanged, the amount of income tax benefits that Antargaz would receive with respect to certain financing arrangements will decrease. As a result, the proposed tax legislation could have an adverse effect on our net income.
Unforeseen difficulties with the operation of our information systems could adversely affect our internal controls and our businesses.
We contracted with third-party consultants to assist us with the design and implementation of an information system that supports the Partnership’s Order-to-Cash business processes. The efficient execution of the Partnership’s business is dependent upon the proper functioning of its internal systems. Any significant failure or malfunction of the Partnership’s or our other business units’ information systems may result in disruptions of their operations. Our results of operations could be adversely affected if we encounter unforeseen problems with respect to the operation of our information systems.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
With the exception of those matters set forth in Note 16 to Consolidated Financial Statements included in Item 8 of this Report, no material legal proceedings are pending involving the Company, any of its subsidiaries, or any of their properties, and no such proceedings are known to be contemplated by governmental authorities other than claims arising in the ordinary course of business.
ITEM 4.
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 on our Common Stock were paid in Fiscal 2013 and Fiscal 2012 as follows:
Record Holders
On November 29, 2013, UGI had 6,839 holders of record of Common Stock.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
(a) Reflects revisions to correct an error in accounting for commodity derivative instruments at Midstream & Marketing and certain other immaterial errors. See Note 3, “Revisions and Restatements of Consolidated Financial Statements,” of Notes to Consolidated Financial Statements included elsewhere in this Report on Form 10-K.
(b) The Selected Financial Data for the years ended September 30, 2010 and 2009 have been revised to correct an error in the accounting for commodity derivative instruments at Midstream & Marketing and certain other immaterial corrections. For general information on the nature of the errors resulting in the corrections, see Note 3 to Consolidated Financial Statements included elsewhere in this Report on Form 10-K.
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 and our financial condition. MD&A should be read in conjunction with our Items 1 & 2, “Business and Properties,” our Item 1A, “Risk Factors,” and our Consolidated Financial Statements in Item 8 below including “Segment Information” included in Note 22 to Consolidated Financial Statements.
Revisions and Restatements of Previously Issued Financial Statements
Historically, the Company used what is commonly referred to as critical terms match to qualify certain of its derivative instruments used in commodity energy transactions by Midstream & Marketing’s reportable segments (comprising Energy Services and Electric Generation) as cash flow hedges under accounting principles generally accepted in the United States of America (“GAAP”). During the preparation of the Fiscal 2013 consolidated financial statements, management concluded that it had incorrectly accounted for these derivative instruments as cash flow hedges. Management had incorrectly applied the hedge accounting criteria when designating these derivative instruments as cash flow hedges largely because its intended plans for supply fulfilment at the time of the hedge inception were not met when we later chose to optimize supply for those hedged transactions. As a result, changes in the fair values of these derivative instruments for which the associated forecasted transaction had not yet occurred have been reported as a component of cost of sales or revenues in the Consolidated Statements of Income rather than in other comprehensive income. Management has discontinued the use of hedge accounting for substantially all of Midstream & Marketing’s commodity derivative instruments and has reported changes in the fair values of unsettled commodity derivative instruments, and gains and losses on settled commodity derivative instruments for which the associated forecasted transactions have not yet occurred, in net income in the consolidated financial statements included in this Report on Form 10-K.
Although the impact of the error was not material to the Company’s historical annual consolidated financial statements, the Company decided to revise its consolidated financial statements and disclosures to correct this error in accounting for Fiscal 2012 and Fiscal 2011 and to record certain other immaterial corrections. Because management concluded that the error in accounting for derivative instruments used in commodity derivative transactions by Midstream & Marketing’s reportable segments and the other corrections were material to its consolidated financial statements for the fiscal quarters ended March 31, 2013, June 30, 2012 and December 31, 2011, it is restating the Company’s financial statements for those periods while the Company’s consolidated financial statements for other quarterly periods within Fiscal 2013 and Fiscal 2012 have been revised. As a result of the revisions and restatements, changes in the fair values of unsettled derivatives and gains and losses on settled derivative instruments not associated with current period transactions are recorded in revenues or cost of sales in the Consolidated Statements of Income. This change has no effect on the Company’s financial condition, day-to-day operations, cash flow or liquidity. For further information on the effects of the revisions and restatements, see Note 3 and Note 21 to the Consolidated Financial Statements.
The following MD&A gives effect to the revisions to the Fiscal 2012 and Fiscal 2011 Consolidated Financial Statements as discussed in Note 3 to the Consolidated Financial Statements.
Executive Overview
We recorded net income attributable to UGI Corporation of $278.1 million, equal to $2.41 per diluted share, for Fiscal 2013 compared to $210.2 million, equal to $1.85 per diluted share, for Fiscal 2012. Operating results in Fiscal 2013 were higher at each of our businesses due in large part to winter heating season and early spring temperatures that were closer to normal compared to temperatures that were substantially warmer than normal in Fiscal 2012. The improved Fiscal 2013 results also reflect the full-year operations of Heritage Propane, which was acquired on January 12, 2012, the full-year benefits from the integration of the Shell LPG businesses acquired in early Fiscal 2012 at UGI International, and the completion of the Heritage Propane integration during Fiscal 2013 (see Note 5 to Consolidated Financial Statements for further information on the Heritage Propane and Shell acquisitions).
At AmeriGas Propane, temperatures based upon heating degree days were approximately 4.9% warmer than normal but approximately 16% colder than the prior year. The significantly colder weather, the full-year operations of Heritage Propane and the benefits of lower propane supply prices resulted in a $32.1 million increase in net income attributable to UGI Corporation from AmeriGas Propane. At UGI International, significantly improved results at Antargaz, the result of a return to near normal weather and higher unit margins, and improved results at Flaga and AvantiGas due in large part to colder weather and lower net operating costs, resulted in an $17.5 million year-over-year increase in net income attributable to UGI Corporation. Fiscal 2013 Gas Utility results were also significantly higher than the prior year reflecting the effects of colder Fiscal 2013 weather and, to a much lesser extent, customer growth principally due to customer conversions from oil. Midstream & Marketing's Energy Services business also benefited in Fiscal 2013 from the effects of colder weather on natural gas marketing and midstream asset activities,
while Midstream & Marketing's Electric Generation business benefited from higher electricity volumes, increased electricity spot market prices and higher capacity revenues. The improved Electric Generation volumes in Fiscal 2013 reflect the full availability of our Hunlock Creek electricity generating station and greater production from the Conemaugh electricity generating station in which we own a 5.97% interest.
We believe that each of our business units has sufficient liquidity in the forms of revolving credit facilities, and with respect to Energy Services also an accounts receivable securitization facility, to fund business operations in Fiscal 2014 (see Financial Condition and Liquidity below).
Looking ahead, our results in Fiscal 2014 will be influenced by a number of factors including heating-season temperatures, the level and volatility of commodity prices for natural gas, LPG, electricity and oil, and economic conditions in the U.S. and Europe. We have made substantial progress on growth initiatives that will fuel earnings growth in the future. The integration efforts at AmeriGas Propane and UGI International are complete and we recently expanded our presence in Poland with the September 2013 acquisition of BP’s LPG distribution business in that country. Acquisition activity in Europe over the last several years makes us an attractive supply partner and creates new business opportunities. At Gas Utility, we expect to experience continued strong growth from conversions from oil as a result of sustained low natural gas prices. We have also made excellent progress on Midstream & Marketing’s Marcellus Shale initiatives in Pennsylvania including the Auburn II pipeline extension project, our storage compressor station project and our Fiscal 2013 acquisition of working interests in natural gas wells. To the extent normal weather patterns have returned, we hope to reap the benefits from these growth initiatives in Fiscal 2014 and beyond.
Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share
UGI management uses “adjusted net income attributable to UGI” and “adjusted earnings per diluted 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 excluding changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments as well as gains and losses on settled commodity derivative instruments not associated with current period transactions. UGI accounts for these commodity derivative instruments at fair value with changes in fair value included in earnings as a component of cost of sales or revenues on the Consolidated Statements of Income. Volatility in net income at UGI can occur as a result of changes in the fair values of unsettled commodity derivative instruments as well as timing differences between the settlement of commodity derivative instruments and the income statement impact of the purchase or sale of the associated commodity. 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 about UGI’s performance because they eliminate the impact of changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments as well as gains and losses on settled commodity derivative instruments not associated with current period transactions that are required, under GAAP, to be recorded in current period earnings.
The following table reconciles consolidated net income attributable to UGI Corporation, the most directly comparable GAAP measure, to adjusted net income attributable to UGI, and reconciles diluted earnings per share, the most comparable GAAP measure, to adjusted diluted earnings per share, to reflect adjustments relating to changes in the fair values of Midstream & Marketing’s commodity derivative instruments and certain gains and losses on settled commodity derivative instruments:
Results of Operations
The following analyses compare the Company’s results of operations for (1) Fiscal 2013 with Fiscal 2012 and (2) Fiscal 2012 with the year ended September 30, 2011 (“Fiscal 2011”).
Fiscal 2013 Compared with Fiscal 2012
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:
(a) Includes changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments and gains and
losses on settled commodity derivative instruments not associated with current period transactions of $4.3 million and $8.9 million in Fiscal 2013 and Fiscal 2012, respectively.
N.M. - Variance is not meaningful.
Highlights - Fiscal 2013 versus Fiscal 2012
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Net income increased significantly in Fiscal 2013 due primarily to a return to more normal winter weather patterns and cooler spring temperatures.
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Fiscal 2013 results include the full-year effects of AmeriGas Partners’ January 2012 acquisition of Heritage Propane and the benefits from the integrations of Heritage Propane and Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden acquired in October 2011 (the “Shell Transaction”).
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Fiscal 2013 results include Heritage Propane transition expenses of $26.5 million (after-tax impact to UGI of $(4.4) million equal to $(0.04) per diluted share). Fiscal 2012 results include combined Heritage Propane and Shell pre-tax acquisition and transition expenses totaling approximately $53 million (after-tax impact to UGI of $(13.3) million equal to $(0.12) per diluted share).
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Fiscal 2013 LPG unit margins at AmeriGas Propane and UGI International were higher principally reflecting the benefit of lower average LPG commodity costs.
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Midstream & Marketing’s Energy Services business benefited from the the colder weather including higher income from winter peaking and capacity management activities. Additionally, Midstream & Marketing’s Electric Generation business results improved on higher generation volumes and higher average unit margins.
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Gas Utility continued to experience record numbers of customer conversions to natural gas from alternative fuels.
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AmeriGas Propane Fiscal 2012 results include a $2.2 million after-tax loss ($0.02 per diluted share) on extinguishments of debt.
(a)
Total margin represents total revenues less total cost of sales.
(b)
Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America (“GAAP”). Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 22 to Consolidated Financial Statements). Partnership EBITDA for Fiscal 2012 includes pre-tax losses of $13.3 million associated with extinguishments of debt. Partnership EBITDA and operating income for Fiscal 2013 and Fiscal 2012 also includes acquisition and transition expenses of $26.5 million and $46.2 million, respectively, associated with Heritage Propane.
(c)
Deviation from average heating degree days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska.
Results for Fiscal 2013 reflect the full-year operations of Heritage Propane acquired in January 2012. Based upon heating degree-day data, temperatures in the Partnership's service territories during Fiscal 2013 averaged approximately 4.9% warmer than normal but 16.2% colder than in Fiscal 2012. Retail gallons sold increased 227.7 million gallons (22.4%) principally reflecting the full-year impact of the Heritage Propane operations and the colder Fiscal 2013 weather.
Retail propane revenues increased $241.6 million during Fiscal 2013 reflecting the higher retail volumes sold ($567.6 million) partially offset by a decline in average retail selling prices ($326.0 million) which was the result of lower propane product costs. Wholesale propane revenues declined $33.7 million principally reflecting lower average wholesale propane selling prices ($28.6 million) and lower wholesale volumes sold ($5.1 million). Average daily wholesale propane commodity prices during Fiscal 2013 at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 19% lower than such prices during Fiscal 2012. Total revenues from fee income and other ancillary sales and services in Fiscal 2013 were $39.4 million higher than in Fiscal 2012 principally reflecting the full-year effects of Heritage Propane. Total propane cost of sales decreased $76.5 million principally reflecting the effects of the previously mentioned lower propane commodity prices on retail propane cost of sales ($376.3 million) and lower wholesale propane cost of sales ($36.8 million) substantially offset by the effects of the greater retail
volumes sold ($336.6 million). Cost of sales associated with ancillary sales and services increased $11.3 million principally reflecting the full-year effects of Heritage Propane.
Total margin increased $312.5 million in Fiscal 2013 principally reflecting higher total propane margin ($284.4 million) and greater total margin from fee income and ancillary sales and services ($28.1 million). These increases principally reflect the incremental full-year effects of Heritage Propane, the colder Fiscal 2013 weather and, with respect to total propane margin, slightly higher average unit margins reflecting in large part the lower propane product costs.
Partnership EBITDA in Fiscal 2013 increased $274.4 million principally reflecting the higher total margin ($312.5 million) and the absence of the $13.3 million loss on extinguishments of debt recorded in Fiscal 2012 partially offset by higher Partnership operating and administrative expenses ($56.7 million) primarily attributable to the full-year effects of Heritage Propane operations. Operating and administrative expenses in Fiscal 2013 include $26.5 million of transition expenses associated with the integration of Heritage Propane while operating and administrative expenses in Fiscal 2012 include Heritage Propane acquisition and transition-related expenses of $46.2 million. AmeriGas Propane operating income increased $225.7 million in Fiscal 2013 principally reflecting the higher total margin ($312.5 million) partially offset by the previously mentioned greater operating and administrative expenses ($56.7 million) and increased depreciation and amortization expense ($37.8 million) reflecting in large part the full-year effects of Heritage Propane.
(a)
Total margin represents total revenues less total cost of sales.
(b)
Excludes retail gallons from operations in China.
(c)
Deviation from average heating degree days for the 30-year period 1981-2010 at locations in our Antargaz and Flaga service territories.
Based upon heating degree day data, temperatures in our European LPG operations in Fiscal 2013 were colder than normal and colder than the prior year. Although Fiscal 2013 wholesale commodity prices for propane and butane based upon index prices in northwest Europe averaged only slightly lower than in Fiscal 2012, such LPG prices generally declined during the Fiscal 2013 peak heating season while LPG prices generally increased during the Fiscal 2012 peak heating season. Retail LPG gallons sold in Fiscal 2013 were higher than Fiscal 2012 principally reflecting the effects of significantly colder weather across all of our European operations partially offset by the effects of a decline in economic activity mainly on commercial and industrial customers in certain of our European markets.
Our UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. The functional currency of a significant portion of our UGI International results is the euro. During Fiscal 2013 and Fiscal 2012, the average unweighted translation rate was approximately $1.31 and $1.30 per euro, respectively. The difference in rates did not have a material impact on net income attributable to UGI.
UGI International revenues increased $233.1 million principally reflecting the effects on LPG revenues of greater low-margin wholesale sales, the increase in LPG retail volumes sold and to a lesser extent greater average retail prices. The increase in revenues also reflects higher revenues from natural gas marketing activities in France. Cost of sales increased to $1,498.4 million in Fiscal 2013 from $1,325.8 million in Fiscal 2012 principally reflecting the effects of the greater wholesale and retail LPG volumes sold. The higher UGI International cost of sales also reflects increased cost of sales associated with natural gas marketing activities in France.
Total UGI International margin increased $60.5 million during Fiscal 2013 principally reflecting higher retail LPG unit margins and volumes at Antargaz and, to a much lesser extent, greater total LPG margin at AvantiGas and Flaga.
UGI International operating income and income before income taxes increased $35.1 million and $35.5 million, respectively, principally reflecting the higher total margin ($60.5 million) partially offset by modestly higher operating and administrative expenses. Operating and administrative expenses in Fiscal 2013 principally reflect higher delivery, selling, and incentive compensation and benefits costs principally at Antargaz. Fiscal 2013 UGI International operating and administrative costs include approximately $4.0 million of acquisition and transition costs associated with Flaga’s September 2013 acquisition of BP’s LPG distribution business in Poland, while Fiscal 2012 UGI International operating and administrative expenses include acquisition and transition costs of approximately $7.0 million associated with the LPG businesses acquired from Shell in October 2011. UGI International net income in Fiscal 2013 as a percentage of UGI International earnings before income taxes was lower than the prior year as the Fiscal 2012 UGI International effective income tax rate reflects, in part, the effects of a greater proportion of UGI International tax benefits relative to pre-tax income and the realization of $4.7 million of previously unrecognized foreign tax credits.
(a)
Total margin represents total revenues less total cost of sales.
(b)
Deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.
Temperatures in the Gas Utility service territory in Fiscal 2013 based upon heating degree days were 0.5% warmer than normal but 18.2% colder than Fiscal 2012. Total distribution system throughput increased principally reflecting significantly higher throughput to core market customers and, to a lesser extent, greater net volumes associated with lower margin firm and interruptible delivery service customers. Gas Utility system throughput to core-market customers was above last year principally reflecting the effects of the significantly colder weather and, to a much lesser extent, customer growth, principally conversions from oil prompted by sustained lower natural gas prices and high oil prices. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.
Gas Utility revenues increased $53.6 million during Fiscal 2013 principally reflecting higher revenues from core market customers ($52.8 million) and higher large firm delivery service revenues ($9.2 million) partially offset by lower off-system sales revenues ($8.6 million). The increase in core market revenues principally reflects the effects of higher retail core-market volumes on PGC revenues ($60.4 million) and greater core market delivery service revenues partially offset by the effects of lower average PGC rates on retail core-market revenues ($50.6 million). Increases or decreases in retail core-market revenues and cost of sales principally result from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility's cost of gas was $407.2 million in Fiscal 2013 compared with $402.5 million in Fiscal 2012 principally reflecting the effects on cost of sales of the greater retail core-market volumes ($60.4 million) substantially offset by the effects of lower average PGC rates ($50.6 million) and the lower off-system sales.
Gas Utility total margin increased $48.9 million in Fiscal 2013 principally reflecting higher core market margin ($38.1 million) and higher large firm delivery service total margin ($9.6 million). The higher core market margin reflects the effects of the greater core market volumes.
The increase in Gas Utility operating income during Fiscal 2013 principally reflects the increase in total margin ($48.9 million) partially offset by higher operating and administrative expenses ($20.2 million) including, among other things, higher pension and benefits expenses ($10.7 million), higher uncollectible accounts expenses ($2.8 million) on higher core market volumes, and greater injuries and damages and distribution system expenses ($4.5 million). The greater income before income taxes in Fiscal 2013 reflects the higher operating income ($22.4 million) and slightly lower interest expense on lower long-term debt outstanding.
(a) Amounts are net of intercompany revenues between Midstream & Marketing’s Energy Services and Electric Generation segments.
(b) Total margin represents total revenues less total cost of sales. Amounts exclude pretax gains (losses) from changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments and gains (losses) on settled commodity derivative instruments not associated with current period transactions of $7.4 million and $15.1 million in Fiscal 2013 and Fiscal 2012, respectively.
Midstream & Marketing total revenues increased $183.7 million in Fiscal 2013 principally reflecting, among other things, higher natural gas revenues ($145.1 million) from higher wholesale volumes sold and higher average selling prices for natural gas, and higher Electric Generation total revenues ($30.7 million) principally the result of higher electricity volumes and prices.
Midstream & Marketing Fiscal 2013 total margin was $33.6 million higher than Fiscal 2012 reflecting higher Electric Generation total margin ($15.6 million), higher natural gas marketing total margin ($14.2 million), and greater peaking and capacity management total margin ($13.4 million) due to the colder weather and greater natural gas price volatility. These increases were partially offset by lower retail power total margin principally reflecting lower average unit margins. Total margin from natural gas marketing activities in Fiscal 2013 principally reflects the benefits of higher average unit margins. Natural gas marketing average unit margins in Fiscal 2013 benefited from higher-margin incremental sales resulting from the colder weather while average unit margins in Fiscal 2012 were negatively impacted by significantly warmer than normal weather. The greater total margin from Electric Generation principally reflects the impact of higher electricity production from our Hunlock Creek natural gas-fired electricity generating station and greater volumes sold from the Conemaugh generating station. In Fiscal 2012 the Hunlock Creek generating station was running at less than full capacity due to an accident at one unit and flood damage at another unit sustained late in Fiscal 2011. Unit margins from Electric Generation were higher in Fiscal 2013 reflecting higher electricity spot market prices, the effects of lower per unit fuel costs at the Hunlock Creek generating station, and higher capacity revenues from the Hunlock Creek and Conemaugh generating stations.
