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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
| ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2009
Commission file number 1-1398
UGI UTILITIES, INC.
(Exact Name of Registrant as Specified in Its Charter)
| Pennsylvania | 23-1174060 | |
| (State or Other Jurisdiction of | (I.R.S. Employer | |
| Incorporation or Organization) | Identification No.) |
P. O. Box 1267, 2525 N. 12th Street, Suite 360
Reading, PA 19612
(Address of Principal Executive Offices) (Zip Code)
Reading, PA 19612
(Address of Principal Executive Offices) (Zip Code)
(610) 796-3400
(Registrant’s telephone number, including area code)
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:None
Securities registered pursuant to Section 12(g) of the Act:None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yesþ Noo
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso Noo
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filero | Accelerated filero | Non-accelerated filerþ | Smaller reporting companyo |
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso Noþ
At September 30, 2009, there were 26,781,785 shares of UGI Utilities Common Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI Corporation.
The Registrant meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format permitted by that General Instruction.
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FORWARD-LOOKING INFORMATION
Information contained in this Annual Report on Form 10-K may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability of oil, electricity and natural gas and the capacity to transport them to market areas; (3) changes in laws and regulations, including safety, tax and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability for environmental claims; (8) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor relations; (10) large customer, counterparty or supplier defaults; (11) increased uncollectible accounts expense; (12) liability for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas, including liability in excess of insurance coverage; (13) political, regulatory and economic conditions in the United States; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity market prices resulting in significantly higher cash collateral requirements.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.
PART I:
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
UGI Utilities, Inc. (“UGI Utilities” or the “Company”) is a public utility company that owns and operates three natural gas distribution utilities and an electric utility in Pennsylvania. We are a wholly owned subsidiary of UGI Corporation (“UGI”).
On October 1, 2008, UGI Utilities completed the acquisition of all of the issued and outstanding stock of PPL Gas Utilities Corporation (“PPL Gas”), the natural gas distribution utility of PPL Corporation, and its wholly owned subsidiary, Penn Fuel Propane, LLC (“Penn Fuel Propane”). Immediately following the closing of the acquisition, Penn Fuel Propane sold its retail propane distribution assets to AmeriGas Propane, L.P., an affiliate of UGI. PPL Gas, now known as UGI Central Penn Gas, Inc. (“CPG”), distributes natural gas to approximately 76,000 customers in 34 counties in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. On August 24, 2006, UGI Utilities, through its subsidiary UGI Penn Natural Gas, Inc. (“PNG”), acquired the natural gas distribution business of Southern Union Company’s PG Energy Division, which significantly increased our natural gas distribution business in northeastern Pennsylvania.
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The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of UGI Utilities, PNG, and CPG. Gas Utility serves approximately 563,000 customers in eastern, northeastern, and central Pennsylvania. UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” Beginning Fiscal 2009, CPG was included in the Company’s Gas Utility segment. See Note 4 to Consolidated Financial Statements. The Electric Utility segment (“Electric Utility”) consists of the regulated electric distribution business of UGI Utilities, serving approximately 62,000 customers in northeastern Pennsylvania. Gas Utility is regulated by the Pennsylvania Public Utility Commission (“PUC”) and the Maryland Public Service Commission. Electric Utility is regulated by the PUC.
UGI Utilities was incorporated in Pennsylvania in 1925. Our executive offices are located at P. O. Box 12677, 2525 N. 12th Street, Suite 360, Reading, Pennsylvania 19612, and our telephone number is (610) 796-3400. In this report, the terms “Company” and “UGI Utilities,” as well as the terms, “our,” “we,” and “its,” are sometimes used to refer to UGI Utilities, Inc. or, collectively UGI Utilities, Inc. and its consolidated subsidiaries. The terms “Fiscal 2009” and “Fiscal 2008” refer to the fiscal years ended September 30, 2009 and September 30, 2008, respectively.
GAS UTILITY
Service Area; Revenue Analysis
Gas Utility is authorized to distribute natural gas to approximately 563,000 customers in portions of 45 eastern, northeastern and central Pennsylvania counties through its distribution system of approximately 11,900 miles of gas mains. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock Haven, Pittston, Pottsville and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility’s service area are major production centers for basic industries such as specialty metals, aluminum, glass and paper product manufacturing.
System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2009 was approximately 150 billion cubic feet (“bcf”). System sales of gas accounted for approximately 44% of system throughput, while gas transported for residential, commercial and industrial customers (who bought their gas from others) accounted for approximately 56% of system throughput.
Sources of Supply and Pipeline Capacity
Gas Utility meets its service requirements by utilizing a diverse mix of natural gas purchase contracts with marketers and producers, along with storage and transportation service contracts. These arrangements enable Gas Utility to purchase gas from Gulf Coast, Mid-Continent, Appalachian and Canadian sources. For the transportation and storage function, Gas Utility has long-term agreements with a number of pipeline companies, including Texas Eastern Transmission Corporation, Columbia Gas Transmission Corporation, Transcontinental Gas Pipeline Corporation, Dominion Transmission, ANR Pipeline and Tennessee Gas Pipeline.
Gas Supply Contracts
During Fiscal 2009, Gas Utility purchased approximately 94 bcf of natural gas for sale to retail core-market customers (principally comprised of firm- residential, commercial and industrial 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) and off-system sales customers. Approximately 77% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 23% of gas purchased by Gas Utility was supplied by approximately 20 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 1 year. Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the months of November through March.
Seasonality
Because many of its customers use gas for heating purposes, Gas Utility sales are seasonal. Approximately 65% to 70% of Gas Utility’s sales volume is supplied, and approximately 85% to 90% of Gas Utility’s operating income is earned, during the peak heating season from October through March.
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Competition
Natural gas is a fuel that competes with electricity and oil, and to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of fuel utilization equipment. In parts of Gas Utility’s service area, electricity may have a competitive price advantage over natural gas due to government regulated rate caps on electricity. Rate caps for electric utilities serving a significant portion of Gas Utility’s service territory are currently scheduled to expire at the end of 2009 and 2010 which will likely result in electricity losing all or some of its competitive price advantage. Additionally, high efficiency electric heat pumps have led to a decrease in the cost of heating with electricity. Government subsidies currently favor ground source heat pumps over fossil fueled systems. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility responds to this competition with marketing efforts designed to retain and grow its customer base.
In substantially all of its service territories, Gas Utility is the only regulated gas distribution utility having the right, granted by the PUC or by law, to provide gas distribution services. Since the 1980s, larger commercial and industrial customers have been able to purchase gas supplies from entities other than natural gas distribution utility companies. As a result of Pennsylvania’s Natural Gas Choice and Competition Act, effective July 1, 1999 all of Gas Utility’s customers, including retail core-market customers, have been afforded this opportunity.
A number of Gas Utility’s commercial and industrial customers have the ability to switch to an alternate fuel at any time and, therefore, are served on an interruptible basis under rates which are competitively priced with respect to the alternate fuel. Margin from these customers, therefore, is affected by the difference or “spread” between the customers’ delivered cost of gas and the customers’ delivered cost of the alternate fuel, as well as the frequency and duration of interruptions. See “Gas Utility and Electric Utility Regulation and Rates — Gas Utility Rates.” Approximately 24% of Gas Utility’s commercial and industrial customers’ annual throughput volume, including certain customers served under interruptible rates, have locations which afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. The majority of customers in this group are served under transportation contracts having 3 to 20 year terms. Included in these two customer groups are 25 customers, most of which are among the 10 largest customers for each of UGI Gas, PNG and CPG in terms of annual volumes. All of these customers have contracts, 19 of which extend beyond the 2010 fiscal year. No single customer represents, or is anticipated to represent, more than 5% of Gas Utility’s total revenues.
Outlook for Gas Service and Supply
Gas Utility anticipates having adequate pipeline capacity and sources of supply available to it to meet the full requirements of all firm customers on its system through fiscal year 2010. Supply mix is diversified, market priced, and delivered pursuant to a number of long-term and short-term firm transportation and storage arrangements, including transportation contracts held by some of Gas Utility’s larger customers.
During Fiscal 2009, Gas Utility supplied transportation service to 2 major co-generation installations and 5 electric generation facilities. Gas Utility continues to pursue opportunities to supply natural gas to electric generation projects located in its service area. Gas Utility also continues to seek new residential, commercial and industrial customers for both firm and interruptible service. In the residential market sector, Gas Utility connected approximately 10,700 residential heating customers during Fiscal 2009. These customers consisted primarily of (1) customers converting from other energy sources, mainly oil and electricity, (2) existing non-heating gas customers who have added gas heating systems to replace other energy sources and (3) new home construction customers. As a result of the decline in the real estate market, customers from new home construction decreased approximately 24% compared to Fiscal 2008. If the slowdown in new home construction continues in fiscal year 2010 in Gas Utility’s service area, customer growth will be adversely affected.
UGI Utilities continues to monitor and participate, where appropriate, in rulemaking and individual rate and tariff proceedings before FERC affecting the rates and the terms and conditions under which Gas Utility transports and stores natural gas. Among these proceedings are those arising out of certain FERC orders and/or pipeline filings which relate to (1) the pricing of pipeline services in a competitive energy marketplace; (2) the flexibility of the terms and conditions of pipeline service tariffs and contracts; and (3) pipelines’ requests to increase their base rates, or change the terms and conditions of their storage and transportation services.
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UGI Utilities’ objective in negotiations with interstate pipeline and natural gas suppliers, and in proceedings before regulatory agencies, is to assure availability of supply, transportation and storage alternatives to serve market requirements at the lowest cost possible, taking into account the need for security of supply. Consistent with that objective, UGI Utilities negotiates the terms of firm transportation capacity on all pipelines serving it, arranges for appropriate storage and peak-shaving resources, negotiates with producers for competitively priced gas purchases and aggressively participates in regulatory proceedings related to transportation rights and costs of service.
ELECTRIC UTILITY
Service Area; Sales Analysis
Electric Utility supplies electric service to approximately 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania through a system consisting of approximately 2,150 miles of transmission and distribution lines and 13 transmission substations. For Fiscal 2009, approximately 54% of sales volume came from residential customers, 34% from commercial customers and 12% from industrial and other customers. Sales of electricity for residential heating purposes accounted for approximately 19% of total sales of electricity during Fiscal 2009.
Sources of Supply
In accordance with Electric Utility’s default service settlement with the PUC effective January 1, 2010, Electric Utility will be permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with the PUC. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures” and Note 5 to Consolidated Financial Statements. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers, if any. See “Gas Utility and Electric Utility Regulation and Rates — Electric Utility Rates.”
As of September 30, 2009, 17 of Electric Utility’s customers have selected an alternative electricity generation supplier. Beginning in 2010, while Electric Utility expects to see an increasing number of customers selecting alternative electricity generation suppliers, it will continue to provide energy to the majority of its distribution customers for the foreseeable future.