Midstream & Marketing operating income in Fiscal 2013 was $25.7 million higher than Fiscal 2012 reflecting the previously mentioned increase in total margin ($33.6 million) partially offset by higher operating, administrative and depreciation expenses.
The higher operating and administrative expenses ($3.1 million) include greater Energy Services operating expenses ($2.6 million) due in large part to expenses associated with peaking LNG liquefaction and storage facilities and incremental expenses associated with our non-operating working interest in natural gas acreage in the Marcellus Shale region in northern Pennsylvania acquired in January 2013. The increase in depreciation expenses ($4.9 million) principally reflects greater depreciation associated with the full-year operation of LNG facilities and the Hunlock Creek generating station. The increase in Midstream & Marketing income before income taxes reflects the greater operating income and lower interest expense on Energy Services' Credit Agreement and Receivables Facility borrowings.
Interest Expense. Our consolidated interest expense was $19.9 million higher in Fiscal 2013 primarily reflecting higher AmeriGas Propane interest expense ($25.0 million), principally full-year interest on debt issued to fund the cash portion of the January 12, 2012, acquisition of Heritage Propane, partially offset by slightly lower UGI Utilities interest expense ($2.9 million) on slightly lower long-term debt outstanding and lower Midstream & Marketing interest expense.
Income Taxes. Income taxes as a percentage of pretax earnings was lower in Fiscal 2013 reflecting, in part, the effects of a higher percentage of income associated with noncontrolling interests not subject to tax, principally AmeriGas Partners, and the realization of previously unrecognized state deferred tax benefits while income taxes in Fiscal 2012 were reduced by $4.7 million as a result of the realization of previously unrecognized foreign tax credits.
Fiscal 2012 Compared with Fiscal 2011
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:
(a) Includes changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments and gains and losses on settled commodity derivative instruments not associated with current period transactions of $8.9 million and $17.4 million in Fiscal 2012 and Fiscal 2011, respectively.
N.M. - Variance is not meaningful.
Highlights - Fiscal 2012 versus Fiscal 2011
•
Our U.S. and European business units were adversely affected by significantly warmer heating-season temperatures during Fiscal 2012. The Fiscal 2012 heating season in the U.S. came to an abrupt end in March 2012.
•
Fiscal 2012 consolidated results were impacted by the January 2012 acquisition of Heritage Propane at AmeriGas Propane and the October 2011 Shell Transaction. Results include combined pre-tax acquisition and transition expenses totaling approximately $53 million (after-tax impact of $(13.3) million equal to $(0.12) per diluted share).
•
AmeriGas Propane Fiscal 2012 results include a $2.2 million after-tax loss ($0.02 per diluted share) on extinguishments of debt while Fiscal 2011 results include a $10.3 million after-tax loss ($0.09 per diluted share) on extinguishments of debt.
•
Midstream & Marketing net income was lower in Fiscal 2012 reflecting the effects of warmer weather on natural gas volumes sold and lower unit margins from our Electric Generation business. Lower and less volatile natural gas prices in Fiscal 2012 reduced capacity management income.
•
Fiscal 2012 UGI International net income benefited from a lower effective income tax rate. Fiscal 2011 Antargaz results include $9.4 million ($0.08 per diluted share) from the reversal of a nontaxable reserve associated with a French competition authority matter.
(a)
Total margin represents total revenues less total cost of sales.
(b)
Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 22 to Consolidated Financial Statements). Partnership EBITDA for Fiscal 2012 and Fiscal 2011 includes pre-tax losses of $13.3 million and $38.1 million, respectively, associated with extinguishments of debt. Partnership EBITDA and operating income for Fiscal 2012 also include acquisition and transition expenses of $46.2 million associated with Heritage Propane.
(c)
Deviation from average heating degree days for the 30-year period 1971-2000 based upon national weather statistics provided by NOAA for 335 airports in the United States, excluding Alaska.
Based upon heating degree-day data, temperatures in the Partnership's service territories during Fiscal 2012 averaged 18.6% warmer than normal and 18.3% warmer than Fiscal 2011. The winter heating season also came to an early end with temperatures in the month of March averaging 38% warmer than normal. Notwithstanding the record warm weather's impact on our legacy AmeriGas Propane volumes, retail propane gallons sold were 143.3 million gallons greater than in the prior year reflecting the impact of Heritage Propane.
Retail propane revenues increased $362.6 million during Fiscal 2012 primarily reflecting higher retail volumes sold. The higher retail volumes sold reflects incremental gallons sold associated with Heritage Propane partially offset by the effects of weather-reduced volumes in AmeriGas Propane’s legacy operations. Wholesale propane revenues decreased $45.0 million principally reflecting lower wholesale volumes sold ($28.8 million) and lower average wholesale propane selling prices ($16.2 million). Average daily wholesale propane commodity prices during Fiscal 2012 at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 20% lower than such prices during Fiscal 2011. Total revenues from fee income and other ancillary sales and services in Fiscal 2012 were $65.7 million higher than Fiscal 2011 reflecting such revenues from Heritage Propane. Total cost of sales increased $117.0 million principally reflecting incremental cost of sales from Heritage Propane offset in part by both the previously mentioned lower retail and wholesale volumes sold by our legacy AmeriGas Propane operations and the lower average propane commodity prices.
Total margin increased $266.3 million in Fiscal 2012 reflecting higher total propane margin ($218.6 million) and higher total margin from ancillary sales and services ($47.7 million). The increases principally reflect incremental margin from Heritage Propane partially offset by lower total propane margin from legacy AmeriGas Propane operations resulting from the significantly warmer weather.
Partnership EBITDA (which includes the losses on extinguishments of debt) in Fiscal 2012 increased $26.5 million principally reflecting the higher total margin ($266.3 million) and a $24.8 million lower loss from extinguishments of debt partially offset by higher operating and administrative expenses ($267.0 million) primarily attributable to Heritage Propane. Fiscal 2012 operating expenses include $46.2 million of acquisition and transition expenses associated with Heritage Propane. Operating income (which excludes the losses on extinguishments of debt) decreased $72.9 million in Fiscal 2012 principally reflecting the higher total margin ($266.3 million) more than offset by the increased operating expenses ($267.0 million) and greater depreciation and amortization expense ($73.6 million) principally associated with Heritage Propane.
(a)
Total margin represents total revenues less total cost of sales.
(b)
Excludes retail gallons from operations in China.
(c)
Deviation from average heating degree days for the 30-year period 1981-2010 at locations in our Antargaz and Flaga service territories.
UGI International operating results in Fiscal 2012 include the operating results from the Shell Transaction. Based upon heating degree day data, temperatures across Europe were significantly warmer than normal and warmer than the prior year. Weather at Antargaz was approximately 7.1% warmer than normal in Fiscal 2012 compared to weather that was approximately 4.7% warmer than normal in Fiscal 2011. Temperatures in Flaga’s central and eastern European operations were approximately 6.4% warmer than normal in Fiscal 2012 compared to temperatures that were approximately 4.6% warmer than normal in Fiscal 2011. During Fiscal 2012, the average unweighted wholesale commodity price for propane in northwest Europe was approximately 4% higher than such prices in Fiscal 2011, while the average unweighted wholesale commodity price for butane was approximately 5% higher than Fiscal 2011. Retail LPG gallons sold were higher than the prior year reflecting incremental volumes of approximately 175 million gallons associated with the Shell Transaction partially offset by the effects of warmer and erratic weather patterns on volumes sold in our legacy UGI International operations.
Our UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. The functional currency of a significant portion of our UGI International results is denominated in euros. During Fiscal 2012 and Fiscal 2011, the average unweighted translation rate was approximately $1.30 and $1.40 per euro, respectively. The difference in rates did not have a material impact on net income attributable to UGI.
UGI International revenues increased $457.4 million, notwithstanding the effects of the significantly warmer weather, principally reflecting the effects of the Shell Transaction (approximately $569 million) partially offset by lower revenues from our legacy European LPG distribution businesses due in large part to the effects of the weaker euro. Cost of sales increased to $1,325.8 million in Fiscal 2012 from $970.8 million in Fiscal 2011 principally reflecting incremental cost of sales from the Shell Transaction (approximately $443 million) offset by lower cost of sales from our legacy European LPG distribution businesses due in large part to the effects of the weaker euro.
Total UGI International margin increased $102.4 million principally reflecting incremental margin from the Shell Transaction (approximately $125.8 million) and higher unit margins at our Antargaz legacy operations partially offset by the effects of the lower volumes at our legacy Antargaz and Flaga units resulting from the warmer weather.
UGI International operating income in Fiscal 2012 was $25.8 million higher than Fiscal 2011 principally reflecting the higher total margin ($102.4 million) resulting from the Shell Transaction offset by incremental expenses associated with these acquired businesses, including operating and administrative expenses, depreciation and acquisition integration costs. Fiscal 2012 operating and administrative expenses include approximately $7.0 million of Shell Transaction transition expenses. Fiscal 2011 operating income includes $9.4 million of other income from the reversal at Antargaz of a nontaxable reserve associated with the French competition authority matter at Antargaz. The $23.7 million increase in income before income taxes principally reflects the previously mentioned increase in operating income ($25.8 million) partially offset by a $2.7 million increase in interest expense, principally higher interest expense on Antargaz’ long-term debt and higher Flaga debt outstanding. Net income from UGI International operations in Fiscal 2012 benefited from a lower UGI International effective income tax rate resulting from the impact of the tax efficient structuring of certain of our international operations, the realization of $4.6 million of previously unrecognized foreign tax credits, and a higher proportion of pre-tax income in lower statutory tax-rate countries as a result of the Shell Transaction.
(a)
Total margin represents total revenues less total cost of sales.
(b)
Deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory.
Temperatures in the Gas Utility service territory in Fiscal 2012 based upon heating degree days were 16.3% warmer than normal and approximately 18.7% warmer than the prior year. Total distribution system throughput was slightly higher than last year, notwithstanding the significantly warmer weather, principally reflecting greater throughput to certain non-weather-sensitive low-margin interruptible delivery service customers. Excluding total volumes to interruptible delivery service customers, Gas Utility system throughput declined 14.3 bcf in Fiscal 2012 principally reflecting the effects of the significantly warmer weather on throughput to core market customers (11.2 bcf) and lower firm delivery service volumes.
Gas Utility revenues decreased $241.0 million during Fiscal 2012 principally reflecting a decline in revenues from retail core-market customers ($169.4 million) and lower revenues from off-system sales ($68.1 million). The decrease in retail core-market revenues principally reflects the effects on gas cost recovery revenues of the lower retail core-market volumes ($91.9 million) and lower average PGC rates resulting from lower natural gas prices ($43.2 million). Gas Utility’s cost of gas was $402.5 million in Fiscal 2012 compared with $610.6 million in Fiscal 2011 reflecting the previously mentioned lower retail core-market sales ($91.9 million), the lower average PGC rates ($43.2 million) and the above-mentioned lower off-system sales.
Gas Utility total margin decreased $32.9 million in Fiscal 2012. The decrease principally reflects lower core market total margin ($27.7 million) and firm delivery service total margin ($4.8 million). Fiscal 2012 Gas Utility total margin includes a full-year of incremental margin from the August 2011 base rate increase at CPG of approximately $9.0 million.
The decreases in Gas Utility operating income and income before income taxes during Fiscal 2012 principally reflects the previously mentioned decrease in total margin ($32.9 million) partially offset by lower operating and administrative expenses.
(a) Amounts are net of intercompany revenues between Midstream & Marketing’s Energy Services and Electric Generation segments.
(b) Total margin represents total revenues less total cost of sales. Amounts exclude pretax gains (losses) from changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments and gains (losses) on settled commodity derivative instruments not associated with current period transactions of $15.1 million and $29.8 million in Fiscal 2012 and Fiscal 2011, respectively.
Midstream & Marketing Fiscal 2012 results were impacted by significantly warmer than normal heating-season temperatures and lower and less volatile natural gas prices. Midstream & Marketing total revenues decreased $205.3 million in Fiscal 2012 principally reflecting lower total revenues from natural gas marketing activities ($211.6 million), the result of lower average natural gas prices and lower volumes sold due to the warmer weather and, to a much lesser extent, lower Electric Generation revenues ($4.7 million) and capacity management revenues ($5.8 million). These decreases were partially offset by greater retail power revenues ($8.9 million), reflecting higher sales, and higher storage services revenues ($7.5 million).
The $7.1 million decrease in Midstream & Marketing’s total margin principally reflects lower natural gas marketing total margin ($17.4 million), lower capacity management total margin ($5.8 million), principally the result of the lower and less volatile natural gas prices, and lower Electric Generation total margin ($0.8 million) partially offset by greater retail power natural gas storage and gas gathering total margin. The decrease in Electric Generation total margin principally reflects the effects of lower electricity prices due in large part to the effects on electricity prices of lower natural gas prices.
Midstream & Marketing’s operating income in Fiscal 2012 was $16.5 million lower than Fiscal 2011 reflecting the decrease in total margin ($7.1 million) and higher operating, administrative and depreciation expenses associated with Electric Generation assets ($3.2 million), including incremental expenses associated with the repowered Hunlock Creek generation station and higher fuel and maintenance expenses associated with the Conemaugh generation station, and greater energy marketing and storage services’ operating and administrative expenses. The decline in income before income taxes reflects the lower operating income ($20.5 million) and greater interest expense principally on Energy Services’ credit facility borrowings.
Interest Expense. Our consolidated interest expense was $82.4 million higher in Fiscal 2012 reflecting higher AmeriGas Propane interest expense ($78.0 million) on debt issued to fund the acquisition of Heritage Propane; greater UGI International interest expense ($2.7 million); and slightly higher Midstream & Marketing interest expense.
Income Taxes. Our effective income tax rate in Fiscal 2012 was higher than in Fiscal 2011 principally reflecting a much smaller share of pre-tax income from AmeriGas Partners which income is generally not subject to entity-level income taxes. Excluding the impact on the effective income tax rate of AmeriGas Partners’ pre-tax income not subject to tax, the Fiscal 2012 effective tax rate was lower than in Fiscal 2011 reflecting, in large part, the effects of the previously mentioned lower UGI International income tax rate. The Fiscal 2011 effective tax rate was reduced by, among other things, the effect of the reversal of the $9.4 million reserve associated with the French competition authority matter at Antargaz, which was not subject to tax, and the regulatory effects of greater state tax depreciation (as further described below under “UGI Utilities Income Taxes”).
Financial Condition and Liquidity
We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities and, in the case of Midstream & Marketing, also from a receivables purchase facility. Long-term cash requirements not met by cash from operations are generally met through issuance of long-term debt or equity securities. We believe that each of our business units has sufficient liquidity in the forms of cash and cash equivalents on hand; cash expected to be generated from operations; credit facility and receivables purchase facility borrowings; and the ability to obtain long-term financing to meet anticipated contractual and projected cash commitments. Issuances of debt and equity securities in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.
Our cash and cash equivalents, excluding cash in commodity futures brokerage accounts that is restricted from withdrawal, totaled $389.3 million at September 30, 2013, compared with $319.9 million at September 30, 2012. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30, 2013 and 2012, UGI had $171.6 million and $107.9 million, respectively, of cash and cash equivalents. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.
The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business units.
AmeriGas Propane’s ability to pay dividends to UGI is dependent upon distributions it receives from AmeriGas Partners. At September 30, 2013, our 27% effective ownership interest in the Partnership consisted of approximately 23.8 million Common Units and an aggregate 2% general partner interest. Approximately 45 days after the end of each fiscal quarter, the Partnership
distributes all of its Available Cash (as defined in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, as amended (the “Partnership Agreement”)) relating to such fiscal quarter. AmeriGas Propane, as general partner of AmeriGas Partners, is entitled to receive incentive distributions when AmeriGas Partners’ quarterly distribution exceeds $0.605 per limited partner unit (see Note 15 to Consolidated Financial Statements).
During Fiscal 2013, Fiscal 2012 and Fiscal 2011, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:
In Fiscal 2013 and Fiscal 2011, Midstream & Marketing received capital contributions from UGI totaling $27.5 million and $45.7 million, respectively, to fund major midstream asset and electric generation capital projects including Marcellus Shale infrastructure projects. Dividends in Fiscal 2012 from Midstream & Marketing were used to fund a portion of the October 2011 Shell Transaction.
On April 30, 2013, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.2825 per common share or $1.13 per common share on an annual basis. This dividend reflects a 4.6% increase from the previous quarterly dividend rate of $0.27. The new quarterly dividend rate was effective with the dividend payable on July 1, 2013, to shareholders of record on June 14, 2013.
On April 29, 2013, the General Partner’s Board of Directors approved a quarterly distribution of $0.84 per Common Unit equal to an annual rate of $3.36 per Common Unit. This distribution reflects an approximate 5% increase from the previous quarterly rate of $0.80 per Common Unit. The new quarterly rate was effective with the distribution payable on May 17, 2013, to unitholders of record on May 10, 2013.
As a result of the issuance of 29,567,362 AmeriGas Partners Common Units to ETP in conjunction with the acquisition of Heritage Propane and related General Partner Common Unit transactions (see Note 5 to Consolidated Financial Statements), and the issuance of 7,000,000 AmeriGas Partners Common Units pursuant to AmeriGas Partners’ public offering (see Note 15 to Consolidated Financial Statements), during Fiscal 2012, the Company recorded a $196.3 million increase in UGI Corporation stockholders’ equity (which amount is net of deferred income taxes) and an associated $321.4 million pre-tax decrease in noncontrolling interests equity.
Long-term Debt and Credit Facilities
The Company’s debt outstanding at September 30, 2013, totaled $3,837.3 million (including current maturities of long-term debt of $67.2 million and bank loan borrowings of $227.9 million) compared to debt outstanding at September 30, 2012, of $3,679.4 million (including current maturities of long-term debt of $166.7 million and bank loan borrowings of $165.1 million). Total debt outstanding at September 30, 2013, consists of (1) $2,417.0 million of Partnership debt; (2) $660.9 million (€488.6 million) of UGI International debt; (3) $659.5 million of UGI Utilities’ debt; (4) $88.0 million of Midstream & Marketing debt; and (5) $11.9 million of other debt. For a detailed description of the Company’s debt, see below and Note 6 to Consolidated Financial Statements.
AmeriGas Partners. AmeriGas Partners’ total debt at September 30, 2013, includes $2,250.8 million of AmeriGas Partners’ Senior Notes, $49.3 million of other long-term debt and $116.9 million of AmeriGas OLP bank loan borrowings.
In order to finance the cash portion of the acquisition of Heritage Propane, on January 12, 2012, AmeriGas Finance Corp. and AmeriGas Finance LLC (the “Issuers”) issued $550 million principal amount of 6.75% Notes due May 2020 (the “6.75% Notes”) and $1,000 million principal amount of 7.00% Notes due May 2022 (the “7.00% Notes”). The 6.75% Notes and the 7.00% Notes are fully and unconditionally guaranteed on a senior secured basis by AmeriGas Partners. The 6.75% and 7.00% Notes and the guarantees rank equal in right of payment with all of AmeriGas Partners’ existing senior notes. In connection with the acquisition of Heritage Propane, AmeriGas Partners, AmeriGas Finance Corp., AmeriGas Finance LLC and UGI entered into a Contingent
Residual Support Agreement (“CRSA”) with ETP pursuant to which ETP will provide contingent, residual support of $1.5 billion of debt (“Supported Debt” as defined in the CRSA).