Competition
As a result of the Electricity Generation Customer Choice and Competition Act (“ECC Act”), all Pennsylvania retail electric customers have the ability to choose their electric generation supplier. Electric Utility remains the provider of last resort (“POLR”) for its customers who do not choose an alternate electric generation supplier. In Fiscal 2009, Electric Utility served nearly all of the electric customers within its service territory and is the only regulated electric utility having the right, granted by the PUC or by law, to distribute electricity in its service territory. Electricity competes with natural gas, oil, propane and other heating fuels for residential heating purposes.
The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service, have been established in a series of PUC-approved settlements (the “POLR Settlements”). Consistent with the terms of the POLR Settlements, Electric Utility’s total average residential heating customer POLR rates were increased in January 2009 by approximately 1.5% over rates in effect during calendar year 2008. For current rates, see “Gas Utility and Electric Utility Regulation and Rates — Electric Utility Rates.” Beginning January 1, 2010, Electric Utility will be assured recovery of prudently incurred costs and will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues, but will, however, forego the opportunity to recover revenues in excess of actual costs.
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GAS UTILITY AND ELECTRIC UTILITY REGULATION AND RATES
Pennsylvania Public Utility Commission Jurisdiction
UGI Utilities’ gas and electric utility operations are subject to regulation by the PUC as to rates, terms and conditions of service, accounting matters, issuance of securities, contracts and other arrangements with affiliated entities, and various other matters.
Electric Transmission and Wholesale Power Sale Rates
FERC has jurisdiction over the rates and terms and conditions of service of electric transmission facilities used for wholesale or retail choice transactions. Electric Utility owns electric transmission facilities that are within the control area of the PJM Interconnection, LLC (“PJM”) and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. PJM is a regional transmission organization that regulates and coordinates generation supply and the wholesale delivery of electricity. Electric Utility receives certain revenues collected by PJM, determined under a formulary rate schedule that is adjusted in June of each year to reflect annual changes in Electric Utility’s electric transmission revenue requirements, when its transmission facilities are used by third parties.
FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy. Electric Utility has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates.
Gas Utility Rates
The most recent general base rate increase for UGI Gas became effective in 1995. In accordance with a statutory mechanism, a rate increase for Gas Utility’s retail core-market customers became effective October 1, 2000 along with a Purchased Gas Cost (“PGC”) variable credit equal to a portion of the margin received from customers served under interruptible rates to the extent such interruptible customers use capacity contracted for by UGI Gas for retail core-market customers.
On August 27, 2009, the PUC approved PNG’s and CPG’s rate case settlement agreements, which resulted in a $19.75 million base rate operating revenue increase for PNG and a $10 million base rate operating revenue increase for CPG. The increases became effective on August 28, 2009.
The gas service tariffs for UGI Gas, PNG and CPG contain PGC rates applicable to firm retail rate schedules. These PGC rates permit recovery of substantially all of the prudently incurred costs of natural gas that UGI Gas, PNG, and CPG sell to their customers. PGC rates are reviewed and approved annually by the PUC. UGI Gas, PNG, and CPG may request quarterly or, under certain conditions, monthly adjustments to reflect the actual cost of gas. Quarterly adjustments become effective on 1 day’s notice to the PUC and are subject to review during the next annual PGC filing. Each proposed annual PGC rate is required to be filed with the PUC 6 months prior to its effective date. During this period, the PUC holds hearings to determine whether the proposed rate reflects a least-cost fuel procurement policy consistent with the obligation to provide safe, adequate and reliable service. After completion of these hearings, the PUC issues an order permitting the collection of gas costs at levels which meet that standard. The PGC mechanism also provides for an annual reconciliation.
UGI Gas has two PGC rates. PGC (1) is applicable to small, firm, retail core-market customers consisting of the residential and small commercial and industrial classes; PGC (2) is applicable to firm, contractual, high-load factor customers served on three separate rates. PNG and CPG each have one PGC rate applicable to all customers. See Note 5 to Consolidated Financial Statements.
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Electric Utility Rates
The most recent general base rate increase for Electric Utility became effective in 1996. Electric Utility’s rates were unbundled into distribution, transmission and generation (POLR or “default service”) components in 1998. In accordance with the POLR Settlements, Electric Utility increased POLR rates annually from 2005 through 2009. The increase implemented January 1, 2009 raised total average residential heating customer rates by approximately 1.5% over rates in effect during calendar year 2008. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its customers.
PUC default service regulations are applicable to Electric Utility’s provision of default service effective January 1, 2010. Electric Utility, consistent with these regulations, acquired a portion of its default service supplies for certain customer groups for the period of January 1, 2010 through April 30, 2014. Electric Utility received approval from the PUC of (1) default service tariff rules applicable for service rendered on or after January 1, 2010, (2) a reconcilable default service cost rate recovery mechanism to become effective January 1, 2010, (3) a plan for meeting the post-2009 requirements of the Alternative Energy Portfolio Standards Act (“AEPS Act”), which requires Electric Utility to directly or indirectly acquire certain percentages of its supplies from designated alternative energy sources and (4) a reconcilable AEPS Act cost recovery rate mechanism to become effective January 1, 2010. Under these rules, default service rates for most customers will be adjusted quarterly.
FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers
Both Gas Utility and Electric Utility are subject to FERC regulations governing the manner in which certain jurisdictional sales or transportation are conducted. Section 4A of the Natural Gas Act and Section 222 of the Federal Power Act prohibit the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of natural gas, electric energy, or natural gas transportation or electric transmission services subject to the jurisdiction of FERC. FERC has adopted regulations to implement these statutory provisions which apply to interstate transportation and sales by the Electric Utility, and to a much more limited extent, to certain sales and transportation by the Gas Utility that are subject to FERC’s jurisdiction. Gas Utility and Electric Utility are subject to certain other regulations and obligations for FERC-regulated activities. Under provisions of the Energy Policy Act of 2005 (“EPACT 2005”), Electric Utility is subject to certain electric reliability standards established by FERC and administered by an Electric Reliability Organization (“ERO”). Electric Utility anticipates that substantially all the costs of complying with the ERO standards will be recoverable through its PJM formulary electric transmission rate schedule.
EPACT 2005 also granted FERC authority to impose substantial civil penalties for the violation of any regulations, orders or provisions under the Federal Power Act and Natural Gas Act, and clarified FERC’s authority over certain utility or holding company mergers or acquisitions of electric utilities or electric transmitting utility property valued at $10 million or more.
State Tax Surcharge Clauses
UGI Utilities’ gas and electric service tariffs contain state tax surcharge clauses. The surcharges are recomputed whenever any of the tax rates included in their calculation are changed. These clauses protect UGI Utilities from the effects of increases in most of the Pennsylvania taxes to which it is subject.
Utility Franchises
UGI Utilities, PNG and CPG each hold certificates of public convenience issued by the PUC and certain “grandfather rights” predating the adoption of the Pennsylvania Public Utility Code and its predecessor statutes, which each of them believes are adequate to authorize them to carry on their business in substantially all of the territories to which they now render gas or electric service. Under applicable Pennsylvania law, UGI Utilities, PNG, and CPG also have certain rights of eminent domain as well as the right to maintain their facilities in streets and highways in their territories.
Other Government Regulation
In addition to regulation by the PUC and FERC, the gas and electric utility operations of UGI Utilities are subject to various federal, state and local laws governing environmental matters, occupational health and safety, pipeline safety and other matters. UGI Utilities is subject to the requirements of the federal Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act and comparable state statutes with respect to the release of hazardous substances on property owned or operated by UGI Utilities. See Note 13 to Consolidated Financial Statements.
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EMPLOYEES
At September 30, 2009, UGI Utilities had approximately 1,430 employees, of which approximately 94% are dedicated to Gas Utility and 6% to Electric Utility. Union employees represent approximately 41% of the total employees.
GLOBAL CLIMATE CHANGE
There is a growing 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 regulating the emission of GHGs for some industry sectors, there is currently no federal regulation mandating the reduction of GHG emissions in the United States. In June of 2009, the United States House of Representatives passed the American Clean Energy and Security Act (“ACES Act”). The ACES Act would establish an economy-wide GHG cap-and-trade system to reduce GHG emissions over time. Subsequently, the United States Senate offered a draft of its own climate change bill, the Clean Energy Jobs and American Power Act. While the Senate’s bill is based on the ACES Act, there are differences between the bills and no legislation can be enacted until a final combined bill is approved by both the House of Representatives and the Senate.
In September of 2009, the Environmental Protection Agency issued a final rule establishing an economy-wide system for mandatory reporting of GHG emissions. Facilities subject to the rule, which include our natural gas distribution businesses, are required to begin emissions monitoring in January of 2010 and to submit detailed annual reports beginning in March of 2011. The rule does not require affected facilities to implement GHG emission controls or reductions.
Because natural gas is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, we anticipate that this will provide us with a competitive advantage over other sources of energy, such as fuel oil and coal, when new climate change regulations become effective. In addition, we are in the process of refining and implementing our strategy to identify both our GHG emissions and our energy consumption in order to be in a position to comply with new regulations and to take advantage of any opportunities that may arise from the regulation of such emissions.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income and identifiable assets attributable to UGI Utilities’ operating segments for the 2009, 2008 and 2007 fiscal years appears in Note 16 to Consolidated Financial Statements included in this Report and is incorporated herein by reference.
| ITEM 1A. | RISK FACTORS |
Decreases in the demand for natural gas and electricity because of warmer-than-normal heating season weather could adversely affect our results of operations, financial condition and cash flows because our rate structure does not contain weather normalization provisions.
Because many of our customers rely on natural gas or electricity to heat their homes, our results of operations are adversely affected by warmer-than-normal heating season weather. Weather conditions have a significant impact on the demand for natural gas and electricity for heating purposes. Accordingly, demand for natural gas and electricity is generally at its highest during the peak heating season of October through March and is directly affected by the severity of the winter weather. Our rate structure does not contain weather normalization provisions to compensate for warmer-than-normal weather conditions, and we have historically sold less natural gas and electricity when weather conditions are milder and, consequently, earned less income. As a result, warmer-than-normal heating season weather could reduce our net income, harm our financial condition and adversely affect our cash flows.
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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 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. 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 recent volatility in credit and capital markets may create additional risks to our business 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. Recent developments in the credit markets 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 recent 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, limit the scope of major capital projects if access to credit and capital markets is limited or could adversely affect our operating results.
The economic recession, volatility in the stock market and the low interest rate environment may negatively impact our pension liability.
The economic recession, the recent decline in the stock market and the low interest rate environment have had a significant impact on our pension liability and funded status. Additional declines in the stock market and valuation of stocks, combined with continued low interest rates, could further impact our pension liability and increase the amount of required contributions to our pension plans.
Changes in commodity market prices may have a negative effect on our liquidity.