UGI International. UGI International’s total debt at September 30, 2013, includes $514.0 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan, $52 million under Flaga’s U.S. dollar-denominated term loan and a combined $81.8 million (€60.5 million) outstanding under Flaga’s euro-denominated term loans. Total UGI International debt outstanding at September 30, 2013, also includes (1) combined borrowings of $6.5 million (€4.8 million) outstanding under Flaga’s working capital facilities and (2) $6.6 million (€4.8 million) of other long-term debt.
Antargaz. Antargaz has a variable-rate term loan agreement with a consortium of banks (“Senior Facilities Agreement”). The Senior Facilities Agreement consists of (1) a €380 million variable-rate term loan and (2) a €40 million credit facility. Scheduled maturities under the term loan are €38 million due May 2014, €34.2 million due May 2015, and €307.8 million due March 2016. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of approximately 3.71% through the date of the term loan’s final maturity in March 2016. At September 30, 2013, the effective interest rate on Antargaz’ term loan was 4.41%.
Flaga. In order to finance the purchase of BP’s LPG distribution business in Poland in September 2013, Flaga entered into a $52 million U.S. dollar-denominated three-year loan that expires in September 2016. The $52 million loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin. Flaga has effectively fixed the euribor component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the $52 million loan, by entering into a cross-currency swap arrangement with a bank. At September 30, 2013, the effective interest rate on the $52 million loan was 1.82%.
Flaga also has a €40 million ($54.1 million) euro-based term loan of which €26.7 million matures in August 2016 and €13.3 million matures in September 2016, and a €19.1 million ($25.8 million) euro-based variable rate term loan that matures in October 2016. The €40 million term loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin and the €19.1 million term loan bears interest at three-month euribor rates plus a margin. Flaga has effectively fixed the euribor components of the interest rates on these term loans through the dates of their expiration by entering into interest rate swap agreements. At September 30, 2013, the effective interest rates on the €40 million and €19.1 million term loans were 4.68% and 3.85%, respectively.
At September 30, 2013, Flaga also had a euro-based variable-rate term loan which had outstanding principal balances of €1.4 ($1.9) with a final maturity in June 2014. This term loan bears interest at three-month euribor rates plus a margin. As of September 30, 2013, the effective interest rate on this term loan was 5.04%.
UGI Utilities. UGI Utilities’ total debt at September 30, 2013, includes long-term debt comprising $275.0 million of Senior Notes, $192.0 million of Medium-Term Notes, $175 million outstanding under UGI Utilities Term Loan Credit Agreement and $17.5 million of bank loan borrowings.
In September 2013, UGI Utilities entered into a 364-day term loan credit agreement (“UGI Utilities Term Loan Credit Agreement”) with a bank comprising a $175 million unsecured term loan facility. The UGI Utilities Term Loan Credit Agreement bears interest at the eurodollar rate for the interest period selected, plus a margin of 0.60%. The UGI Utilities Term Loan Credit Agreement terminates on September 22, 2014, but UGI Utilities may prepay the loan in whole or in part, without penalty. UGI Utilities borrowed $175 million on September 30, 2013, under the UGI Utilities Term Loan Credit Agreement which cash proceeds were used to repay UGI Utilities’ $108 million 6.375% Senior Notes due September 30, 2013, and for other general corporate purposes. On October 30, 2013, UGI Utilities entered into a Note Purchase Agreement which provides for the private placement of $175 million aggregate principal amount of 4.98% Senior Notes due March 26, 2044. UGI Utilities expects to use $175 million of borrowings under the Note Purchase Agreement, anticipated to occur in March 2014, to repay amounts outstanding under the UGI Utilities Term Loan Credit Agreement.
Credit Facilities
Due to the seasonal nature of the Company’s businesses, operating cash flows are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest. AmeriGas Propane and UGI Utilities primarily use their credit facilities to satisfy their seasonal operating cash flow needs. Energy Services historically has used its Receivables Facility to satisfy its operating cash flow needs. Energy Services also has a $240 million credit facility which it can use for working capital and general corporate purposes. Flaga principally uses borrowings
under its credit agreements to satisfy its operating cash flow needs. During Fiscal 2013, Fiscal 2012 and Fiscal 2011, Antargaz generally funded its operating cash flow needs without using its revolving credit facilities and AvantiGas has satisfied its operating cash flow needs from cash on hand. Borrowings under the credit facilities and under the Energy Services Receivables Facility are classified as bank loans on the Consolidated Balance Sheets.
AmeriGas Partners. AmeriGas OLP has a $525 million unsecured credit agreement (“AmeriGas Credit Agreement”) that expires on October 15, 2016. During Fiscal 2012, the AmeriGas Credit Agreement was amended to, among other things, increase the total amount available to $525 million from $325 million previously, extend its expiration date to October 2016, and amend certain financial covenants as a result of the acquisition of Heritage Propane.
UGI International. Under its Senior Facilities Agreement, Antargaz has a €40 million credit facility that expires in March 2016. Flaga has two principal working capital facilities (the “Flaga Credit Agreements”) comprising (1) a €46 million multi-currency working capital facility that includes an uncommitted €6 million overdraft facility (the “Flaga Multi-Currency Working Capital Facility”) and (2) a euro-denominated working capital facility that provides for borrowings and issuances of guarantees totaling €12 million (the “Euro Facility”). Both the Flaga Multi-Currency Working Capital Facility and the Euro Facility expire in September 2014.
UGI Utilities. UGI Utilities has a revolving credit agreement (the “UGI Utilities Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit) which expires in October 2015.
Energy Services. At September 30, 2013, Energy Services had an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $240 million (including a $50 million sublimit for letters of credit) which expires in June 2016. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries and to fund dividend payments provided that, after giving effect to such dividend payments, Energy Services maintains a specified ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement.
Information about the Company’s principal credit agreements (excluding the Energy Services Receivables Facility discussed below) as of September 30, 2013 and 2012, is presented in the table below. There were no borrowings under Antargaz’ credit facility during Fiscal 2013 and Fiscal 2012.
The average daily and peak bank loan borrowings under the Company’s principal credit agreements during Fiscal 2013 and 2012 are as follows:
At September 30, 2013, Energy Services had a $100 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper. In October 2013, Energy Services extended its Receivables Facility until October 31, 2014 and amended the Receivables Facility to better align its borrowing limits with Energy Services’ seasonal borrowing needs. The Receivables Facility, as amended, provides Energy Services with the ability to borrow up to $150 million of eligible receivables during the period November 1, 2013 to May 31, 2014, and up to $75 million of eligible receivables during the period June 1, 2014 to October 31, 2014. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a commercial paper conduit of a major bank (through September 30, 2013) and, subsequent to September 30, 2013, to the bank itself. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the commercial paper conduit or the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit or the bank. The Company records interest expense on amounts owed to the commercial paper conduit or the bank.
At September 30, 2013, the outstanding balance of ESFC trade receivables was $55.0 million and there was $30.0 million that was sold to the commercial paper conduit and reflected as bank loans on the Consolidated Balance Sheets. At September 30, 2012, the outstanding balance of ESFC trade receivables was $43.5 million of which no amount was sold to the commercial paper conduit. During Fiscal 2013 and Fiscal 2012, peak sales of receivables were $46.5 million and $51.5 million, respectively, and average daily amounts sold were $10.4 million and $15.6 million, respectively.
Cash Flows
Operating Activities. Year-to-year variations in cash flow from operations can be significantly affected by changes in operating working capital especially during periods of significant changes in energy commodity prices.
Cash flow provided by operating activities was $801.5 million in Fiscal 2013, $707.7 million in Fiscal 2012 and $554.7 million in Fiscal 2011. Cash flow from operating activities before changes in operating working capital was $845.6 million in Fiscal 2013, $629.0 million in Fiscal 2012 and $697.6 million in Fiscal 2011. The increase in cash flow from operating activities before changes in operating working capital in Fiscal 2013 compared to Fiscal 2012 largely reflects the effects of the higher operating results. Changes in operating working capital provided (used) operating cash flow of $(44.1) million in Fiscal 2013, $78.7 million in Fiscal 2012 and $(142.9) million in Fiscal 2011. The cash required to fund changes in operating working capital in Fiscal 2013 reflects, among other things, greater cash needed to fund operating working capital associated with the increased Fiscal 2013 sales while cash provided by changes in operating working capital in the prior-year period benefited from the timing of the acquisition of Heritage Propane on cash receipts from Heritage Propane customers. This greater use of cash in the current-year period was partially offset by, among other things, the timing and amount of cash payments associated with accounts payable including the impact of lower LPG product costs.
Investing Activities. Investing activity cash flow is principally affected by expenditures for property, plant and equipment; cash paid for acquisitions of businesses; changes in restricted cash balances and proceeds from sales of assets. Net cash flow used by investing activities was $553.3 million in Fiscal 2013, $1,904.5 million in Fiscal 2012 and $415.4 million in Fiscal 2011. Cash paid for acquisitions in Fiscal 2013 largely includes Flaga’s acquisition of BP’s LPG distribution business in Poland; Midstream & Marketing’s acquisition of a non-operating working interest in natural gas acreage in the Marcellus Shale region of Pennsylvania; and several Partnership acquisitions. Cash paid for acquisitions in Fiscal 2012 principally reflects the January 2012 acquisition of Heritage Propane and the October 2011 acquisition of certain of Shell’s European LPG businesses. Cash expenditures for property, plant and equipment totaled $486.0 million in Fiscal 2013, $339.4 million in Fiscal 2012 and $360.7 million in Fiscal
2011. Cash from changes in restricted cash in futures brokerage accounts provided (used) cash of $(5.3) million in Fiscal 2013, $14.2 million in Fiscal 2012 and $17.6 million in Fiscal 2011. The amount of restricted cash required in such accounts is generally the result of changes in underlying commodity prices.
Financing Activities. Cash flow provided (used) by financing activities was $(186.1) million in Fiscal 2013, $1,278.5 million in Fiscal 2012 and $(152.1) million in Fiscal 2011. Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; net bank loan borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units; and issuances of UGI and AmeriGas Partners equity instruments.
Distributions on AmeriGas Partners’ publicly held Common Units in Fiscal 2013 increased over the prior-year period reflecting the full-year impact of a greater number of Common Units outstanding subsequent to the acquisition of Heritage Propane and higher quarterly per-unit distribution rates. In order to finance the cash portion of the acquisition of Heritage Propane, on January 12, 2012, AmeriGas Partners issued $550 million principal amount of 6.75% Notes due 2020 and $1.0 billion principal amount of 7.00% Notes due 2022. During March 2012, AmeriGas Partners sold 7 million Common Units in an underwritten public offering and used a portion of the net proceeds to repay $200 million of outstanding 6.50% Senior Notes due May 2021, to reduce bank loan borrowings and for general corporate purposes.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions but include capital leases) by our business segments for Fiscal 2013, Fiscal 2012 and Fiscal 2011. We also provide amounts we expect to spend in Fiscal 2014. We expect to finance Fiscal 2014 capital expenditures principally from cash generated by operations, borrowings under credit facilities and cash on hand.
Midstream & Marketing’s capital expenditures in Fiscal 2013, Fiscal 2012 and Fiscal 2011 principally reflect capital expenditures related to natural gas storage, electric generation and Marcellus Shale projects. These Midstream & Marketing capital expenditures were financed in large part by capital contributions from UGI and cash from operations. AmeriGas Propane Fiscal 2013 and Fiscal 2012 capital expenditures include $20.4 million and $17.6 million, respectively, related to Heritage Propane integration activities. The increase in Gas Utility capital expenditures in Fiscal 2013 includes greater main replacement and system improvement capital expenditures.
Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2013. 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 financial instruments. The following table presents contractual cash obligations with non-affiliates under agreements existing as of September 30, 2013:
(a)
Based upon stated maturity dates. UGI Utilities’ $175 million Term Loan Credit Agreement borrowings anticipated to be refinanced on a long-term basis in March 2014 are presented in the table above under “Thereafter.”
(b)
Based upon stated interest rates adjusted for the effects of interest rate swaps.
(c)
Represents the sum of amounts due from us if derivative financial instrument liabilities were settled at the September 30, 2013, amounts reflected in the Consolidated Balance Sheet (but excluding amounts associated with interest rate swaps).
(d)
Includes material capital expenditure obligations.
Other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2013, principally comprise refundable tank and cylinder deposits (as further described in Note 2 to Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”); litigation, property and casualty liabilities and obligations under environmental remediation agreements (see Note 16 to Consolidated Financial Statements); pension and other postretirement benefit liabilities recorded in accordance with accounting guidance relating to employee retirement plans (see Note 8 to Consolidated Financial Statements); and liabilities associated with executive compensation plans (see Note 14 to Consolidated Financial Statements). These liabilities are not included in the table of Contractual Cash Obligations and Commitments because they are estimates of future payments and not contractually fixed as to timing or amount. We believe we will be required to make contributions to UGI Utilities’ pension plan (as further described below under “U.S. Pension Plan”) in Fiscal 2014 of approximately $18 million. Contributions to the U.S. Pension Plan in years beyond Fiscal 2014 will depend in large part on the impact of future returns and interest rates on pension plan assets. Certain of our operating lease arrangements, primarily vehicle leases with remaining lease terms of one to ten years, have residual value guarantees. Although such fair values at the end of the leases have historically exceeded the guaranteed amount, at September 30, 2013, the maximum potential amount of future payments under lease guarantees assuming the leased equipment was deemed worthless was approximately $14.0 million.
Significant Acquisitions
In September 2013, Flaga acquired the LPG distribution business of BP in Poland for total cash consideration of approximately $36 million, subject to working capital adjustments. Also during Fiscal 2013, Energy Services acquired a non-operating working interest in natural gas acreage in the Marcellus Shale region of Pennsylvania for approximately $23 million in cash and AmeriGas OLP acquired two domestic retail propane distribution businesses for approximately $20 million in cash.
On January 12, 2012 (the “Acquisition Date”), AmeriGas Partners completed the acquisition of Heritage Propane for total consideration of approximately $2.6 billion comprising $1.5 billion in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of approximately $1.1 billion. The acquisition of Heritage Propane was consummated pursuant to the Contribution Agreement by and among AmeriGas Partners, ETP, Energy Transfer Partners GP, L.P., the general partner of ETP, and Heritage ETC, L.P. (“Contribution Agreement”). The acquired business conducts its propane operations in 41 states. According to LP-Gas Magazine rankings published on February 1, 2012, Heritage Propane was the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers in 2011. The acquisition of Heritage Propane is consistent with our growth strategies, one of which is to grow our core business through acquisitions. The results of operations of Heritage Propane are included in the Consolidated Statements of Income since the Acquisition Date.
In October 2011, we acquired Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden for €133.6 million ($179.0 million) in cash.
For additional information on these acquisitions, see Note 5 to Consolidated Financial Statements.
U.S. Pension Plan
In the U.S., we currently sponsor one 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 value of the U.S. Pension Plan’s assets totaled $398.2 million and $351.5 million at September 30, 2013 and 2012, respectively. At September 30, 2013 and 2012, 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 $88.3 million and $192.1 million, respectively.
We believe we are in compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations. We anticipate that we will be required to make contributions to the U.S. Pension Plan during Fiscal 2014 of approximately $18 million. Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2013 was $19.9 million. Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2014 is expected to be approximately $11 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. Through September 30, 2013, we have recorded cumulative after-tax charges to UGI Corporation’s stockholders’ equity of $17.1 million and recorded regulatory assets totaling $94.5 million in order to reflect the funded status of our pension and other postretirement benefit plans. For a more detailed discussion of the U.S. Pension Plan and our other postretirement benefit plans, see Note 8 to Consolidated Financial Statements.
Related Party Transactions
During Fiscal 2013, Fiscal 2012 and Fiscal 2011, 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 Matters
On February 19, 2013, the PUC entered a final order (the “Final Order”) settling all regulatory compliance issues pertaining to a natural gas explosion on February 9, 2011, in Allentown, PA. The Final Order requires UGI Utilities to (i) pay a civil penalty in the amount of $0.5 million; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities’ consolidated financial position, results of operations or cash flows.
On August 11, 2011, the PUC approved a settlement agreement with CPG that resulted in an increase in annual base rate revenues of $8.0 million as well as $0.9 million in revenues per year to fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). The increase became effective August 30, 2011. During Fiscal 2012, the PUC reversed its earlier decision related to the $0.9 million increase in revenues associated with the Energy and Efficiency Conservation Program and required CPG to refund revenue it had collected for that program.
On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11-mile natural gas pipeline, related facilities and right of way located in Delmar Township, Pennsylvania (“TL-96 line”) to Energy Services. The PUC approved the transfer and, in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy
Services. The net book value of the TL-96 line is approximately $2.6 million.
On October 21, 2010, FERC approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011, the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9 million. Compliance with the provisions of the PUC Order approving the transfer of the storage assets did not have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.
On December 1, 2010, PNG filed an application with the PUC for expedited review and approval of the transfer of a 9 mile natural gas pipeline, related facilities, and right of way located in Mehoopany, Pennsylvania (the “Auburn Line”) to Energy Services. The PUC approved the transfer and in September 2011 the Auburn Line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the Auburn Line was $1.1 million.
UGI Utilities Income Taxes
In 2010, U.S. federal tax legislation was enacted that allowed taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of calendar 2011, when such property was placed in service before 2012. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers are also permitted to fully deduct such qualifying capital expenditures for Pennsylvania state corporate net income tax purposes. Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits from accelerated tax depreciation. UGI Utilities’ Fiscal 2011 and, to a lesser extent, Fiscal 2012 state tax rates reflect the beneficial effects of this greater state tax depreciation.
Manufactured Gas Plants
UGI Utilities
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA is currently scheduled to terminate at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At September 30, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14.0 million and $15.0 million, respectively. Because CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites, in accordance with GAAP related to rate-regulated entities we have recorded associated regulatory assets in equal amounts.
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At September 30, 2013, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.
From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.
For additional information on an MGP site outside of Pennsylvania currently subject to a third-party claim, see Note 16 to Consolidated Financial Statements.
AmeriGas Propane
By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac Lake, New York, on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by DEC disclosed contamination related to former MGP operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership has researched the history of the site and its ownership interest in the site and reviewed the preliminary site characterization study prepared by the DEC, the extent of contamination and the possible existence of other potentially responsible parties. The Partnership communicated the results of its research to DEC in January 2009. There have been no recent developments in this matter. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.
In connection with the acquisition of Heritage Propane on January 12, 2012, a predecessor of Titan Propane LLC (“Titan LLC”), a former subsidiary acquired in the acquisition of Heritage Propane, is purportedly the beneficial holder of title with respect to two former MGPs discussed below. The Contribution Agreement provides for indemnification from ETP for certain expenses associated with remediation of these sites. By letter dated September 30, 2010, the EPA notified Titan LLC that it may be a potentially responsible party (“PRP”) for cleanup costs associated with contamination at a former MGP in Claremont, New Hampshire. In June 2010, the Maryland Attorney General (“MAG”) identified Titan LLC as a PRP in connection with contamination at a former MGP in Chestertown, Maryland and requested that Titan LLC participate in characterization and remediation activities. Titan LLC has supplied the EPA and MAG with corporate and bankruptcy information for its predecessors to support its claim that it is not liable for any remediation costs at the sites. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.
We cannot predict with certainty the final results of any of the MGP matters referenced above. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows.
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 International Propane operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for propane 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 International Propane may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements and over-the-counter derivative commodity instruments including price swap and option contracts. Our UGI International LPG operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. Over-the-counter derivative commodity instruments used to hedge forecasted purchases of propane are generally settled at expiration of the contract. In addition, Antargaz hedges a portion of its future U.S. dollar denominated LPG product purchases through the use of forward foreign exchange contracts as further described below.
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the NYMEX to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism.
Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations.
In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income.