Depending on the terms of our contracts with suppliers as well as our use of financial instruments including natural gas futures contracts to reduce volatility in the cost of natural gas we purchase, changes in the market price of electricity and natural gas could create payment obligations for the Company and expose us to an increased liquidity risk.
Our transmission and distribution systems may not operate as planned, which may increase our expenses or decrease our revenues and, thus, have an adverse effect on our financial results.
Our ability to manage operational risk with respect to our transmission and distribution systems is critical to our financial results. Our business also faces several risks, including the breakdown or failure of or damage to equipment or processes (especially due to severe weather or natural disasters), accidents and other factors. Operation of our transmission and distribution systems below our expectations may result in lost revenues or increased expenses, including higher maintenance costs.
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.
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 which may affect our businesses in ways that we cannot predict.
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Regulators may not allow timely recovery of costs for us in the future, which may adversely affect our results of operations.
Our Gas Utility and Electric Utility operations are subject to regulation by the PUC. The PUC, among other things, approves the rates that we may charge to our utility customers, thus impacting the returns that we may earn on the assets that are dedicated to those operations. We expect that PNG and CPG will periodically file requests with the PUC to increase base rates that they charge customers. If we are required in a rate proceeding to reduce the rates we charge our utility customers, or if we are unable to obtain approval for timely rate increases from the PUC, particularly when necessary to cover increased costs, our revenue growth will be limited and earnings may decrease.
Our operations, capital expenditures and financial results may be affected by regulatory changes and/or market responses to global climate change.
There is a growing concern, both nationally and internationally, about climate change and the contribution of GHG emissions, most notably carbon dioxide, to global warming. In response to this concern, the United States House of Representatives passed the ACES Act in June of 2009 to establish an economy-wide GHG cap-and-trade system to reduce GHG emissions over time. Subsequently, the United States Senate offered a draft climate change bill, the Clean Energy Jobs and American Power Act, based on the ACES Act. The proposed legislation includes a cap-and-trade policy structure in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. The legislation establishes mechanisms for GHG sources to obtain allowances to emit GHGs during the course of a year which may be used to cover their own allowances or sell them to other sources that do not hold enough emissions for their own operations.
It is expected that climate change legislation will continue to be a priority in the foreseeable future and it is possible that federal legislation mandating the reduction of GHG emissions on an economy-wide basis may be enacted during calendar year 2010. Increased regulation of GHG emissions could impose significant additional costs on the Company and our customers. The impact of legislation and regulations on us will depend on a number of factors, including (i) what 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 results of operations in the future.
We are subject to operating and litigation risks that may not be covered by insurance.
Our business operations are subject to all of the operating hazards and risks normally incidental to the handling, storage and distribution of combustible products, such as natural gas. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment. 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.
Remediation costs resulting from liability from contamination claims could reduce our net income.
We have 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 at sites outside of Pennsylvania cannot be recovered in future UGI Utilities’ rate proceedings, and insurance may not cover all or even part of these costs. Our actual costs related to these sites may exceed our current estimates due to factors beyond our control, such as:
| • | the discovery of presently unknown conditions; |
| • | changes in environmental laws and regulations; |
| • | judicial rejection of our legal defenses to the third-party claims; or |
| • | the insolvency of other responsible parties at the sites at which we are involved. |
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In addition, if we discover additional contaminated sites, we could be required to incur material costs, which would reduce our net income.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
| ITEM 3. | LEGAL PROCEEDINGS |
For information regarding legal proceedings, including environmental matters, see Note 13 to Consolidated Financial Statements.
PART II:
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Market Information
All of the outstanding shares of the Company’s Common Stock are owned by UGI and are not publicly traded.
Dividends
Cash dividends declared on the Company’s Common Stock totaled $61.2 million in Fiscal 2009, $68.8 million in Fiscal 2008, and $40.0 million in Fiscal 2007.
| 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 16 to Consolidated Financial Statements.
EXECUTIVE OVERVIEW
Our net income in Fiscal 2009 was $78.7 million, an increase of 6.4% from Fiscal 2008 net income of $74.0 million. The increase in net income reflects the accretive effect of the acquisition of all the stock of PPL Gas Utilities Corporation (the “CPG Acquisition”) which closed on October 1, 2008, partially offset by the impact of higher pension expense, higher environmental matters expense and reduced income from our Electric Utility. During Fiscal 2009, our Gas Utility and Electric Utility benefited from heating-season weather that was colder than in Fiscal 2008. Summer temperatures in our Electric Utility were cooler, however, reducing electricity demand for air conditioning. The colder heating-season weather helped offset some of the effects of the recession on general economic activity in our Gas Utility and Electric Utility service territories and the effects of customer conservation. In January 2009, CPG Gas and PNG Gas filed separate requests to increase base operating revenues. We received PUC approval of increased rates that went into effect in late August 2009. The combined increases in annual base rate revenues approved totaled $29.8 million. Due to the timing of the new rates, they did not have a material impact on Fiscal 2009 results but will have a full-year’s impact on Fiscal 2010 results. Electric Utility results were impacted by higher costs under fixed-price electricity purchase agreements which exceeded increases in POLR rate increases. While the number of Fiscal 2009 customer additions in our Gas Utility was about equal with Fiscal 2008, a substantial portion of the Fiscal 2009 growth resulted from the conversion market while growth in the new home market suffered due to the economic recession.