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, IntercontinentalExchange and over-the-counter natural gas and electricity futures and natural gas basis swap contracts or enters into fixed-price supply arrangements. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge a portion of its anticipated sales of electricity from its electricity generation facilities. Although Midstream & Marketing’s fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas or electricity would adversely impact Midstream & Marketing’s results. In order to reduce this risk of supplier nonperformance, Midstream & Marketing has diversified its purchases across a number of suppliers. Midstream & Marketing has entered into and may continue to enter into fixed-price propane sales agreements. In order to manage the market price risk relating to substantially all of its fixed-price propane sales agreements, Midstream & Marketing enters into price swap and option contracts.
Midstream & Marketing purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. Midstream & Marketing from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Midstream & Marketing also uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Although Midstream & Marketing’s FTRs and NYISO capacity swap contracts, and NYMEX futures contracts associated with the purchase and later anticipated sale of natural gas and propane, are generally effective as economic hedges, they do not currently qualify for hedge accounting treatment.
UGID 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, UGID 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 UGID’s results.
Interest Rate Risk
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact their fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt includes bank loan borrowings and Antargaz’ and Flaga’s variable-rate term loans. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz and Flaga have effectively fixed the underlying euribor interest rates on their euro-denominated term loans through their scheduled maturity dates through the use of interest rate swaps. In addition, Flaga’s $52 million U.S. dollar-denominated loan has been swapped from fixed-rate U.S. dollars to fixed-rate euro currency at issuance through cross currency swaps, removing interest rate risk and foreign currency exchange risk associated with the underlying interest and principal payments. At September 30, 2013, combined borrowings outstanding under variable-rate debt agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate term loans and Flaga’s U.S. dollar-denominated loan, totaled $227.9 million. Based upon average borrowings outstanding under variable-rate borrowings (excluding Antargaz’ 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 2013 and Fiscal 2012 interest expense by approximately $1.8 million and $2.8 million, respectively. The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of $170.3 million and $160.1 million at September 30, 2013 and 2012, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $102.2 million and $137.0 million at September 30, 2013 and 2012, respectively.
Long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce interest rate risk associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). There were no unsettled IRPAs at September 30, 2013.
Foreign Currency Exchange Rate Risk
Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. From time to time we use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Gains or losses on net investment hedges remain in accumulated other comprehensive income until such foreign operations are liquidated. At September 30, 2013, there were no unsettled net investment hedges outstanding. With respect to our net investments in our International Propane operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value at September 30, 2013, by approximately $94 million, which amount would be reflected in other comprehensive income.
In addition, in order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases during the months of October through March through the use of forward foreign exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% - 30% of estimated dollar-denominated purchases to occur during the heating-season months of October to March.
Derivative Financial Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial 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.
Certain of our 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 natural gas and electricity exchange-traded futures and option contracts generally require cash deposits in margin accounts. Declines in natural gas, LPG and electricity product costs can require our business units to post collateral with counterparties or make margin deposits to brokerage accounts. At September 30, 2013 and 2012, restricted cash in brokerage accounts totaled $7.0 million and $3.0 million, respectively.
The following table summarizes the fair values of unsettled market risk sensitive derivative instruments assets (liabilities) held at September 30, 2013 and 2012. The table also includes the changes in fair values of derivative instruments that
would result if there were a 10% adverse change in (1) the market prices of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges; (2) the three-month and one-month Euribor rates; and (3) the value of the euro versus the U.S. dollar. Gas Utility’s and Electric Utility’s derivative instruments other than gasoline futures and swap contracts are excluded from the table below because any associated net gains or losses are refundable to or recoverable from customers in accordance with Gas Utility and Electric Utility ratemaking.
Because a significant portion of our derivative instruments qualify as hedges under GAAP, we expect that changes in the fair value of derivative instruments used to manage commodity, currency or interest rate market risk would be substantially offset by gains or losses on the associated anticipated transactions.
Critical Accounting Policies and Estimates
Accounting policies and estimates discussed in this section are those that we consider to be the most critical to an understanding of our financial statements because they involve significant judgments and uncertainties. Changes in these policies and estimates could have a material effect on the financial statements. The application of these accounting policies and estimates necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements. Management has reviewed these critical accounting policies, and the estimates and assumptions associated with them, with the Company’s Audit Committee. In addition, management has reviewed the following disclosures regarding the application of these critical accounting policies and estimates with the Audit Committee. Also, see Note 2 to Consolidated Financial Statements which discusses the significant accounting policies that we have selected from acceptable alternatives.
Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation regarding pending claims and legal actions that arise in the normal course of business. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere, and PNG and CPG owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with GAAP, when a loss is considered probable and reasonably estimable, we record a liability in the amount of our best estimate for the ultimate loss. When there is a range of possible loss with equal likelihood, liabilities recorded are based upon the low end of such range. The likelihood of a loss with respect to a particular contingency is often difficult to predict and determining a reasonable estimate of the loss or a range of possible loss may not be practicable based upon the information available and the potential effects of future events and decisions by third parties that will determine the ultimate resolution of the contingency. Reasonable estimates involve management judgments based on a broad range of information and prior experience. These judgments are reviewed quarterly as more information is received and the amounts reserved are updated as necessary. Such estimated reserves may differ materially from the actual liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted.
Accounting For Derivative Instruments At Fair Value. The Company enters into derivative instruments to 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. Changes in the fair values of derivative instruments that qualify and are designated as cash flow hedges are recorded in 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, hedges under GAAP, which currently comprise substantially all of Midstream & Marketing’s commodity derivative instruments, are recognized in earnings on the Consolidated Statements of Income. The fair values of our derivative instruments are determined based upon actively-quoted market prices for identical assets and liabilities, indicative price quotations available through brokers, industry
price publications or recent market transactions and related market indicators. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Gains and losses associated with derivatives utilized by UGI Utilities to manage the price risk inherent in its natural gas purchasing and electricity activities are recoverable through PGC or Electric Utility default service mechanisms, subject to PUC approval. Accordingly, the offset to the change in fair value of these derivatives is recorded as either a regulatory asset or liability on the Consolidated Balance Sheets. At September 30, 2013, our total net derivative liabilities totaled $31.2 million.
Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation by the PUC. In accordance with accounting guidance associated with rate-regulated entities, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2013, our regulatory assets totaled $244.9 million. See Notes 2 and 9 to Consolidated Financial Statements.
Depreciation and Amortization of Long-Lived Assets. We compute depreciation on utility property, plant and equipment on a straight-line basis over the average remaining lives of its various classes of depreciable property and on our non-utility property, plant and equipment on a straight-line basis over estimated useful lives generally ranging from 2 to 40 years. We also use amortization methods and determine asset values of intangible assets subject to amortization using reasonable assumptions and projections. Changes in the estimated useful lives of property, plant and equipment and changes in intangible asset amortization methods or values could have a material effect on our results of operations. As of September 30, 2013, our net property, plant and equipment totaled $4,480.2 million and we recorded depreciation expense of $301.4 million during Fiscal 2013. As of September 30, 2013, our net intangible assets subject to amortization totaled $477.7 million and we recorded amortization expense on intangible assets subject to amortization of $52.8 million during Fiscal 2013.
Purchase Price Allocations. From time to time, the Company enters into material business combinations. In accordance with accounting guidance associated with business combinations, the purchase price is allocated to the various assets acquired and liabilities assumed at their estimated fair value. Fair values of assets acquired and liabilities assumed are based upon available information and we may involve an independent third party to perform appraisals. Estimating fair values can be complex and subject to significant business judgment and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, if necessary, up to one year from the acquisition date to finalize the purchase price allocation.
Impairment of Goodwill. We 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 if they have similar economic characteristics. Certain of the Company’s operating segments have goodwill resulting from purchase business combinations. In accordance with GAAP, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. For certain of our reporting units, 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, and for those reporting units for which we are not able, based upon the assessment of qualitative factors, to determine that it is more likely than not that the fair value of such reporting unit is not less than its carrying amount, we determine fair values generally using an income approach unless market values are available. For purposes of the income approach, fair values are determined based upon the present value of estimated future cash flows discounted at an appropriate risk-adjusted rate. Cash flow estimates used to establish fair values involve management judgments based on a broad range of information and historical results. We use our internal forecasts to estimate future cash flows and include an estimate of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value and the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill which would adversely impact our results of operations. As of September 30, 2013, our goodwill totaled $2,873.7 million. We did not record any impairments of goodwill in Fiscal 2013, Fiscal 2012 or Fiscal 2011.
Pension Plan Assumptions. Pension plan assumptions are significant inputs to the actuarial models that measure pension benefit obligations and pension expense. The cost of providing benefits under the U.S. Pension Plan is dependent on historical information such as employee age, length of service, level of compensation and the actual rate of return on plan assets. In addition, certain assumptions relating to the future are used to determine pension expense including the discount rate applied to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase, among others. Assets of the U.S. Pension Plan are held in trust and consist principally of equity and fixed income mutual funds. Changes in plan assumptions as well as fluctuations
in actual equity or fixed income market returns could have a material impact on future pension costs. We believe the two most critical assumptions are (1) the expected rate of return on plan assets and (2) the discount rate. A decrease in the expected rate of return on U.S. Pension Plan assets of 50 basis points to a rate of 7.25% would result in an increase in pre-tax pension cost of approximately $1.9 million in Fiscal 2014. A decrease in the discount rate of 50 basis points to a rate of 4.70% would result in an increase in pre-tax pension cost of approximately $3.1 million in Fiscal 2014.
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, 2013, our net deferred tax liabilities totaled $967.4 million.
Recently Issued Accounting Pronouncements
See Note 4 to 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 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 defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended), 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, because of the material weakness in internal control over financial reporting identified in “Management’s Annual Report on Internal Control over Financial Reporting” (see Item 8 of this Report), the Company’s disclosure controls and procedures were not effective as of September 30, 2013.
Remediation Plans
Management and the Board of Directors are committed to the remediation of the material weakness related to the accounting for commodity derivative instruments described in Item 8 of this Report. Subsequent to the end of the Company’s fiscal year ended September 30, 2013 the Company has taken or will take the following actions designed to remediate the material weakness: 1) supplement the Company’s existing technical expertise necessary to evaluate the accounting for commodity derivatives, 2) enhance controls over the assessment of new commodity derivative agreements to ensure the appropriate accounting is identified at the inception of the agreement, and 3) enhance controls over commodity derivative agreements to ensure that any ongoing compliance requirements are appropriately monitored. Management expects to remediate the material weakness during fiscal 2014. In addition, management has discontinued the use of hedge accounting for commodity derivative instruments at Midstream and Marketing and will report mark-to-market adjustments on unsettled derivatives.
(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, 2013.
Information
Captions of Proxy Statement
Incorporated by Reference
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
Election of Directors - Nominees; Corporate Governance; Board Independence; Board Committees; Communications with the Board; Securities Ownership of Management - 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
Securities Ownership of Certain Beneficial Owners; Securities Ownership of Management
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Election of Directors - Board Independence and Board Committees; 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 2013 with respect to compensation plans under which our equity securities are authorized for issuance.
(1)
Represents 6,795,968 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 187,543 securities remaining for future issuance of stock options from the 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 and 13,449,649 of securities for issuance from the UGI Corporation 2013 Omnibus Incentive Compensation Plan. The UGI Corporation 2013 Omnibus Incentive Compensation Plan was approved by shareholders on January 24, 2013.
(3)
Represents 920,601 phantom share units under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 and the UGI Corporation 2013 Omnibus Incentive Compensation Plan.
(4)
Weighted-average exercise price of outstanding options; excludes phantom share units.
The information concerning the Company’s executive officers required by Item 10 is set forth below.
EXECUTIVE OFFICERS
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 Vice Chairman of AmeriGas Propane, Inc. (since 2005) and UGI Utilities, Inc. (since 2005). Previously, he also served as Chief Operating Officer of UGI Corporation (2005 to 2013) and as President and Chief Executive Officer of UGI Utilities, Inc. (2009 to 2011). Mr. Walsh was the Chief Executive of the Industrial and Special Products Division of the BOC Group plc, an industrial gases company, a position he assumed in 2001. He was also an Executive Director of BOC (2001 to 2005). He joined BOC in 1986 as Vice President-Special Gases and held various senior management positions in BOC, including President of Process Gas Solutions, North America (2000 to 2001) and President of BOC Process Plants (1996 to 2000). Mr. Walsh also serves as a Director of UGI Utilities, Inc. and AmeriGas Propane, Inc.
Kirk R. Oliver
Mr. Oliver is Chief Financial Officer of UGI (since October 2012). From December 2011 until September 2012, Mr. Oliver served as Senior Managing Director & Chief Operating Officer of InfraREIT Capital Partners, LLC, a partnership that invests in infrastructure assets, primarily electric transmission and gas pipeline assets. Prior to joining InfraREIT Capital, Mr. Oliver served as Senior Vice President and Chief Financial Officer of Allegheny Energy, Inc., an electric utility company, from 2008 to 2011, and as a Senior Executive at Hunt Power, LLC, a company that develops and invests in electric and gas utility projects, from 2007 to 2008. Mr. Oliver served in various positions at TXU Corp. (now Energy Future Holdings Corp.), an electricity distribution, generation and transmission company in Texas, from 1998 to 2006, including as Executive Vice President and Chief Financial Officer from 2004 to 2006, Senior Vice President, Finance from 2000 to 2003 and Vice President, Treasurer and Assistant Secretary from 1998 to 1999. Prior to joining TXU Corp., Mr. Oliver spent eleven years as an investment banker in the Global Power and Energy Group at Lehman Brothers and six years at Motorola Inc.
Davinder S. Athwal
Mr. Athwal is Vice President - Accounting and Financial Control and Chief Risk Officer (since January 2009). He previously served as the Global Mergers & Acquisitions Controller of Nortel Networks, Inc., a global supplier of telecommunications equipment and solutions from 2007 through 2008. Mr. Athwal served as Director, Global Revenue Governance for Nortel Networks, Inc. from 2006 through 2007. Mr. Athwal previously served in both accounting and risk management roles for IBM Corporation, a globally integrated innovation and technology company (2003 to 2006).
Jerry E. Sheridan
Mr. Sheridan is President, Chief Executive Officer and a Director of AmeriGas Propane, Inc. (since March 2012). Previously, he served as Vice President - Operations and Chief Operating Officer (2011 to 2012) and as Vice President - Finance and Chief Financial Officer (2005 to 2011) of AmeriGas Propane, Inc. Mr. Sheridan served as President and Chief Executive Officer (2003 to 2005) of Potters Industries, Inc., a global manufacturer of engineered glass materials and a wholly-owned subsidiary of PQ Corporation, a global producer of inorganic specialty chemicals. In addition, Mr. Sheridan served as Executive Vice President (2003 to 2005) and as Vice President and Chief Financial Officer (1999 to 2003) of PQ Corporation. Mr. Sheridan also serves on the Management Board of CP Kelco, a privately held company that provides innovative products and solutions through the use of nature-based chemistry.
Robert F. Beard
Mr. Beard is President and Chief Executive Officer of UGI Utilities, Inc. (since September 2011). He previously served as Vice President - Marketing, Rates and Gas Supply (2010 to 2011) and Vice President - Southern Region (2008 to 2010) of UGI Utilities, Inc. From 2006 until 2008, Mr. Beard served as Vice President - Operations and Engineering of PPL Gas Utilities Corporation and, from 2002 until 2006, he served as Director - Operations and Engineering of PPL Gas Utilities Corporation.
Monica M. Gaudiosi
Ms. Gaudiosi is Vice President, General Counsel and Secretary (since April 2012). She also serves as Vice President and Secretary of AmeriGas Propane, Inc. and UGI Utilities, Inc. (since April 2012). Prior to joining UGI, 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).
Bradley C. Hall
Mr. Hall is Vice President - New Business Development (since October 1994). He also serves as President of UGI Enterprises, Inc. (since 1994) and UGI Energy Services, LLC (formerly known as UGI Energy Services, Inc.) (since 1995). He joined the Company in 1982 and held various positions in UGI Utilities, Inc., including Vice President - Marketing and Rates.
PART IV:
ITEM 15.
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
Consolidated Balance Sheets as of September 30, 2013 and 2012
Consolidated Statements of Income for the years ended September 30, 2013, 2012 and 2011
Consolidated Statements of Comprehensive Income for the years ended September 30, 2013, 2012 and 2011
Consolidated Statements of Cash Flows for the years ended September 30, 2013, 2012 and 2011
Consolidated Statements of Changes in Equity for the years ended September 30, 2013, 2012 and 2011
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, 2013, 2012 and 2011
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.
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 December 16, 2013, by the following persons on behalf of the Registrant in the capacities indicated.
Signature
Title
/s/ John L. Walsh
Chief Executive Officer
(Principal Executive Officer) and Director
John L. Walsh
/s/ Kirk R. Oliver
Chief Financial Officer (Principal Financial Officer)
Kirk R. Oliver
/s/ Davinder S. Athwal
Vice President - Accounting and Financial Control,
Chief Risk Officer (Principal Accounting Officer)
Davinder S. Athwal
/s/ Lon R. Greenberg
Chairman and Director
Lon R. Greenberg
/s/ Richard W. Gochnauer
Director
Richard W. Gochnauer
/s/ Frank S. Hermance
Director
Frank S. Hermance
/s/ Ernest E. Jones
Director
Ernest E. Jones
/s/ Anne Pol
Director
Anne Pol
/s/ M. Shawn Puccio
Director
M. Shawn Puccio
/s/ Marvin O. Schlanger
Director
Marvin O. Schlanger
/s/ Roger B. Vincent
Director
Roger B. Vincent
UGI CORPORATION AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2013
UGI CORPORATION
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.
Report of Management
Financial Statements
The Company’s consolidated financial statements and other financial information contained in this Annual Report are 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 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, none of whom is an employee of the Company. This Committee is responsible for (i) overseeing the financial reporting process and the adequacy of internal control and (ii) monitoring the independence and performance of the Company’s independent registered public accounting firm and internal auditors. The Committee is also responsible for maintaining direct channels of communication among the Board of Directors, management, and both the independent registered public accounting firm and the internal auditors.
PricewaterhouseCoopers LLP, our independent registered public accounting firm, is engaged to perform audits of our consolidated financial statements. These audits are performed in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our independent registered public accounting firm was given unrestricted access to all financial records and related data, including minutes of all meetings of the Board of Directors and committees of the Board. The Company believes that all representations made to the independent registered public accounting firm during their audits were valid and appropriate.
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, using the criteria in Internal Control - Integrated Framework (1992), issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”).
Internal control over financial reporting refers to the process, designed under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, and effected by the Company’s Board of Directors, to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and includes policies and procedures that, among other things, provide reasonable assurance that assets are safeguarded and that transactions are executed in accordance with management’s authorization and are properly recorded to permit the preparation of reliable financial information.
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.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.
We did not maintain effective controls over our accounting for commodity derivative instruments. Specifically, controls were not designed effectively to provide reasonable assurance that commodity derivative instruments were accounted for in accordance with GAAP. The material weakness resulted in errors in the recording of certain commodity derivative transactions as cash flow hedges. As a result of the error, the Company misstated other comprehensive income, non-utility revenues and non-utility cost of sales, requiring the Company to restate its financial statements for the fiscal quarters ended March 31, 2013, June 30, 2012 and December 31, 2011 and revise its financial statements for the fiscal years ended September 30, 2012 and 2011 and the quarters ended June 30, 2013, December 31, 2012, and March 31, 2012. Additionally, this material weakness could result in misstatements of the aforementioned accounts and disclosures that would result in a material misstatement of the consolidated financial statements that would not be prevented or detected.
Because of this material weakness, management concluded that the Company did not maintain effective internal control over financial reporting as of September 30, 2013 based on criteria in the COSO Framework.
The Company’s independent registered public accounting firm, PricewaterhouseCoopers LLP, has issued its report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2013, which appears herein.