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Looking ahead, our results in Fiscal 2010 will be influenced by a number of factors including temperatures during the heating-season months and the length and severity of the economic recession on economic activity in our service territories. Our Electric Utility’s default service settlement with the PUC, which becomes effective January 1, 2010, allows for the recovery of prudently incurred electricity costs but eliminates the opportunity for Electric Utility to realize revenue in excess of such costs on electricity sales. This will result in a reduction in Electric Utility’s Fiscal 2010 operating income.
We believe that we have sufficient liquidity in the form of our revolving credit facility to fund business operations for the foreseeable future. We do not have significant amounts of long-term debt maturing or revolving credit agreements terminating until late in Fiscal 2011.
ANALYSIS OF RESULTS OF OPERATIONS
The following results of operations covers Fiscal 2009, Fiscal 2008 and the year ended September 30, 2007 (“Fiscal 2007”). On October 1, 2008, we consummated the CPG Acquisition, expanding our Gas Utility operations in Pennsylvania (see “Acquisition of PPL Gas Utilities Corporation” below). Our Fiscal 2009 results reflect the full-year impact of the operations of CPG.
Fiscal 2009 Compared with Fiscal 2008
| Increase | ||||||||||||||||
| (Millions of dollars) | 2009 | 2008 | (Decrease) | |||||||||||||
Gas Utility: | ||||||||||||||||
| Revenues | $ | 1,241.0 | $ | 1,138.3 | $ | 102.7 | 9.0 | % | ||||||||
| Total margin (a) | $ | 387.8 | $ | 307.3 | $ | 80.5 | 26.2 | % | ||||||||
| Operating income | $ | 153.5 | $ | 137.6 | $ | 15.9 | 11.6 | % | ||||||||
| Income before income taxes | $ | 111.3 | $ | 100.5 | $ | 10.8 | 10.7 | % | ||||||||
| System throughput — billions of cubic feet (“bcf”) | 149.7 | 133.7 | 16.0 | 12.0 | % | |||||||||||
| Degree days — % colder (warmer) than normal (b) | 4.1 | % | (2.7 | )% | — | — | ||||||||||
Electric Utility: | ||||||||||||||||
| Revenues | $ | 138.5 | $ | 139.2 | $ | (0.7 | ) | (0.5 | )% | |||||||
| Total margin (a) | $ | 39.3 | $ | 47.0 | $ | (7.7 | ) | (16.4 | )% | |||||||
| Operating income | $ | 15.4 | $ | 24.4 | $ | (9.0 | ) | (36.9 | )% | |||||||
| Income before income taxes | $ | 13.7 | $ | 22.5 | $ | (8.8 | ) | (39.1 | )% | |||||||
| Distribution sales — millions of kilowatt-hours (“gwh”) | 965.7 | 1,004.4 | (38.7 | ) | (3.9 | )% | ||||||||||
| (a) | Gas Utility’s total margin represents total revenues less cost of sales. Electric Utility’s total margin represents total revenues less cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes of $7.6 million in Fiscal 2009 and $7.9 million in Fiscal 2008. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” on the Consolidated Statements of Income. | |
| (b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory. |
Gas Utility.Temperatures in the Gas Utility service territory based upon heating degree days were 4.1% colder than normal in Fiscal 2009 compared with temperatures that were 2.7% warmer than normal in Fiscal 2008. In Fiscal 2009, Gas Utility began calculating normal degree days using the 15-year period 1990—2004. Previously, normal degree days were based upon recent 30-year periods. For comparison purposes, the Fiscal 2008 weather variance has been recalculated using the new 15-year period. Total distribution throughput increased 16.0 bcf in Fiscal 2009 principally reflecting the effects of the October 1, 2008 CPG Acquisition and increases in core-market volumes resulting from the colder Fiscal 2009 weather and year-over-year customer growth. Gas Utility’s core-market customers principally 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. These increases in system throughput were partially offset by the effects on volumes sold and transported due to lower demand from commercial and industrial customers as a result of the deterioration in general economic activity and customer conservation.
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Gas Utility revenues increased $102.7 million in Fiscal 2009 principally reflecting $187.4 million of incremental revenues from CPG Gas largely offset by lower revenues from low-margin off-system sales. 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 $853.2 million in Fiscal 2009 compared with $831.1 million in Fiscal 2008 principally reflecting incremental cost of sales of $117.0 million associated with CPG Gas partially offset principally by the cost of sales effect of the lower off-system sales.
Gas Utility total margin increased $80.5 million in Fiscal 2009 principally reflecting incremental margin from CPG Gas and higher total core-market margin resulting from the higher core-market volumes sold.
The increase in Gas Utility operating income during Fiscal 2009 principally reflects the previously mentioned greater total margin partially offset by higher operating and administrative and depreciation expenses, principally incremental expenses associated with CPG Gas, and, to a lesser extent, higher pension expense, costs associated with environmental matters and greater distribution system maintenance expenses. Income before income taxes also increased reflecting the previously mentioned higher operating income partially offset by higher interest expense associated with $108 million Senior Notes issued to finance a portion of the CPG Acquisition.
Electric Utility. Electric Utility’s kilowatt-hour sales in Fiscal 2009 were lower than in Fiscal 2008. Temperatures based upon heating degree days in Electric Utility’s service territory were approximately 5.0% colder than last year resulting in greater sales to Electric Utility’s residential heating customers. These greater sales were more than offset, however, by lower sales to commercial and industrial customers as a result of the deterioration in general economic activity and lower weather-related air-conditioning sales during the summer of Fiscal 2009. Notwithstanding the lower sales, Electric Utility revenues were about equal with last year as a result of higher POLR rates and greater revenues from spot market sales of electricity. Electric Utility cost of sales increased to $91.6 million in Fiscal 2009 from $84.3 million in Fiscal 2008 principally reflecting greater purchased power costs.