/s/ John L. Walsh
Chief Executive Officer
/s/ Kirk R. Oliver
Chief Financial Officer
/s/ Davinder S. Athwal
Chief Accounting Officer
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of UGI Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of changes in equity and of cash flows present fairly, in all material respects, the financial position of UGI Corporation and its subsidiaries at September 30, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15 (a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of September 30, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992) because a material weakness in internal control over financial reporting related to commodity derivative accounting existed as of that date. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the September 30, 2013 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in management’s report referred to above. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
December 16, 2013
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
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Index to Notes
Note 1 - Nature of Operations
Note 2 - Significant Accounting Policies
Note 3 - Revisions and Restatements of Consolidated Financial Statements
Note 4 - Accounting Changes
Note 5 - Acquisitions
Note 6 - Debt
Note 7 - Income Taxes
Note 8 - Employee Retirement Plans
Note 9 - Utility Regulatory Assets and Liabilities and Regulatory Matters
Note 10 - Inventories
Note 11 - Property, Plant and Equipment
Note 12 - Goodwill and Intangible Assets
Note 13 - Series Preferred Stock
Note 14 - Common Stock and Equity-Based Compensation
Note 15 - Partnership Distributions and Common Unit Offerings
Note 16 - Commitments and Contingencies
Note 17 - Fair Value Measurements
Note 18 - Disclosures About Derivative Instruments and Hedging Activities
Note 19 - Energy Services Accounts Receivable Securitization Facility
Note 20 - Other Income, Net
Note 21 - Quarterly Data (unaudited)
Note 22 - Segment Information
Note 1 - Nature of Operations
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; (3) own all or a portion of electricity generation facilities; (4) own and operate an energy marketing, midstream infrastructure, storage and energy services business; and (5) own and operate heating, ventilation, air conditioning and electrical contracting businesses. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”
We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”), a publicly traded limited partnership, its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”) and, prior to its merger with AmeriGas OLP on July 1, 2013, AmeriGas OLP’s principal operating subsidiary Heritage Operating, L.P. (“HOLP”). In addition, from January 12, 2012, through the date of its merger with and into AmeriGas OLP in August 2012, we also conducted business through AmeriGas OLP’s operating subsidiary, Titan Propane LLC (“Titan LLC”). HOLP and Titan LLC (collectively, “Heritage Propane”) were acquired on January 12, 2012, from Energy Transfer Partners, L.P. (“ETP”) (see Note 5 for additional information about the acquisition of Heritage Propane). AmeriGas OLP along with HOLP and Titan LLC (prior to their mergers with and into AmeriGas OLP) are referred to herein as the “Operating Partnership.” AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30, 2013, the General Partner held a 1% general partner interest and 25.3% limited partner interest in AmeriGas Partners, and held an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises 47,000,295 Common Units held by the public and 22,067,362 Common Units held by a subsidiary of ETP as a result of the acquisition of Heritage Propane.
Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“Antargaz”); (2) an LPG distribution business in central, northern
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
and eastern Europe (“Flaga”); (3) an LPG distribution business in the United Kingdom (“AvantiGas”); and (4) an LPG distribution business in the Nantong region of China. We refer to our foreign LPG operations collectively as “UGI International.”
Enterprises, through UGI Energy Services, LLC (which was formerly known as UGI Energy Services, Inc. prior to its merger with and into UGI Energy Services, LLC effective October 1, 2013) and its subsidiaries conduct an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic region of the United States. In addition, UGI Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. These businesses are referred to herein collectively as “Midstream & Marketing.” UGI Energy Services, LLC subsequent to the merger and UGI Energy Services, Inc. prior to the merger are referred to herein as “Energy Services.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries.
Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary, UGI Utilities, Inc. (“UGI Utilities”), and its subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”
Note 2 - 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. In addition, see Note 3 regarding the effects of revisions on previously issued financial statements.
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 general public’s and ETP’s interests in the Partnership, and outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests. We eliminate all significant intercompany accounts and transactions when we consolidate. Entities in which we do not have control but have significant influence over operating and financial policies are accounted for by the equity method. Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2013. Investments in business entities that are not publicly traded and in which we hold less than 20% of voting rights are accounted for using the cost method. Such investments are recorded in other assets and totaled $82.0 and $80.0 at September 30, 2013 and 2012, respectively (including $16.4 and $20.0, respectively, associated with our approximate 3.5% interest in a private equity partnership that invests in renewable energy companies). Undivided interests in natural gas production assets and an electricity generation facility are consolidated on a proportionate basis.
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980 related to regulated entities whose rates are designed to recover the costs of providing service. 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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulator.
For additional information regarding the effects of rate regulation on our utility operations, see Note 9.
Fair Value Measurements
We apply fair value measurements on a recurring basis to certain assets and liabilities, principally our commodity, foreign currency and interest rate derivative instruments. Assets that are not measured at fair value on a recurring basis but are subject to fair value measurements under certain circumstances principally comprise our cost and equity method investments and long-lived assets that are written down to fair value when they are impaired. 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 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. Fair value measurements require that we assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.
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. Instruments categorized in Level 1 consist of our exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and non exchange-traded electricity forward contracts whose underlying is identical to an exchange-traded contract.
•
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 inactive markets, 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. Instruments categorized in Level 2 include non-exchange traded derivatives such as over the counter commodity price swap and option contracts, interest rate swaps and interest rate protection agreements, foreign currency forward contracts, financial transmission rights (“FTRs”) and non exchange-traded electricity forward and capacity swap contracts that do not qualify for Level 1.
•
Level 3 - Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 2013 or 2012.
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. See Note 17 for additional information on fair value measurements.
Derivative Instruments
We account for derivative instruments and hedging activities in accordance with guidance provided by the FASB which requires that all derivative instruments, whether designated in hedging relationships or not, be recognized as either assets or liabilities and measured at fair value unless the derivative instruments qualify for the normal purchase and sale exemption under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.
A substantial portion of our derivative financial instruments other than commodity derivative instruments at Midstream & Marketing are designated and qualify as cash flow hedges or net investment hedges. Substantially all of Midstream & Marketing’s commodity derivative instruments are not designated as cash flow hedges. These derivative instruments are recorded at fair value
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
with changes in fair value reflected in income. In addition, unrealized gains and losses on certain derivative financial instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities in accordance with FASB guidance regarding accounting for rate-regulated entities.
For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Changes in the fair values of Midstream & Marketing’s commodity derivative instruments, along with those of certain of our other businesses’ derivative financial instruments, do not qualify for, or are not designated as, cash flow hedges. Changes in the fair values of these derivative instruments are generally reflected in cost of sales or revenues, as appropriate, on the Consolidated Statements of Income. Cash flows from derivative financial instruments, other than net investment hedges, are included in cash flows from operating activities. Cash flows from net investment hedges are included in cash flows from investing activities.
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 18.
Foreign Currency Translation
Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income.
Revenue Recognition
Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing records revenues when energy products are delivered or services are provided to customers. Revenues from the sale of appliances and equipment are recognized at the later of sale or installation. Revenues from repair or maintenance services are recognized upon completion of services.
UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service and commodities rendered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective.
We present revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.
LPG Delivery Expenses
Expenses associated with the delivery of LPG to customers of the Partnership and our UGI International operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as operating and administrative expenses on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and UGI International delivery vehicles is classified in depreciation on the Consolidated Statements of Income.
Income Taxes
AmeriGas Partners and the Operating Partnerships are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. The Operating Partnership has subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation.
Gas Utility and Electric Utility record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. They also record a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. Investment tax credits associated with Midstream & Marketing’s qualifying solar energy property under the Emergency Economic Stabilization Act of 2008 are reflected in income taxes for assets placed in service after Fiscal 2011 and are amortized over the estimated useful life of the property for assets placed in service prior to Fiscal 2012.
We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. No amounts were recorded for interest in Fiscal 2013. For Fiscal 2012 and Fiscal 2011, interest (income) expense of $(0.1) and $0.2, respectively, was recognized in income taxes on the Consolidated Statements of Income.
Earnings Per Common Share
Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2013, Fiscal 2012 and Fiscal 2011:
(a)
For Fiscal 2013, Fiscal 2012 and Fiscal 2011, there were approximately 88 shares, 81 shares and 3,700 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.
Comprehensive Income
Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally results from gains and losses on derivative instruments qualifying as cash flow hedges, actuarial gains and losses on postretirement benefit plans and foreign currency translation adjustments and foreign currency long-term intra-company transactions.
The components of AOCI at September 30, 2013 and 2012 follow:
Cash and Cash Equivalents
All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.
Restricted Cash
Restricted cash principally represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Inventories
Our inventories are stated at the lower of cost or market. We determine cost using an average cost method for natural gas, propane and other LPG; 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 original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.
We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives ranging from 15 to 40 years for buildings and improvements; 7 to 40 years for storage and customer tanks and cylinders; 25 to 35 years for electricity generation facilities; and 2 to 12 years for vehicles, equipment and office furniture and fixtures. Costs to install Partnership and Antargaz-owned tanks, net of amounts billed to customers, are capitalized and amortized over the estimated period of benefit not exceeding ten years.
We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.3% in Fiscal 2013, 2.2% in Fiscal 2012 and 2.3% in Fiscal 2011. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.4% in Fiscal 2013, 2.4% in Fiscal 2012 and 2.6% in Fiscal 2011. When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes.
We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.
No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
Goodwill and Intangible Assets
In accordance with GAAP relating to intangible assets, we amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. We review identifiable intangible assets subject to amortization for impairment whenever events or changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset. Intangible assets with indefinite lives are not amortized but are tested annually for impairment and written down to fair value as required.
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. We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value and the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill. 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, and for those reporting units for which we are not able, based upon the assessment of qualitative factors, to determine that it is not more likely than not that the fair value of such reporting unit is less than its carrying amount, we determine fair values generally using an income approach unless market values are available. For purposes of the income approach, fair values are determined based upon the present value of estimated future cash flows discounted at an appropriate risk-adjusted rate.
No provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2013, Fiscal 2012 or Fiscal 2011. No amortization expense is included in cost of sales in the Consolidated Statements of Income (see Note 12).
Impairment of Long-Lived Assets and Cost Basis Investments
We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
to be generated by such assets. No material provisions for impairments were recorded during Fiscal 2013, Fiscal 2012 or Fiscal 2011.
We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary. During Fiscal 2013, we recorded a pre-tax loss of $6.3 associated with an other-than-temporary impairment of an investment in a private equity partnership.
Deferred Debt Issuance Costs
Included in other assets on our Consolidated Balance Sheets are net deferred debt issuance costs of $39.4 and $46.6 at September 30, 2013 and 2012, respectively. We are amortizing these costs over the terms of the related debt.
Refundable Tank and Cylinder Deposits
Included in other noncurrent liabilities on our Consolidated Balance Sheets are customer paid deposits on Antargaz owned tanks and cylinders of $214.6 and $205.1 at September 30, 2013 and 2012, 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 effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.
Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can reasonably be estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs, and CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. For further information, see Note 16.
Employee Retirement Plans
We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 8).
Equity-Based Compensation
All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units”), are measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as a liability or as equity in 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.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
We have calculated a tax windfall pool using the shortcut method. We record deferred tax assets for awards that we expect will result in deductions on our income tax returns based on the amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return are recorded in Common Stock (if the tax benefit exceeds the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeds the tax benefit and no tax windfall pool exists from previous awards).
For additional information on our equity-based compensation plans and related disclosures, see Note 14.
Note 3 - Revisions and Restatements of Consolidated Financial Statements
During the preparation of the Fiscal 2013 consolidated financial statements, management concluded that it had incorrectly accounted for certain commodity derivative instruments as cash flow hedges. Management had incorrectly applied the hedge accounting criteria when designating certain commodity derivative instruments at its Midstream & Marketing businesses as cash flow hedges. As a result, the accompanying financial statements as of and for the two years in the period ended September 30, 2012, have been revised to report changes in the fair values of unsettled commodity derivative instruments and gains and losses on settled commodity derivative instruments for which the associated forecasted transactions have not yet occurred in cost of sales or revenues in the Consolidated Statements of Income rather than in other comprehensive income. Management has discontinued the use of hedge accounting for substantially all of Midstream & Marketing’s commodity derivative instruments and has reported changes in the fair values of unsettled commodity derivative instruments, and gains and losses on settled commodity derivatives for which the associated forecasted transaction has not yet occurred, in net income.
Although the impact of the error was not material to the Company’s historical annual consolidated financial statements, management decided to revise its consolidated financial statements and disclosures to correct this error in accounting for the years ended September 30, 2012 and 2011. Management did conclude that the error in accounting was material to its consolidated financial statements for the fiscal quarters ended March 31, 2013, June 30, 2012, and December 31, 2011, and that it is necessary to restate the Company’s financial statements for those periods while the Company’s consolidated financial statements for other quarterly periods have been revised (see Note 21).
The following table sets forth the effects of the revision on affected line items within the Company’s previously reported consolidated financial statements for fiscal years ended September 30, 2012 and 2011. Also included in the adjustment columns in the tables below are certain other immaterial corrections that the Company made, including, but not limited to, adjustments to correct the Partnership’s accounting for certain customer credits and to correct the classification of deferred income tax assets, as further described below, as well as certain other minor adjustments related principally to the timing of certain expense and income accruals.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Consolidated Balance Sheet
During the three months ended September 30, 2013, we identified an error in the classification of deferred income tax assets on the September 30, 2012, Consolidated Balance Sheet in the amount of $27.0. The adjustment to correct this error is included in the table above in deferred income taxes (assets) and deferred income taxes (liabilities).
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Equity
During the three months ended March 31, 2013, the Partnership determined that the recording of propane revenues did not appropriately consider the effects of certain customer credits which were recorded in a subsequent period. Although the Company evaluated the impact of the error on prior periods and determined the effect was not material to any prior period financial statement and corrected the error during the three months ended March 31, 2013, the tables above include correction of the error in accounting for customer credits in the appropriate historical period.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The impacts of the corrections on the key financial metrics operating income, net income attributable to UGI Corporation and diluted earnings per share for the years ended September 30, 2013 and 2012 are as follows:
Note 4 - Accounting Changes
New Accounting Standards Not Yet Adopted
Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued new accounting guidance regarding disclosures for items reclassified out of AOCI. The new disclosure guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2012. The new disclosures are to be applied prospectively, and early adoption is permitted. We will adopt the new guidance in Fiscal 2014. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.
Disclosures about Offsetting Assets and Liabilities. In December 2011 (and amended in January 2013), the FASB issued new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 (Fiscal 2014) and interim periods within those annual periods, and is required to be applied retrospectively. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.
Note 5 - Acquisitions
On January 12, 2012 (the “Acquisition Date”), AmeriGas Partners completed the acquisition of Heritage Propane from ETP for total consideration of $2,598.2, comprising $1,465.6 in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of $1,132.6 (the “Heritage Acquisition”). The Acquisition Date cash consideration for the Heritage Acquisition was subject to purchase price adjustments based on working capital, cash and the amount of indebtedness of Heritage Propane (“Working Capital Adjustment”) and certain excess cash proceeds resulting from ETP’s sale of HOLP’s former cylinder exchange business (“HPX”). In April 2012, AmeriGas Partners paid $25.5 of additional cash consideration as a result of the Working Capital Adjustment and in June 2012, AmeriGas Partners received $18.9 in cash representing the excess cash proceeds from the sale of HPX. The Heritage Acquisition was consummated pursuant to a Contribution and Redemption Agreement dated October 15, 2011, as amended (the “Contribution Agreement”), by and among AmeriGas Partners, ETP, Energy Transfer Partners GP, L.P., the general partner of ETP (“ETP GP”), and Heritage ETC, L.P. (the “Contributor”). The acquired business conducted its propane
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
operations in 41 states through HOLP and Titan LLC. According to LP-Gas Magazine rankings published on February 1, 2012, Heritage Propane was the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers in 2011. The Heritage Acquisition is consistent with our growth strategies, one of which is to grow the Partnership’s core business through acquisitions.
Pursuant to the Contribution Agreement, the Contributor contributed to AmeriGas Partners a 99.999% limited partner interest in HOLP; a 100% membership interest in Heritage Operating GP, LLC, a Delaware limited liability company and a holder of a 0.001% general partner interest in HOLP; a 99.99% limited partner interest in Titan Energy Partners, L.P., a Delaware limited partnership and the sole member of Titan LLC; and a 100% membership interest in Titan Energy GP, L.L.C., a Delaware limited liability company and holder of a 0.01% general partner interest in Titan Energy Partners, L.P. As a result of the Heritage Acquisition, the General Partner, in order to maintain its general partner interests in AmeriGas Partners and AmeriGas OLP, contributed 934,327 Common Units to the Partnership having a fair value of $41.7. These Common Units were subsequently cancelled.
The cash portion of the Heritage Acquisition was financed by the issuance by AmeriGas Finance Corp. and AmeriGas Finance LLC, wholly owned finance subsidiaries of AmeriGas Partners (the “Issuers”), of $550 principal amount of 6.75% Senior Notes due May 2020 (the “6.75% Notes”) and $1,000 principal amount of 7.00% Senior Notes due May 2022 (the “7.00% Notes”). For further information on the 6.75% Notes and the 7.00% Notes, see Note 6.
The Consolidated Balance Sheet at September 30, 2012, reflects the final allocation of the purchase price to the assets acquired and liabilities assumed for the Heritage Propane business combination. The purchase price paid comprises AmeriGas Partners Common Units issued having a fair value of $1,132.6, and total cash consideration of $1,472.2 including cash acquired of $60.7. The fair value of the AmeriGas Partners Common Units issued to ETP was based on the closing price on the Acquisition Date subject to a discount to reflect certain contractual transfer restrictions for a period of approximately twelve months. The purchase price allocation was as follows:
(a) During Fiscal 2013, the Partnership made a correcting adjustment to trademarks and tradenames and goodwill which is not reflected in the table above. See Note 12.
Goodwill associated with the Heritage Acquisition principally results from synergies expected from combining the operations and from assembled workforce. The tax effects of such goodwill will be realized over a fifteen-year period. We allocated the purchase price of the acquisition to identifiable intangible assets based on estimated fair values. Tradenames and trademarks were valued using the relief from royalty method and customer relationships were valued using a discounted cash flow method. The relief from royalty 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 and are the assumptions most sensitive and susceptible to change as they require significant management judgment. The key assumptions used in the customer relationship discounted cash flow method include discount rates, growth rates and cash flow projections and are the assumptions most sensitive and susceptible to change as they require significant management judgment. We allocated the purchase price of the acquisition to property, plant and equipment based on estimated fair values primarily using replacement cost and market value methods.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Transaction expenses associated with the Heritage Acquisition, which are included in operating and administrative expenses in the Consolidated Statement of Income, totaled $5.3 for Fiscal 2012. The results of operations of Heritage Propane are included in the Consolidated Statements of Income since the Acquisition Date. As a result of combining the Heritage Propane operations with the Partnership’s legacy operations, it is impracticable to determine the impact of the Heritage Propane operations on the revenues and earnings of the Company.
The following presents unaudited pro forma income statement and earnings per share data for Fiscal 2012 and 2011 as if the Heritage Acquisition had occurred on October 1, 2010:
The unaudited pro forma results of operations reflect Heritage Propane’s historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The unaudited pro forma consolidated results of operations are not necessarily indicative of the results that would have occurred had the Heritage Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results.
During Fiscal 2013, Flaga acquired BP’s LPG distribution business in Poland for total cash consideration of approximately $36 which Flaga financed with cash proceeds from the issuance of long-term debt (see Note 6) and its purchase price has been preliminarily allocated to the assets acquired and liabilities assumed; AmeriGas OLP acquired two domestic retail propane distribution businesses for approximately $20 in cash; and Energy Services acquired a non-operating working interest in natural gas acreage in the Marcellus Shale region of Pennsylvania for approximately $23 in cash. In October 2011, we acquired Shell’s LPG distribution businesses in (1) Belgium, the Netherlands and Luxembourg through Antargaz; (2) Denmark, Finland, Norway and Sweden through Flaga; and (3) the United Kingdom through UGI Midlands Limited (a second-tier subsidiary of Enterprises), for a total of €133.6 ($179.0) in cash (the “Shell Transaction”). Also during Fiscal 2012, AmeriGas OLP acquired a number of smaller domestic retail propane distribution businesses for $13.5 in cash. During Fiscal 2011, AmeriGas OLP acquired a number of domestic retail propane distribution businesses for $34.0 in cash, and Flaga acquired a propane distribution business in Poland for total cash consideration of approximately $19.0.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 6 - Debt
Long-term debt comprises the following at September 30:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Scheduled principal repayments of long-term debt due in fiscal years 2014 to 2018 follow:
(a) UGI Utilities $175 Term Loan Credit Agreement borrowings anticipated to be refinanced on a long-term basis in March 2014 pursuant to a Note Purchase Agreement as further described below are excluded from the table above.