Electric Utility total margin decreased $7.7 million during Fiscal 2009 principally reflecting the higher cost of sales and the effects of the lower sales volumes.
Electric Utility operating income and income before income taxes in Fiscal 2009 were $9.0 million and $8.8 million lower than in Fiscal 2008, respectively, reflecting the previously mentioned lower total margin and higher operating and administrative costs including higher customer assistance expenses and greater pension expense.
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Fiscal 2008 Compared with Fiscal 2007
| Increase | ||||||||||||||||
| (Millions of dollars) | 2008 | 2007 | (Decrease) | |||||||||||||
Gas Utility: | ||||||||||||||||
| Revenues | $ | 1,138.3 | $ | 1,044.9 | $ | 93.4 | 8.9 | % | ||||||||
| Total margin (a) | $ | 307.3 | $ | 303.5 | $ | 3.8 | 1.3 | % | ||||||||
| Operating income | $ | 137.6 | $ | 136.6 | $ | 1.0 | 0.7 | % | ||||||||
| Income before income taxes | $ | 100.5 | $ | 96.7 | $ | 3.8 | 3.9 | % | ||||||||
| System throughput — billions of cubic feet (“bcf”) | 133.7 | 131.8 | 1.9 | 1.4 | % | |||||||||||
| Degree days — % (warmer) than normal (b) | (2.7 | )% | (2.4 | )% | — | — | ||||||||||
Electric Utility: | ||||||||||||||||
| Revenues | $ | 139.2 | $ | 121.9 | $ | 17.3 | 14.2 | % | ||||||||
| Total margin (a) | $ | 47.0 | $ | 47.3 | $ | (0.3 | ) | (0.6 | )% | |||||||
| Operating income | $ | 24.4 | $ | 26.0 | $ | (1.6 | ) | (6.2 | )% | |||||||
| Income before income taxes | $ | 22.5 | $ | 23.6 | $ | (1.1 | ) | (4.7 | )% | |||||||
| Distribution sales — millions of kilowatt-hours (“gwh”) | 1,004.4 | 1,010.6 | (6.2 | ) | (0.6 | )% | ||||||||||
| (a) | Gas Utility’s total margin represents total revenues less cost of sales. Electric Utility’s total margin represents total revenues less cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes of $7.9 million in Fiscal 2008 and $6.8 million in Fiscal 2007. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” on the Consolidated Statements of Income. | |
| (b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory. |
Gas Utility.Temperatures in the Gas Utility service territory based upon heating degree days were 2.7% warmer than normal in Fiscal 2008 compared with temperatures that were 2.4% warmer than normal in Fiscal 2007. Total distribution system throughput increased 1.9 bcf in Fiscal 2008 principally reflecting greater interruptible delivery service volumes (principally volumes associated with low margin cogeneration customers) and an increase in the number of Gas Utility core- market customers partially offset by lower average usage per customer due in large part to price-induced customer conservation and a weak economy.
Gas Utility revenues increased $93.4 million in Fiscal 2008 principally reflecting a $57.4 million increase in revenues from off-system sales and the effects of higher average PGC rates on retail core-market revenues. Gas Utility’s cost of sales was $831.1 million in Fiscal 2008 compared with $741.5 million in Fiscal 2007 principally reflecting the greater off-system sales and the increase in average retail core-market PGC rates.
Gas Utility total margin increased $3.8 million in Fiscal 2008 primarily reflecting modest increases in interruptible delivery service and core market total margin.
The increase in Gas Utility operating income principally reflects the previously mentioned $3.8 million increase in total margin and a $5.3 million increase in other income partially offset by modestly higher operating and administrative expenses. The higher other income reflects in large part greater storage contract fees and a $2.2 million postretirement benefit plan curtailment gain. The increase in operating and administrative expenses includes, among other things, higher environmental legal costs and greater uncollectible accounts expense. Gas Utility income before income taxes also reflects lower interest expense on bank loans.
Electric Utility.Electric Utility’s kilowatt-hour sales in Fiscal 2008 were about equal to Fiscal 2007 on heating-season weather that was slightly warmer and cooling-season weather that was slightly cooler. Electric Utility revenues increased $17.3 million principally as a result of higher POLR rates. Electric Utility cost of sales increased to $84.3 million in Fiscal 2008 from $67.8 million in the prior year principally reflecting higher per-unit purchased power costs.
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Electric Utility total margin in Fiscal 2008 was about equal to Fiscal 2007 reflecting the effects of the higher POLR rates offset principally by the higher per-unit purchased power costs and higher revenue-related taxes.
The decrease in Fiscal 2008 Electric Utility operating income reflects slightly higher operating and administrative costs including higher system maintenance and uncollectible accounts expense. Income before income taxes reflects the lower operating income partially offset by lower interest expense on bank loans.
FINANCIAL CONDITION AND LIQUIDITY
Capitalization and Liquidity
UGI Utilities’ total debt outstanding was $794 million at September 30, 2009 compared with total debt outstanding of $589 million at September 30, 2008. Included in these amounts are $154 million and $57 million, respectively, of bank loans outstanding under UGI Utilities’ Revolving Credit Agreement. UGI Utilities’ total debt outstanding at September 30, 2009, other than bank loans, comprises $383 million of Senior Notes and $257 million of Medium-Term Notes. In conjunction with the October 1, 2008 CPG Acquisition, on September 25, 2008 UGI made a $120 million cash contribution to UGI Utilities. This cash contribution was used by UGI Utilities to reduce its bank loans outstanding. On October 1, 2008, UGI Utilities borrowed under the Revolving Credit Facility to fund a portion of the CPG Acquisition (see “Acquisition of PPL Gas Utilities Corporation” below).