AmeriGas Propane
In order to finance the cash portion of the Heritage Acquisition, on January 12, 2012, the Issuers issued $550 principal amount of 6.75% Notes due May 2020 and $1,000 principal amount of 7.00% Notes due May 2022. The 6.75% Notes and the 7.00% Notes are fully and unconditionally guaranteed on a senior unsecured basis by AmeriGas Partners. The Issuers have the right to redeem the 6.75% Notes, in whole or in part, at any time on or after May 20, 2016, and to redeem the 7.00% Notes, in whole or in part, at any time on or after May 20, 2017, subject to certain restrictions. A premium applies to redemptions of the 6.75% Notes and 7.00% Notes through May 2018 and May 2020, respectively. On or prior to May 20, 2015, the Issuers may also redeem, at a premium and subject to certain restrictions, up to 35% of each of the 6.75% Notes and the 7.00% Notes with the proceeds of an AmeriGas Partners registered public equity offering. The 6.75% Notes and the 7.00% Notes and the guarantees rank equal in right of payment with all of AmeriGas Partners’ existing Senior Notes. In connection with the Heritage Acquisition, AmeriGas Partners, AmeriGas Finance Corp., AmeriGas Finance LLC and UGI entered into a Contingent Residual Support Agreement (“CRSA”) with ETP pursuant to which ETP will provide contingent, residual support of $1,500 of debt (“Supported Debt” as defined in the CRSA).
On March 28, 2012, AmeriGas Partners announced that holders of approximately $383.5 in aggregate principal amount of outstanding 6.50% Senior Notes due May 2021 (the “6.50% Notes”), representing approximately 82% of the total $470 principal amount outstanding, had validly tendered their notes in connection with the Partnership’s March 14, 2012, offer to purchase for cash up to $200 of the 6.50% Notes. Tendered 6.50% Notes in the amount of $200 were redeemed on March 28, 2012, at an effective price of 105% using an approximate proration factor of 52.3% of total notes tendered. During June 2012, AmeriGas Partners repurchased approximately $19.2 aggregate principal amount of outstanding 7.00% Notes. The Partnership recorded a net loss of $13.3 on these extinguishments of debt which amount is reflected on the Fiscal 2012 Consolidated Statement of Income under the caption loss on extinguishments of debt. The net loss reduced net income attributable to UGI Corporation by $2.2 during Fiscal 2012.
In January 2011, AmeriGas Partners issued $470 principal amount of 6.50% Notes due May 2021. The proceeds from the issuance of the 6.50% Notes were used in February 2011 to repay AmeriGas Partners’ $415 principal amount of its 7.25% Senior Notes due May 2015 pursuant to a tender offer and subsequent redemption. In addition, in February 2011, AmeriGas Partners redeemed the outstanding $14.6 principal amount of its 8.875% Senior Notes due May 2011. The Partnership incurred a loss of $18.8 on these extinguishments of debt which amount is reflected on the Fiscal 2011 Consolidated Statement of Income under the caption loss on extinguishments of debt. This loss reduced net income attributable to UGI Corporation by $5.2 during Fiscal 2011.
In August 2011, AmeriGas Partners issued $450 principal amount of 6.25% Senior Notes due August 2019 (the “6.25% Senior Notes”). The proceeds from the issuance of the 6.25% Senior Notes were used to repay $350 principal amount of AmeriGas Partners 7.125% Senior Notes due May 2016 pursuant to a tender offer and subsequent redemption. The Partnership incurred a loss of $19.3 on this extinguishment of debt which amount is reflected on the Fiscal 2011 Consolidated Statement of Income under the caption loss on extinguishments of debt. This loss reduced net income attributable to UGI Corporation by $5.2 during Fiscal 2011.
The 6.50% and 6.25% Senior Notes generally may be redeemed at our option (pursuant to a tender offer). A redemption premium applies through May 2019 (with respect to the 6.50% Notes) and through August 2017 (with respect to the 6.25% Notes). In addition, in the event that AmeriGas Partners completes a registered public offering of Common Units, the Partnership may, at its option, redeem up to 35% of the outstanding 6.50% Notes (through May 20, 2014) or 35% of the outstanding 6.25% Notes (through August 20, 2014), each at a premium. AmeriGas Partners may, under certain circumstances involving excess sales proceeds
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
from the disposition of assets not reinvested in the business or a change of control, be required to offer to prepay its 6.50% and 6.25% Senior Notes.
The Partnership’s total long-term debt at September 30, 2013, includes $32.0 of HOLP Senior Secured Notes (including unamortized premium of $3.7). At September 30, 2013, the face interest rates on the HOLP Notes range from 7.89% to 8.87% with an effective interest rate of 6.75%. The HOLP Senior Secured Notes are collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash.
AmeriGas OLP has an unsecured credit agreement (the “AmeriGas Credit Agreement”) with a group of banks providing for borrowings up to $525 (including a $125 sublimit for letters of credit) which expires in October 2016. The AmeriGas Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin. The margin on base rate borrowings (which ranges from 0.75% to 1.75%), Eurodollar Rate borrowings (which ranges from 1.75% to 2.75%), and the AmeriGas Credit Agreement facility fee rate (which ranges from 0.30% to 0.50%) are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”), each as defined in the AmeriGas Credit Agreement.
At September 30, 2013 and 2012, there were $116.9 and $49.9, respectively, of borrowings outstanding under the AmeriGas Credit Agreement, which amounts are reflected as bank loans on the Consolidated Balance Sheets. The weighted-average interest rates on AmeriGas Credit Agreement borrowings at September 30, 2013 and 2012, were 2.69% and 2.72%, respectively. At September 30, 2013 and 2012, issued and outstanding letters of credit, which reduce available borrowings under the AmeriGas Credit Agreement, totaled $53.7 and $47.9, respectively.
Restrictive Covenants. The AmeriGas Partners Senior Notes restrict the ability of the Partnership and AmeriGas OLP to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets. Under the AmeriGas Partners Senior Notes Indentures, AmeriGas Partners is generally permitted to make cash distributions equal to Available Cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. At September 30, 2013, these restrictions did not limit the amount of Available Cash. See Note 15 for definition of Available Cash included in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. (“Partnership Agreement”).
The HOLP Senior Secured Notes contain restrictive covenants including the maintenance of financial covenants and limitations on the disposition of assets, changes in ownership, additional indebtedness, restrictive payments and the creation of liens. The financial covenants require AmeriGas OLP to maintain a ratio of Consolidated Funded Indebtedness to Consolidated EBITDA (as defined) below certain thresholds and to maintain a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense (as defined).
The AmeriGas Credit Agreement restricts the incurrence of additional indebtedness and also restrict certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas Credit Agreement requires that the Partnership and AmeriGas OLP 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, as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result, the Partnership and AmeriGas OLP are permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter.
UGI International
In March 2011, Antargaz entered into a five-year Senior Facilities Agreement with a consortium of banks (“Senior Facilities Agreement”) consisting of a €380 ($514.0) variable-rate term loan and a €40 credit facility. The proceeds from the Senior Facilities Agreement term loan were used to repay Antargaz’ then-existing Senior Facilities Agreement term loan due March 2011.
Scheduled maturities under the term loan are €38 ($51.4) due May 2014, €34.2 ($46.3) due May 2015, and €307.8 ($416.3) due March 2016. Borrowings under the Senior Facilities Agreement bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the Senior Facilities Agreement. There were no amounts outstanding under the Senior Facilities Agreement at September 30, 2013 or 2012. The margin on the term loan and credit facility borrowings (which ranges from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the Senior Facilities Agreement. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of 3.71% through the date of the term loan’s
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
final maturity in March 2016. At September 30, 2013 and 2012, the effective interest rates on Antargaz’ term loan were 4.41% and 4.66%, respectively. The Senior Facilities Agreement is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivables.
In order to finance the purchase of BP’s LPG distribution business in Poland in September 2013, Flaga entered into a $52 U.S. dollar-denominated three-year term loan which matures in September 2016. The $52 loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin of 1.25%. Flaga has effectively fixed the euribor component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the $52 loan, by entering into a cross-currency swap arrangement with a bank. At September 30, 2013, the effective interest rate on the $52 loan was 1.82%.
In December 2011, Flaga entered into a €19.1 ($25.8) euro-based variable-rate term loan agreement. Proceeds from the term loan were used, in large part, to fund Flaga’s October 2011 acquisition of Shell’s LPG propane businesses in Finland, Norway, Sweden and Denmark. The term loan matures in October 2016 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 1.175% to 2.525% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 1.79% by entering into an interest rate swap agreement. The effective interest rates on this term loan at September 30, 2013 and 2012, was 3.85% and 4.35%, respectively.
In September 2011, Flaga entered into a €40 euro-based variable-rate term loan of which €26.7 ($36.1) matures in August 2016 and €13.3 ($18.0) matures in September 2016. A portion of the proceeds from the loan were used to repay its €24.0 euro-based variable-rate term loan which matured during Fiscal 2011. The €40 euro-based term loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin. The margin on such borrowings ranges from 0.23% to 2.55% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios. Flaga has effectively fixed the euribor component of its interest rate on this term loan through September 2016 at 2.68% by entering into interest rate swap agreements. The effective interest rates on Flaga’s term loans at September 30, 2013 and 2012, were 4.68% and 5.18%, respectively.
As of September 30, 2013 and 2012, Flaga also has a euro-based variable-rate term loan which had outstanding principal balances of €1.4 ($1.9) and €2.8 ($3.6), respectively. This term loan matures in June 2014 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 2.625% to 3.50% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios. Semi-annual principal payments of €0.7 are due on December 31 and June 30 each year through June 2014. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 2.16% by entering into an interest rate swap agreement. As of September 30, 2013 and 2012, the effective interest rate on this term loan was 5.04%.
At September 30, 2013, Flaga has two principal working capital facilities (the “Flaga Credit Agreements”) comprising (1) a €46 multi-currency working capital facility which includes an uncommitted €6 overdraft facility (the “Multi-Currency Working Capital Facility”) and (2) a euro-denominated working capital facility that provides for borrowings and issuances of guarantees totaling €12 (the “Euro Working Capital Facility”). Both the Multi-Currency Working Capital Facility and the Euro Working Capital Facility expire in September 2014. At September 30, 2013 and 2012, there were €0.2 ($0.3) and €11.9 ($15.3) of borrowings outstanding under the Flaga Credit Agreements. These amounts are reflected as bank loans on the Consolidated Balance Sheets.
Borrowings under the Flaga Credit Agreements generally bear interest at market rates (a daily euro-based rate or three-month euribor rates) plus a margin. The weighted-average interest rates on Flaga Credit Agreements borrowings at September 30, 2013 and 2012, were 4.21% and 2.31%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the Flaga Credit Agreements, totaled €28.6 ($38.7) and €19.2 ($24.7) at September 30, 2013 and 2012, respectively.
Restrictive Covenants and Guarantees. The Senior Facilities Agreement restricts the ability of Antargaz to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires Antargaz to maintain a ratio of net debt to EBITDA on a French generally accepted accounting basis, as defined in the agreement, that shall not exceed 3.50 to 1.00. Under this agreement, Antargaz is generally permitted to make restricted payments, such as dividends if no event of default exists or would exist upon payment of such restricted payment. UGI has guaranteed up to €100 of payments under the Senior Facilities Agreement.
The Flaga term loans, working capital facilities and interest rate and cross currency agreements are guaranteed by UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending banks may accelerate repayment of the debt.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
UGI Utilities
In September 2013, UGI Utilities entered into a 364-day term loan credit agreement (“UGI Utilities Term Loan Credit Agreement”) with a bank comprising a $175 unsecured term loan facility. The UGI Utilities Term Loan Credit Agreement bears interest at the eurodollar rate for the interest period selected, plus a margin of 0.60%. The UGI Utilities Term Loan Credit Agreement terminates on September 22, 2014, but UGI Utilities may prepay the loan in whole or in part, without penalty. UGI Utilities borrowed $175 on September 30, 2013, under the UGI Utilities Term Loan Credit Agreement which cash proceeds were used to repay UGI Utilities’ $108 million 6.375% Senior Notes due September 30, 2013, and for other general corporate purposes. On October 30, 2013, UGI Utilities entered into a Note Purchase Agreement which provides for the private placement of $175 aggregate principal amount of 4.98% Senior Notes due March 26, 2044. UGI Utilities expects to use net proceeds from the issuance of $175 face amount of 4.98% Senior Notes in March 2014 to repay then-outstanding borrowings under the UGI Utilities Term Loan Credit Agreement. Because the Company has the intent and ability to refinance the UGI Utilities Term Loan Credit Agreement on a long-term basis, amounts outstanding under the UGI Utilities Term Loan Agreement are classified as long-term on the September 30, 2013 Consolidated Balance Sheet.
UGI Utilities has an unsecured credit agreement (“UGI Utilities Credit Agreement”) with a group of banks providing for borrowings up to $300 (including a $100 sublimit for letters of credit) which expires in October 2015. Under the UGI Utilities 2011 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based upon the credit ratings of certain indebtedness of UGI Utilities. UGI Utilities had $17.5 and $9.2 of borrowings outstanding under the UGI Utilities Credit Agreement at September 30, 2013 and 2012, respectively, which amounts are reflected in bank loans on the Consolidated Balance Sheets. The weighted-average interest rates on UGI Utilities Credit Agreement borrowings at September 30, 2013 and 2012 were 1.18% and 1.21%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the UGI Utilities Credit Agreement, totaled $2.0 at September 30, 2013 and 2012.
Restrictive Covenants. UGI Utilities Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
Energy Services
Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $240 (including a $50 sublimit for letters of credit) which expires in June 2016. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries. In addition, Energy Services may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not exceed 2.25 to 1.00. There were $57 and $85 of borrowings outstanding under the Energy Services Credit Agreement at September 30, 2013 and 2012, respectively. These amounts are reflected as bank loans on the Consolidated Balance Sheets.
Borrowings under the Energy Services Credit Agreement bear interest at either (i) a rate derived from LIBOR (the “LIBO Rate”) plus 2.5% for each Eurodollar Revolving Loan (as defined in the Energy Services Credit Agreement) or (ii) the Alternate Base Rate plus 1.5%. The Alternate Base Rate (as defined in the Energy Services Credit Agreement) is generally the greater of (a) the Agent Bank’s prime rate, (b) the federal funds rate plus 0.50% and (c) the one-month LIBO Rate plus 1.0%. The weighted-average interest rates on the Energy Services Credit Agreement borrowings at September 30, 2013 and 2012, were 2.91% and 3.25%, respectively. The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services.
Restrictive Covenants. The Energy Services Credit Agreement restricts the ability of Energy Services to dispose of assets, effect certain consolidations or mergers, incur indebtedness and guaranty obligations, create liens, make acquisitions or investments, make certain dividend or other distributions and make any material changes to the nature of its businesses. In addition, the Energy Services Credit Agreement requires Energy Services to not exceed a ratio of Consolidated Total Indebtedness, as defined, to Consolidated EBITDA, as defined; a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense, as defined; a maximum ratio of Consolidated Total Indebtedness to Consolidated Total Capitalization, as defined, at any time when Consolidated Total Indebtedness is greater than $250; and a minimum Consolidated Net Worth, as defined, of $200.
Energy Services also has a receivables securitization facility (see Note 19).
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Restricted Net Assets
At September 30, 2013, the amount of net assets of UGI’s consolidated subsidiaries that was restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $1,500.
Note 7 - Income Taxes
Income before income taxes comprises the following:
The provisions for income taxes consist of the following:
Federal income taxes for Fiscal 2013 and Fiscal 2012 are net of foreign tax credits of $34.9 and $5.2, respectively.
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The effects of foreign operations in the table above for Fiscal 2012 reflects the impact of tax efficient structuring of certain of our international operations and, as a result of the Fiscal 2012 Shell Transaction, also reflects a greater proportion of pretax income in countries in which the statutory income tax rate is less than the U.S. statutory tax rate. The tax restructuring of certain of our international operations also permitted us to reduce our foreign tax credit valuation allowance by $4.6 during Fiscal 2012 which is included as a valuation allowance adjustment in the table above.
Earnings of the Company’s foreign subsidiaries are generally subject to U.S. taxation upon repatriation to the U.S. and the Company’s tax provision reflects the related incremental U.S. tax except for certain foreign subsidiaries whose unremitted earnings are considered to be indefinitely reinvested. Because of the availability of U.S. foreign tax credits, it is likely no U.S. tax would be due if such earnings were repatriated.
Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2013, Fiscal 2012 and Fiscal 2011, the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $1.5, $3.2 and $7.9, respectively. The state tax flow through amounts in Fiscal 2012 and Fiscal 2011 reflect the impact of 2010 U.S. Federal tax legislation that allowed taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of calendar 2011, when such property was placed in service before 2012. This legislation was also permitted for Pennsylvania state corporate income tax purposes.
Deferred tax liabilities (assets) comprise the following at September 30:
At September 30, 2013, foreign net operating loss carryforwards principally relating to Flaga and certain operations of Antargaz totaled $47.7 and $5.3, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $224.9 and expire through 2033. We also have operating loss carryforwards of $15.7 for certain operations of AmeriGas Propane that expire through 2033. At September 30, 2013, deferred tax assets relating to operating loss carryforwards include $11.0 for Flaga, $1.8 for Antargaz, $0.9 for UGI International Holdings BV, $6.1 for AmeriGas Propane and $17.6 for certain other subsidiaries. A valuation allowance of $13.5 has been provided for deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries because, on a state reportable basis, it is more likely than not that these assets will expire unused. Valuation allowances for net operating loss tax benefits decreased by $4.7 primarily due to changes in entities that will now allow carryforward use of previously incurred losses. A valuation allowance of $7.9 was also provided for deferred tax assets related to certain operations of Antargaz, Flaga and UGI International Holdings BV. Operating activities and tax deductions related to the exercise of non-qualified stock options contributed to the state net operating losses disclosed above. We first recognize the utilization of state net operating losses from operations
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(which exclude the impact of tax deductions for exercises of non-qualified stock options) to reduce income tax expense. Then, to the extent state net operating loss carryforwards, if realized, relate to non-qualified stock option deductions, the resulting benefits will be credited to UGI Corporation stockholders’ equity. The table of deferred tax assets and liabilities do not include $5.6 for Fiscal 2013 and $4.6 for Fiscal 2012 of deferred tax assets and associated valuation allowance for unrealized state tax benefits for equity compensation deductions.
We have foreign tax credit carryforwards of approximately $81.8 expiring through 2023 resulting from the actual and planned repatriation of Antargaz’ accumulated earnings since acquisition which are includable in U.S. taxable income. Because we expect that these credits will expire unused, a valuation allowance has been provided for the entire foreign tax credit carryforward amount. The valuation allowance for all deferred tax assets increased by $20.6 in Fiscal 2013 due to an increase in unusable foreign tax credits of $26.3 partially offset by decreases in unusable state and federal operating loss tax benefits of $4.7 and $1.0, respectively, as a result of changes in entity status.
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 2009 tax year, our French tax returns are settled through the 2009 tax year. Our Austrian tax returns are settled through 2007 and our other European tax returns are effectively settled for various years from 2005 to 2010. State and other income tax returns in the U.S. are generally subject to examination for a period of three to five years after the filing of the respective returns.
As of September 30, 2013, we have unrecognized income tax benefits totaling $3.6 including related accrued interest of $0.2. If these unrecognized tax benefits were subsequently recognized, $2.4 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. Included in the balance at September 30, 2013, are $1.1 of tax positions for which the deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, the disallowance of the current deduction would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. There is an expected change in unrecognized tax benefits and related interest in the next twelve months in the amount of $0.7.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
Note 8 - Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans. In the U.S., we currently sponsor one 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”).
We also provide postretirement health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all domestic active and retired employees. In addition, Antargaz employees are covered by certain defined
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the Antargaz 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 Antargaz 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, 2013 and 2012. 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
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
In Fiscal 2014, we estimate that we will amortize approximately $7.8 of net actuarial losses, primarily associated with the U.S. Pension Plan, and $0.2 of prior service credits from UGI stockholders’ equity and regulatory assets into retiree benefit cost.
Actuarial assumptions for our domestic plans are described below. Assumptions for the Antargaz plans are based upon market conditions in France. 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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
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 the current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).
______________
(a)
Effective December 31, 2010, we merged our then-existing two U.S. defined benefit pension plans (“U.S. Pension Plans Merger”) to form the U.S. Pension Plan. The discount rates used during Fiscal 2011 to calculate pension expense were rates of 5.0% through December 31, 2010 (the date of the U.S. Pension Plans Merger) and 5.5% for the remainder of Fiscal 2011.
The ABOs for the U.S. Pension Plan were $451.3 and $496.4 as of September 30, 2013 and 2012, respectively.
Net periodic pension expense and other postretirement benefit cost includes the following components:
U.S. Pension Plan’s assets are held in trust. 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 2013, Fiscal 2012 and Fiscal 2011, we made cash contributions to the U.S. Pension Plan of $22.4, $31.2 and $18.7 respectively. We believe that in Fiscal 2014 we will be required to make contributions to the U.S. Pension Plan totaling approximately $18.
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 determined under GAAP. The difference between such amounts and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. The required contributions to the VEBA during Fiscal 2014 are not expected to be material.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Expected payments for pension benefits and for other postretirement welfare benefits are as follows:
The assumed domestic health care cost trend rates for Fiscal 2013 are 7.0% during Fiscal 2013, decreasing to 5.0% in Fiscal 2017. The assumed domestic health care cost trend rates as of September 30, 2013, are 7.5% decreasing to 5.0% in Fiscal 2019. A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 2012 other postretirement benefit cost or September 30, 2013, other postretirement benefit ABO.
We also sponsor unfunded and non-qualified supplemental executive retirement plans (“Supplemental Defined Benefit Plans”). At September 30, 2013 and 2012, the PBOs of these plans were $33.9 and $29.5, respectively. We recorded pre-tax costs for these plans of $3.0 in Fiscal 2013, $3.0 in Fiscal 2012 and $3.0 in Fiscal 2011. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $9.4 and $11.0 at September 30, 2013 and 2012, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.6 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2014. During Fiscal 2013, the Company made payments with respect to the Supplemental Defined Benefit Plans totaling $21.6, including $21.0 to fund self-directed grantor trusts established by the Company for participants who chose to defer their Supplemental Defined Benefit Plan payment upon retirement. The total fair value of these trust assets, which are included in other assets on the Consolidated Balance Sheets, totaled $23.7 million and $2.0 million at September 30, 2013 and 2012, respectively.
U.S. Pension Plan and VEBA Assets. The assets of the U.S. Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the U.S. Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly-traded diversified equity and fixed income mutual funds and UGI Common Stock.
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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
VEBA
Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap 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 8.2% and 7.5% of U.S. Pension Plan assets at September 30, 2013 and 2012, respectively.
GAAP establishes a hierarchy that prioritizes fair value measurements based upon the inputs and valuation techniques used to measure fair value. This fair value hierarchy groups assets into three levels, as described in Note 2. We maximize the use of observable inputs and minimize the use of unobservable inputs when determining fair value. 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.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The fair values of the U.S. Pension Plan and VEBA trust assets at September 30, 2013 and 2012, by asset class are as follows:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The expected long-term rates of return on U.S. Pension Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.
Defined Contribution Plans. We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans totaled $14.0 in Fiscal 2013, $13.7 in Fiscal 2012 and $10.4 in Fiscal 2011. 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. Costs associated with these plans were not material in Fiscal 2013, Fiscal 2012 or Fiscal 2011.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 9 - Utility Regulatory Assets and Liabilities and Regulatory Matters
The following regulatory assets and liabilities associated with Utilities are included in our accompanying balance sheets at September 30:
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 accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 50 years.
Underfunded pension and other postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and other postretirement benefits which are probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants.
Environmental costs. Environmental costs represent amounts actually spent by UGI Gas to clean up sites in Pennsylvania as well as the portion of estimated probable future environmental remediation and investigation costs principally at manufactured gas plant (“MGP”) sites that CPG and PNG expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 16). UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites. PNG and CPG are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2013, the period over which PNG and CPG expect to recover these costs will depend upon future remediation activity.
Deferred fuel and power - costs and refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and delivery 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 financial 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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
financial instruments are included in deferred fuel costs or refunds. Net unrealized (losses) gains on such contracts at September 30, 2013 and 2012 were $(1.7) and $5.3, respectively.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP related to derivative financial instruments, these electricity supply contracts are recognized on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At September 30, 2013 and 2012, the fair values of Electric Utility’s electricity supply contracts were losses of $4.8 and $9.2, respectively, which amounts are reflected in current derivative financial instruments and other noncurrent liabilities on the Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.
In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. At September 30, 2013 and 2012, such gains or losses were not material.
Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. At September 30, 2013, UGI Utilities expects to recover these costs over periods of 1 to 5 years.
Postretirement benefits. Gas Utility and Electric Utility are recovering ongoing postretirement benefit costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI Gas and Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above. In addition, this regulatory liability includes the portion of prior service credits and net actuarial gains associated with certain other postretirement benefit plans.
Environmental overcollections. This regulatory liability represents the difference between amounts recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms of a consent order agreement between CPG and the Pennsylvania Department of Environmental Protection to remediate certain gas plant sites.
State income tax benefits - distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.
Other. Other regulatory assets comprise a number of items including, among others, deferred postretirement costs, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2013, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.
UGI Utilities’ regulatory liabilities relating to postretirement benefits, environmental overcollections and state tax benefits - distribution system repairs are included in other noncurrent liabilities on the Consolidated Balance Sheets. UGI Utilities does not recover a rate of return on its regulatory assets.
Other Regulatory Matters
Allentown, Pennsylvania Natural Gas Incident. On February 19, 2013, the PUC entered a final order (the “Final Order”) settling all regulatory compliance issues pertaining to a natural gas explosion on February 9, 2011, in Allentown, PA. The Final Order requires UGI Utilities to (i) pay a civil penalty in the amount of $0.5; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities' consolidated financial position, results of operations or cash flows.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
CPG Base Rate Filing. On August 11, 2011, the PUC approved a settlement agreement with CPG that resulted in an increase in annual base rate revenues of $8.0 as well as $0.9 in revenues per year to fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). The increase became effective August 30, 2011. During Fiscal 2012, the PUC reversed its earlier decision related to the $0.9 increase in revenues associated with the Energy and Efficiency Conservation Program and required CPG to refund revenue it had collected for that program.
Transfers of Assets. On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11-mile natural gas pipeline, related facilities and right of way located in Delmar Township, Pennsylvania (“TL-96 line”) to Energy Services. The PUC approved the transfer and, in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the TL-96 line is approximately $2.6.
On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011, the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9. Compliance with the provisions of the PUC Order approving the transfer of the storage assets did not have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.
On December 1, 2010, PNG filed an application with the PUC for expedited review and approval of the transfer of a 9-mile natural gas pipeline, related facilities, and right of way located in Mehoopany, Pennsylvania (the “Auburn Line”) to Energy Services. The PUC approved the transfer and in September 2011 the Auburn Line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the Auburn Line was $1.1.
Note 10 - Inventories
Inventories comprise the following at September 30:
At September 30, 2013, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”), one of which expired in October 2013 and two of which expire in October 2015. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.
As of September 30, 2013, UGI Utilities’ principal SCAAs are with Energy Services. The carrying values of gas storage inventories released under the SCAAs to non-affiliates at September 30, 2013 and 2012, comprising 0.6 billion cubic feet (“bcf”) and 3.8 bcf of natural gas was $2.4 and $11.4, respectively. Effective November 1, 2013, UGI Utilities entered into a new SCAA with Energy Services having a term of one year and another with a third party having a term of three years.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 11 - Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:
Note 12 - Goodwill and Intangible Assets
Goodwill and intangible assets comprise the following at September 30:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Changes in the carrying amount of goodwill are as follows:
The decrease in trademarks and tradenames and the correcting adjustment to goodwill during the year ended September 30, 2013 primarily reflects a correcting adjustment associated with the Heritage Acquisition. We amortize customer relationships and noncompete agreement intangibles over their estimated periods of benefit which do not exceed 15 years. Amortization expense of intangible assets was $52.8 in Fiscal 2013, $44.5 in Fiscal 2012 and $20.4 in Fiscal 2011. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2014 - $51.2; Fiscal 2015 - $48.4; Fiscal 2016 - $42.4; Fiscal 2017 - $35.9; Fiscal 2018 - $34.5. There were no accumulated impairment losses at September 30, 2013.
Note 13 - Series Preferred Stock
UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2013 or 2012.
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, 2013 and 2012, there were no shares of UGI Utilities Series Preferred Stock outstanding.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 14 - Common Stock and Equity-Based Compensation
UGI Common Stock share activity for Fiscal 2011, Fiscal 2012 and Fiscal 2013 follows:
As a result of the January 2012 issuance of 29,567,362 AmeriGas Partners Common Units to ETP in conjunction with the Heritage Acquisition and related General Partner Common Unit transactions (see Note 5), and the March 2012 issuance of 7,000,000 AmeriGas Partners Common Units pursuant to AmeriGas Partners’ public offering (see Note 15), the Company recorded a $196.3 increase in UGI Corporation stockholders’ equity (which amount is net of deferred income taxes) and an associated $321.4 pre-tax decrease in noncontrolling interests equity.
Equity-Based Compensation
The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $17.6 ($11.4 after-tax), $14.5 ($8.7 after-tax) and $15.6 ($10.3 after-tax) in Fiscal 2013, Fiscal 2012 and Fiscal 2011, respectively.
UGI Equity-Based Compensation Plans and Awards. On January 24, 2013, the Company’s shareholders approved the UGI Corporation 2013 Omnibus Incentive Compensation Plan (the “2013 OICP”). The 2013 OICP succeeds the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “2004 OECP”) for awards granted on or after January 24, 2013. The 2004 OECP will continue in effect but all future grants issued pursuant to it will be solely in the form of options to acquire Common Stock. Under the 2013 OICP, we may grant options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”), other equity-based awards and cash to key employees and non-employee directors. The exercise price for options may not be less than the fair market value on the grant date. Awards granted under the 2013 OICP may vest immediately or ratably over a period of years, and stock options can be exercised no later than ten years from the grant date. In addition, the 2013 OICP provides that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
Under the 2004 OECP, we could grant options to acquire shares of UGI Common Stock, UGI Units and other equity-based awards to key employees and non-employee directors through January 23, 2013 (except with respect to the granting of stock option awards as previously mentioned). Under the 2004 OECP, the exercise price for stock options could not be less than the fair market value on the grant date. Awards granted under the 2004 OECP could vest immediately or ratably over a period of years, and stock options could be exercised no later than ten years from the date of grant. In addition, the 2004 OECP provided that the awards of UGI Units could include the crediting of dividend equivalents.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Under the 2013 OICP, awards representing up to 14,500,000 shares of UGI Common Stock may be granted. Dividend equivalents on UGI Unit awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are accumulated in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of Common Stock and cash. UGI Unit awards granted to Antargaz employees are settled in shares of Common Stock. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions. It is currently our practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit awards. We may choose to repurchase shares on the market for such purposes during Fiscal 2014. Beginning during Fiscal 2012, options granted under the 2004 OECP, and option awards granted under the 2013 OICP, may be net exercised whereby shares equal to the option price and grantee’s minimum applicable payroll tax withholding are withheld from the number of shares payable (“net exercise”). We record shares withheld under option net exercises as shares reacquired.
UGI Stock Option Awards. Stock option transactions under the 2013 OICP, the 2004 OECP and predecessor plans during Fiscal 2011, Fiscal 2012 and Fiscal 2013 follow:
Cash received from stock option exercises and associated tax benefits were $30.8 and $12.1, $9.4 and $2.3, and $22.9 and $3.8 in Fiscal 2013, Fiscal 2012 and Fiscal 2011, respectively. As of September 30, 2013, there was $5.4 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 1.9 years.
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2013:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $4.93 in Fiscal 2013, $4.31 in Fiscal 2012 and $5.40 in Fiscal 2011. These amounts were determined using a Black-Scholes option pricing model which values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments and the risk-free interest rate over the expected life of the option. The expected life of option awards represents the period of time during which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on historical UGI dividend rates. The risk free interest rate is based on U.S. Treasury bonds with terms comparable to the options in effect on the date of grant.
The assumptions we used for valuing option grants during Fiscal 2013, Fiscal 2012 and Fiscal 2011 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 (i) companies in the Standard & Poor’s Utilities Index for grants prior to January 1, 2011 and (ii) the Russell Midcap Utility Index, excluding telecommunication companies, for grants on or after January 1, 2011 (each a respective “UGI comparator group”). For grants issued on or after January 1, 2013, grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 25th percentile compared to the UGI comparator group, the employee will not be paid. At the 40th percentile, the employee will be paid an award equal to 70% of the target award; at the 50th percentile, 100%; and at the 90th percentile, 200%. For grants issued prior to January 1, 2013, grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 40th percentile compared to the UGI comparator group, the employee will not be paid. At the 40th percentile, the employee will be paid an award equal to 50% of the target award; at the 50th percentile, 100%; and at the 100th percentile, 200%. The actual amount of the award is interpolated between these percentile rankings. Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.
The fair value of UGI Stock Units on the grant date is equal to the market price of UGI Stock on the grant date. 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
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
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 group 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 $37.97 for Units granted in Fiscal 2013, $27.25 for Units granted in Fiscal 2012 and $35.19 for Units granted in Fiscal 2011.
The following table summarizes UGI Unit award activity for Fiscal 2013:
(a)
Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2012 and Fiscal 2011 were 42,445 and 61,945, respectively.
During Fiscal 2013, Fiscal 2012 and Fiscal 2011, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
During Fiscal 2013, Fiscal 2012 and Fiscal 2011, we granted UGI Unit awards representing 254,600, 239,845 and 285,470 shares, respectively, having weighted-average grant date fair values per Unit of $37.31, $27.68 and $34.78, respectively.
As of September 30, 2013, there was a total of approximately $8.3 of unrecognized compensation cost associated with 920,601 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 2.0 years. The total fair values of UGI Units that vested during Fiscal 2013, Fiscal 2012 and Fiscal 2011 were $6.0, $3.6 and $6.8, respectively. As of September 30, 2013 and 2012, total liabilities of $8.0 and $5.0, respectively, associated with UGI Unit awards are reflected in employee compensation and benefits accrued and other noncurrent liabilities in the Consolidated Balance Sheets.
At September 30, 2013, 13,449,649 shares of Common Stock were available for future grants under the 2013 OICP, and up to 187,543 shares of Common Stock were available for future grants of stock options under the 2004 OECP.
AmeriGas Partners Equity-Based Compensation Plans and Awards. Under the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. (“2010 Propane Plan”), the General Partner may award to employees and non-employee directors grants of AmeriGas Partners Units (comprising “AmeriGas Stock Units” and “AmeriGas Performance Units”), options, unit appreciation rights and other Common Unit-based awards. The 2010 Propane Plan succeeded the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan (“2000 Propane Plan”) which expired on December 31, 2009, and replaced the AmeriGas Propane, Inc. Discretionary Long-Term Incentive Plan for Non-Executive Key Employees (“Nonexecutive Propane Plan”). 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.
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 based upon AmeriGas Partners’ Total Unitholder Return (“TUR”) percentile rank relative to entities in a peer group. Percentile rankings and payout percentages are generally the same as those used for the UGI Performance Unit awards. Any Common Unit distribution equivalents earned are paid in cash. Generally, except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed by the General Partner. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
As a result of the Heritage Acquisition, certain Heritage Propane employees were awarded AmeriGas Performance Units, AmeriGas Stock Units (in the form of phantom units), or a combination of AmeriGas Performance Units and AmeriGas Stock Units. The terms of the Performance Unit awards granted to Heritage Propane employees are generally the same as those described above. The AmeriGas Stock Units awards granted to Heritage employees vest in tranches with certain awards beginning to vest in January 2013 through January 2016. Certain of the AmeriGas Stock Unit awards provide for accelerated vesting under certain conditions. Under certain conditions all or a portion of these awards could be forfeited. The AmeriGas Stock Unit awards granted to Heritage Propane employees provide for the crediting of distribution equivalents to participants’ accounts.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Under GAAP, AmeriGas Performance Units are equity awards with a market-based condition which, if settled in Common Units, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of AmeriGas Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award and the award above the target, if any, which will be paid in Common Units, is accounted for as equity and the fair value of all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability. The expected term of the AmeriGas Performance Unit awards is three years based on the performance period. 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 limited partnerships in the peer group is based on historical volatility.
The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards and related compensation costs:
The General Partner granted awards under the 2010 Propane Plan representing 65,136, 248,818 and 49,287 Common Units in Fiscal 2013, Fiscal 2012 and Fiscal 2011, respectively, having weighted-average grant date fair values per Common Unit subject to award of $42.58, $43.22 and $53.19, respectively. At September 30, 2013, 2,484,839 Common Units were available for future award grants under the 2010 Propane Plan.
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2013:
During Fiscal 2013, Fiscal 2012 and Fiscal 2011, the Partnership paid AmeriGas Common Unit-based awards in Common Units and cash as follows:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(a) In addition, during Fiscal 2013 and 2012, 19,342 AmeriGas Stock Units and $0.5 in cash, and 40,516 AmeriGas Stock Units and $0.9 in cash, respectively, were paid to former Heritage Propane employees associated with awards granted in Fiscal 2012.
As of September 30, 2013, there was a total of approximately $3.0 of unrecognized compensation cost associated with 224,168 Common Units subject to award that is expected to be recognized over a weighted-average period of 1.8 years. The total fair value of Common Unit-based awards that vested during Fiscal 2013, Fiscal 2012 and Fiscal 2011 was $2.8, $5.1 and $2.0, respectively. As of September 30, 2013 and 2012, total liabilities of $1.1 and $1.1 associated with Common Unit-based awards are reflected in employee compensation and benefits accrued and other noncurrent liabilities in the Consolidated Balance Sheets.
Note 15 - Partnership Distributions and Common Unit Offerings
The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash (as defined in the Partnership Agreement) for such quarter. Available Cash generally means:
1.
all cash on hand at the end of such quarter,
2.
plus all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter,
3.
less the amount of cash reserves established by the General Partner in its reasonable discretion.
The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the next four quarters.
Distributions of Available Cash are made 98% to limited partners and 2% to the General Partner (representing a 1% General Partner interest in AmeriGas Partners and 1.01% interest in AmeriGas OLP) until Available Cash exceeds the Minimum Quarterly Distribution of $0.55 and the First Target Distribution of $0.055 per Common Unit (or a total of $0.605 per Common Unit). When Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner will receive a greater percentage of the total Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common Unit to limited partners exceeds $0.605.
During Fiscal 2013, Fiscal 2012 and Fiscal 2011, 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. The total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $27.4 in Fiscal 2013, $19.7 in Fiscal 2012 and $9.0 in Fiscal 2011. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2013, Fiscal 2012 and Fiscal 2011 of $19.3, $13.0 and $5.0, respectively.
In March 2012, AmeriGas Partners sold 7,000,000 Common Units in an underwritten public offering at a public offering price of $41.25 per unit. The net proceeds of the public offering totaling $276.6 and the associated capital contributions from the General Partner totaling $2.8 were used to redeem $200 of 6.50% Senior Notes pursuant to a tender offer (see Note 6), to reduce bank loan borrowings and for general partnership purposes.
Note 16 - Commitments and Contingencies
Commitments
We lease various buildings and other facilities and vehicles, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $82.5 in Fiscal 2013, $77.9 in Fiscal 2012 and $69.8 in Fiscal 2011.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Minimum future payments under operating leases with non-affiliates that have initial or remaining noncancelable terms in excess of one year are as follows:
Our businesses enter into contracts of varying lengths and terms to meet their supply, pipeline transportation, storage, capacity and energy needs. Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation and natural gas storage services, which Gas Utility may terminate at various dates through Fiscal 2025. Gas Utility’s costs associated with transportation and storage capacity agreements are included in its annual PGC filings with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices. Electric Utility purchases its electricity needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2014. Midstream & Marketing enters into fixed-price contracts with suppliers to purchase natural gas and electricity to meet its sales commitments. Generally, these contracts have terms of less than two years. The Partnership enters into fixed-price and variable-price contracts to purchase a portion of its supply requirements. These contracts currently have terms that do not exceed three years. UGI International enters into fixed-price and variable-priced contracts to purchase a portion of its supply requirements that currently do not exceed three years.
The following table presents contractual obligations with non-affiliates under Gas Utility, Electric Utility, Midstream & Marketing, AmeriGas Propane and UGI International supply, storage and service contracts existing at September 30, 2013:
The Partnership and UGI International also enter into other contracts to purchase LPG to meet supply requirements. Generally, these contracts are one- to three-year agreements subject to annual price and quantity adjustments.
Contingencies
Environmental Matters
UGI Utilities
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA is currently scheduled to terminate at the end of 2013. The PNG-COA terminates in 2019 but may be terminated
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At September 30, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14.0 and $15.0, respectively. Because CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites, in accordance with GAAP related to rate-regulated entities we have recorded associated regulatory assets in equal amounts.
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At September 30, 2013, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.
From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.
Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount or range of possible clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska, and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012. There have been no recent developments in this matter.
AmeriGas Propane
AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac Lake, New York, on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by DEC disclosed contamination related to former MGP operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership has researched the history of the site and its ownership interest in the site. The Partnership has reviewed the preliminary site characterization study prepared by the DEC, the extent of contamination and the possible existence of other potentially responsible parties. The Partnership communicated the results of its research to DEC in January 2009. There have been no recent developments in this matter. Because of the preliminary nature of available environmental information, the ultimate amount or range of possible clean up costs cannot be reasonably estimated.
Claremont, New Hampshire and Chestertown, Maryland. In connection with the Heritage Acquisition on January 12, 2012, a predecessor of Titan Propane LLC (“Titan LLC”), a former subsidiary acquired in the Heritage Acquisition, is purportedly the beneficial holder of title with respect to two former MGPs discussed below. The Contribution Agreement provides for indemnification from ETP for certain expenses associated with remediation of these sites. By letter dated September 30, 2010, the EPA notified Titan LLC that it may be a potentially responsible party (“PRP”) for clean up costs associated with contamination
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
at a former MGP in Claremont, New Hampshire. In June 2010, the Maryland Attorney General (“MAG”) identified Titan LLC as a PRP in connection with contamination at a former MGP in Chestertown, Maryland and requested that Titan LLC participate in characterization and remediation activities. Titan LLC has supplied the EPA and MAG with corporate and bankruptcy information for its predecessors to support its claim that it is not liable for any remediation costs at the sites. Because of the preliminary nature of available environmental information, the ultimate amount or range of possible clean up costs cannot be reasonably estimated.
Other Matters
AmeriGas Cylinder Investigation. On or about October 21, 2009, the General Partner received a notice that the Offices of the District Attorneys of Santa Clara, Sonoma, Ventura, San Joaquin and Fresno Counties and the City Attorney of San Diego (the “District Attorneys”) had commenced an investigation into AmeriGas OLP's cylinder labeling and filling practices in California as a result of the Partnership’s decision in 2008 to reduce the volume of propane from 17 pounds to 15 pounds in the cylinders it provides to retailers who then sell them to consumers. At that time, the District Attorneys issued an administrative subpoena seeking documents and information relating to those practices. We have responded to the administrative subpoena. On or about July 20, 2011, the General Partner received a second subpoena from the District Attorneys. The subpoena sought additional information and documents regarding AmeriGas OLP’s cylinder exchange program. We responded to that subpoena. In connection with this matter, the District Attorneys have alleged potential violations of California's antitrust and unfair competition laws, California’s slack-fill law, and California’s principal false advertising statute. On November 20, 2013, the District Attorneys filed a complaint against the General Partner and AmeriGas OLP and simultaneously filed a proposed stipulated final consent judgment (the “Judgment”) which was approved by the court on December 2, 2013 and resolved all claims against those defendants that were known to the District Attorneys at that time. The Judgment requires the General Partner to pay a civil penalty and to certain injunctive relief including the posting of a consumer notice on all cylinder cages in California. That notice informs consumers, among other things, of the reduction of propane in weight from 17 pounds to 15 pounds. The Judgment will not have a material effect on our consolidated financial position, results of operations or cash flows.
Federal Trade Commission Investigation of Propane Grill Cylinder Filling Practices. On or about November 4, 2011, the General Partner received notice that the Federal Trade Commission (“FTC”) is conducting an antitrust and consumer protection investigation into certain practices of the Partnership that relate to the filling of portable propane cylinders. On February 2, 2012, the Partnership received a Civil Investigative Demand from the FTC that requested documents and information concerning, among other things, (i) the Partnership’s decision, in 2008, to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds and (ii) cross-filling, related service arrangements and communications regarding the foregoing with competitors. The Partnership responded to that subpoena and has continued to cooperate with the FTC’s requests for information. The Partnership believes it has good defenses to any claims that may result from this investigation. We are not able to assess the financial impact this investigation or any related claims may have on the Partnership.
Purported Class Action Lawsuit. In 2005, Samuel and Brenda Swiger (the “Swigers”) filed what purports to be a class action lawsuit in the Circuit Court of Harrison County, West Virginia, against UGI, an insurance subsidiary of UGI, certain officers of UGI and the General Partner, and their insurance carriers and insurance adjusters. In this lawsuit, the Swigers are seeking compensatory and punitive damages on behalf of the putative class for alleged violations of the West Virginia Insurance Unfair Trade Practice Act, negligence, intentional misconduct, and civil conspiracy. The Court has not certified the class. We believe we have good defenses to the claims in this action.
Antargaz Competition Authority Matter. On July 21, 2009, Antargaz received a Statement of Objections (“Statement”) from France’s Autorité de la concurrence (“Competition Authority”) with respect to the investigation of Antargaz by the General Division of Competition, Consumption and Fraud Punishment. The Statement alleged that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. On December 17, 2010, the Competition Authority issued its decision dismissing all objections against Antargaz. The appeal period expired without an appeal being filed. As a result of the decision, during the three-month period ended December 31, 2010, the Company reversed its previously recorded nontaxable accrual for this matter which increased Fiscal 2011 net income by $9.4.
We cannot predict the final results of any of the environmental or other pending claims or legal actions described above. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements in amounts in excess of recorded amounts, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. In addition to the matters described above, there are other
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
pending claims and legal actions arising in the normal course of our businesses. We believe, after consultation with counsel, the final outcome of such other matters will not have a material effect on our consolidated financial position, results of operations or cash flows.
Note 17 - Fair Value Measurements
Derivative Financial Instruments
The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of September 30, 2013 and 2012:
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 financial instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 which are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. There were no transfers between Level 1 and Level 2 during the periods presented.
Other Financial Instruments
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. At September 30, 2013, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,609.4 and $3,761.8, respectively. At September 30, 2012, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,514.3 and $3,787.6, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2).
Financial instruments other than derivative financial instruments, such as our short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit our credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 18. Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value.
Note 18 - Disclosures About 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. A substantial portion of our derivative financial instruments, other than commodity derivative instruments at Midstream & Marketing, are designated and qualify as cash flow hedges or net investment hedges. Substantially all of Midstream & Marketing’s commodity derivative instruments are not accounted for as hedges under GAAP. Because a substantial portion of our derivative instruments qualify for and are designated as hedges under GAAP or are subject to regulatory rate recovery mechanisms, we expect that changes in the fair value of derivative instruments used to manage commodity, interest rate or currency exchange rate risk would be substantially offset by gains or losses on the associated anticipated transactions.
Commodity Price Risk
In order to manage market price risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane principally during the months of October through March, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units and our UGI International operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. In addition, the Partnership from time to time enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility which agreements are generally not designated as hedges for accounting purposes.
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 15.0 million dekatherms and 19.2 million dekatherms, respectively. At September 30, 2013, the maximum period over which Gas Utility is hedging natural gas market price risk is 12 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 9).
Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At September 30, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $4.8
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
and $9.2, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At September 30, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts were 245.8 million kilowatt hours and 570.4 million kilowatt hours, respectively. At September 30, 2013, the maximum period over which these contracts extend is 8 months.
In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 9). 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. At September 30, 2013 and 2012, the volumes associated with Electric Utility FTRs totaled 189.3 million kilowatt hours and 189.7 million kilowatt hours, respectively. Midstream & Marketing’s FTRs and capacity swap contracts are recorded at fair value with changes in fair value reflected in cost of sales. At September 30, 2013 and 2012, the volumes associated with Midstream & Marketing’s FTRs and NYISO capacity swap contracts totaled 1,401.9 million kilowatt hours and 988.8 million kilowatt hours, respectively.
In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures contracts, IntercontinentalExchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over the counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Substantially all of Midstream & Marketing’s derivative financial instruments described above are not accounted for as hedges under GAAP. These derivative instruments are recorded at fair value with changes in fair value reflected in income. As a result, volatility in Midstream and Marketing’s results can occur due to changes in the fair value of unsettled derivative instruments. Volatility can also occur as a result of timing differences between the settlement of financial derivatives and the sale or purchase of the corresponding physical commodity that was economically hedged.
At September 30, 2013 and September 30, 2012, total volumes associated with Midstream & Marketing’s natural gas futures contracts associated with forecasted purchases of natural gas totaled 24.3 million dekatherms and 23.6 million dekatherms, respectively. At September 30, 2013 and 2012, total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 754.4 million kilowatt hours and 393.0 million kilowatt hours, and 1,415.7 million kilowatt hours and 135.3 million kilowatt hours, respectively. At September 30, 2013, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 2.9 million dekatherms and 2.8 million gallons, respectively. At September 30, 2012, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 4.3 million dekatherms and 3.1 million gallons, respectively.
In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. Associated volumes, fair values and effects on net income were not material for all periods presented.
At September 30, 2013 and 2012, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:
At September 30, 2013, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 24 months with a weighted average of 6 months and the maximum period over which
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 24 months for electricity forward purchase contracts, with a weighted average of 8 months.
We account for commodity price risk contracts (other than Midstream & Marketing’s contracts that are not designated as accounting hedges and Gas Utility and Electric Utility contracts that are subject to regulatory treatment) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales in the Consolidated Statements of Income. At September 30, 2013, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $13.6.
Interest Rate Risk
Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its term loans, in each case through the respective scheduled maturity dates. As of September 30, 2013 and 2012, the total notional amounts of variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) were €440.5 and €441.9, respectively.
Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At September 30, 2013, we had no unsettled IRPAs. At September 30, 2012, the total notional amount of unsettled IRPAs was $173.0.
During Fiscal 2012, UGI Utilities reclassified pre-tax losses of $0.7 from AOCI into income as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in other income, net, in the 2012 Consolidated Statement of Income.
We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values of interest rate swaps and IRPAs are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At September 30, 2013, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $2.7.
Foreign Currency Exchange Rate Risk
In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At September 30, 2013 and 2012, we were hedging a total of $200.2 and $174.5 of U.S. dollar-denominated LPG purchases, respectively. At September 30, 2013, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 30 months with a weighted average of 11 months. From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At September 30, 2013 and 2012, we had no euro-dominated net investment hedges.
We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At September 30, 2013, the amount of net losses associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $2.5. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
From time to time, the Company may enter into foreign currency exchange transactions to economically hedge the local-currency purchase price of anticipated foreign business acquisitions. These transactions do not qualify for hedge accounting treatment and any changes in fair value are recorded in other income, net.
Cross-Currency Swaps
During Fiscal 2013, Flaga entered into a cross-currency swap to hedge its exposure to the variability in expected future cash flows associatd with foreign currency and interest rate risk resulting from the issuance of $52.0 million of U.S. dollar denominated variable-rate debt. The cross-currency hedge includes initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. The cross-currency swap also includes an interest rate swap of a fixed foreign-denominated interest rate to a fixed U.S. denominated interest rate. We have designated this cross-currency swap as a cash flow hedge. Changes in the fair value of our cross-currency swap is recorded in AOCI to the extent effective in offsetting changes in the underlying foreign currency exchange and interest rate risk. At September 30, 2013, the amount of net losses associated with this cross-currency swap expected to be reclassified into earnings over the next twelve months is not material.
Derivative Financial Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2013 and 2012, restricted cash in brokerage accounts totaled $7.0 and $3.0, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at September 30, 2013. 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, 2013, 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
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following table provides information regarding the balance sheet location and fair value of derivative assets and liabilities existing as of September 30, 2013 and 2012:
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Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following tables provide information on the effects of derivative instruments in the Consolidated Statement of Income and changes in AOCI and noncontrolling interest for Fiscal 2013 and 2012:
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 2013, Fiscal 2012 and Fiscal 2011.
As a result of the Partnership’s refinancing of its 7.125% Senior Notes (see Note 6), during the three months ended September 30, 2011, the Partnership discontinued cash flow hedge accounting for settled but unamortized IRPA losses associated with AmeriGas Partners Senior Notes and recorded a loss of $2.6 which amount is included in loss on extinguishments of debt on the Fiscal 2011 Consolidated Statement of Income.
We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery, or sale, of natural gas, LPG and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchases and normal sales exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
Note 19 - Energy Services Accounts Receivable Securitization Facility
At September 30, 2013, Energy Services had a $100 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper. Prior to its scheduled expiration on November 1, 2013, Energy Services extended its Receivables Facility until October 31, 2014, and amended the Receivables Facility to better align its borrowing limits with
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Energy Services’ seasonal borrowing needs. The Receivables Facility, as amended, provides Energy Services with the ability to borrow up to $150 million of eligible receivables during the period November 1, 2013 to May 31, 2014, and up to $75 million of eligible receivables during the period June 1, 2014 to October 31, 2014.
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 commercial paper conduit of a major bank (through September 30, 2013) and, subsequent to September 30, 2013, to the bank itself . ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the commercial paper conduit or the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit or the bank. The Company records interest expense on amounts owed to the commercial paper conduit or the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC.
During Fiscal 2013, Fiscal 2012 and Fiscal 2011, Energy Services transferred trade receivables totaling $975.3, $836.0 and $1,134.9, respectively, to ESFC. During Fiscal 2013, Fiscal 2012 and Fiscal 2011, ESFC sold an aggregate $291.0, $286.0 and $88.0, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At September 30, 2013, the outstanding balance of ESFC trade receivables was $55.0 of which $30.0 was sold to the commercial paper conduit and reflected on the Consolidated Balance Sheet as bank loans. At September 30, 2012, the outstanding balance of ESFC trade receivables was $43.5 of which no amount was sold to the commercial paper conduit. Losses on sales of receivables to the commercial paper conduit during Fiscal 2013, Fiscal 2012 and Fiscal 2011, which amounts are included in interest expense on the Consolidated Statements of Income, totaled $0.7, $1.0 and $1.2, respectively.
Note 20 - Other Income, Net
Other income, net, comprises the following:
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 21 - Quarterly Data (unaudited)
The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) which we consider necessary for a fair presentation unless otherwise indicated and reflects the revisions or restatements to correct the errors described in Note 3. Our quarterly results fluctuate because of the seasonal nature of our businesses.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The impacts of the corrections on the key financial metrics operating income (loss), net income (loss) attributable to UGI Corporation and diluted earnings (loss) per share for each of the relevant quarters in the two years ended September 30, 2013 is are follows:
(1) Other adjustments principally relate to the timing of certain expense and income accruals. Other diluted earnings (loss) per share attributable to UGI Corporation stockholders also includes the impact of rounding.
The adjustments reflected in the tables above did not affect cash flows from operating activities, investing activities or financing activities for any of the quarterly periods. In addition, the adjustments above relating to the Midstream & Marketing hedge accounting did not affect total stockholders’ equity as these adjustments resulted in changes to accumulated other comprehensive income and retained earnings in equal and offsetting amounts. In addition, the adjustments related to Midstream & Marketing hedge accounting had no effect on consolidated assets and liabilities. The Partnership customer credits and other adjustments did not have a material effect on the consolidated balance sheets for all periods presented.
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(a)
Includes impairment loss on private equity partnership investment which increased operating loss by $6.3 and net loss attributable to UGI Corporation by $3.7 or $0.03 per share (see Note 2).
(b)
Includes adjustment to foreign tax credit valuation allowance which increased net income by $5.5 or $0.05 per diluted share (see Note 7).
(c)
Includes loss on extinguishment of Partnership long-term debt which decreased net income attributable to UGI Corporation by $2.2 or $0.02 per diluted share (see Note 6).
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 22 - Segment Information
Our operations comprise six reportable segments generally based upon products sold, geographic location and regulatory environment. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) Gas Utility; (5) Energy Services; and (6) Electric Generation. We refer to both international segments together as “UGI International” and Energy Services and Electric Generation together as “Midstream & Marketing.”
AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers in all 50 states. Antargaz’ revenues are derived principally from the distribution of LPG to retail customers in France and, to a much lesser extent, Belgium, the Netherlands and Luxembourg. Flaga & Other revenues are derived principally from the distribution of LPG to customers in northern, central and eastern Europe and the United Kingdom. Gas Utility’s revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Energy Services revenues are derived from the sale of natural gas and, to a lesser extent, LPG, electricity and fuel oil as well as storage and other energy services to customers located primarily in the Mid-Atlantic region of the United States. Electric Generation revenues are derived principally from the sale of electricity through PJM, a regional electricity transmission organization in the eastern U.S.
The accounting policies of our reportable segments are the same as those described in Note 2. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership 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 EBITDA may be different from that used by other companies. We evaluate the performance of our other reportable segments principally based upon their income before income taxes.
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.
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Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
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Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
(a)
The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:
(i)
Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(b)
Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments and gains and losses on settled commodity derivative instruments not associated with current period transactions, (4) net expenses of UGI’s captive general liability insurance company, and (5) UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
(c)
Represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
BALANCE SHEETS
(Millions of dollars)
(a) Investments in subsidiaries and common stockholder’s equity have been revised to reflect the effects of corrections to consolidated financial statements (see Note 3 to Consolidated Financial Statements).
Note 1 - Commitments and Contingencies:
In addition to the guarantees of Flaga’s and Antargaz’ debt as described in Note 6 to Consolidated Financial Statements, at September 30, 2013, UGI Corporation had agreed to indemnify the issuers of $52.5 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $425.0 of obligations to suppliers and customers of UGI Energy Services, Inc. and subsidiaries of which $368.6 of such obligations were outstanding as of September 30, 2013. UGI Corporation has guaranteed the floating to fixed rate interest rate swaps at Flaga which obligations totaled $4.3 at September 30, 2013.
S-1
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
(a) Equity in income of unconsolidated subsidiaries have been revised to reflect the effects of corrections to consolidated financial statements (see Note 3 to Consolidated Financial Statements).
(1)
UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers the relative percentage of such items for each subsidiary to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to its subsidiaries. These billed expenses are classified as “Other income, net” in the Statements of Income above.
S-2
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(Millions of dollars)
(a)
Includes dividends received from unconsolidated subsidiaries of $155.2, $156.0 and $188.9, for the years ended September 30, 2013, 2012 and 2011, respectively.
S-3
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)
Acquisition.
S-4
EXHIBIT INDEX