UGI Utilities has a $350 million Revolving Credit Agreement which expires in August 2011. At September 30, 2009 and 2008, there was $154 million and $57 million outstanding under this Revolving Credit Agreement. As previously mentioned, the September 30, 2008 amount was reduced by a $120 million cash contribution made by UGI on September 25, 2008 to finance a portion of the CPG Acquisition on October 1, 2008. The Revolving Credit Agreement requires UGI Utilities to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. During Fiscal 2009 and Fiscal 2008, average daily bank loan borrowings totaled $180.0 million and $121.0 million, respectively, and peak bank loan borrowings totaled $312 million and $267 million, respectively. Peak bank loan borrowings typically occur during the peak heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is generally greatest. Average bank loan borrowings were higher in Fiscal 2009 than in Fiscal 2008 due in large part to increases in margin deposits associated with natural gas futures contracts as a result of declines in wholesale natural gas prices (see “Market Risk Disclosures” below).
Based upon cash expected to be generated from operations and borrowings under our Revolving Credit Agreement, management believes the Company will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2010. For additional discussion of UGI Utilities’ long-term debt and Revolving Credit Agreement, see Note 8 to Consolidated Financial Statements.
Cash Flows
Operating activities.Due to the seasonal nature of UGI Utilities’ businesses, cash flows from our operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas and electricity 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 accounts receivable and inventories, is generally greatest. UGI Utilities uses borrowings under its Revolving Credit Agreement to manage seasonal cash flow needs.
Cash provided by operating activities was $176.4 million in Fiscal 2009, $142.6 million in Fiscal 2008 and $133.5 million in Fiscal 2007. Cash provided by operating activities before changes in operating working capital was $187.1 million in Fiscal 2009, $143.3 million in Fiscal 2008 and $150.6 million in Fiscal 2007. Changes in operating working capital used $10.7 million of cash in Fiscal 2009, $0.8 million of cash in Fiscal 2008 and $17.1 million of cash in Fiscal 2007. The greater cash flow required for changes in operating working capital in Fiscal 2009 as compared with Fiscal 2008 principally reflects greater cash used for purchases of natural gas inventories, the timing of payments of accounts payable and lower net recoveries of purchased gas costs partially offset by $19 million of collateral deposits received under storage contract administrative agreements. The lower cash flow required for changes in operating working capital in Fiscal 2008 as compared with Fiscal 2007 principally reflects the timing of cash recoveries through Gas Utility’s PGC recovery mechanism in excess of purchased gas costs, including cash from settled gains on natural gas futures contracts, partially offset by the timing of interest payments and payments for accounts payable.
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Investing activities.Cash used by investing activities was $310.4 million in Fiscal 2009, $92.3 million in Fiscal 2008, and $55.2 million in Fiscal 2007. Fiscal 2009 cash flow from investing activities includes net cash used for the acquisition of CPG. It also includes net cash proceeds from the concurrent sale of the assets of Penn Fuel Propane, CPG’s wholly owned subsidiary, to AmeriGas OLP. Expenditures for property, plant and equipment were higher in Fiscal 2009 compared with Fiscal 2008 reflecting in large part expenditures for CPG. Expenditures for property, plant and equipment decreased $9.1 million in Fiscal 2008 compared with Fiscal 2007 principally reflecting lower Gas Utility capital expenditures associated with its multi-year automated meter reading project. Fiscal 2009 investing activity cash flows also reflect a reduction in restricted cash in natural gas futures brokerage accounts of $34.0 million compared with an increase of $27.4 million in Fiscal 2008. Changes in restricted cash in futures brokerage accounts are the result of the timing of settlement of natural gas futures contracts and changes in natural gas prices. Cash flow from investing activities in Fiscal 2007 includes a $23.7 million working capital adjustment associated with UGI Utilities’ Fiscal 2006 acquisition of Southern Union Company’s PG Energy Division (see Note 4 to Consolidated Financial Statements).
Financing activities.Cash provided (used) by financing activities was $144.1 million in Fiscal 2009, ($63.0) million in Fiscal 2008 and ($65.0) million in Fiscal 2007. Financing activities cash flows are primarily the result of issuances and repayments of long-term debt, borrowings under the Revolving Credit Agreement, cash dividends to UGI, and capital contributions from UGI. During Fiscal 2009 net bank loan borrowings totaled $97 million compared with net bank loan repayments of $133 million in Fiscal 2008 and $26 million in Fiscal 2007. The significant increase in net cash from bank loan borrowings in Fiscal 2009 was due in large part to the timing and use of cash contributions made by UGI in September 2008 to fund the CPG Acquisition on October 1, 2008. As previously mentioned, a $120 million cash contribution made by UGI on September 25, 2008 was temporarily used by UGI Utilities in September 2008 to reduce bank loan borrowings. This amount was then reborrowed on October 1, 2008, along with additional bank loan borrowings, to fund a portion of the CPG Acquisition. During Fiscal 2009, we issued $108 million of 6.375% Senior Notes due 2013 the proceeds of which were used to fund a portion of the CPG Acquisition. In January 2008, UGI Utilities issued $20 million of 5.67% Medium-Term Notes and used the proceeds to reduce Revolving Credit Agreement borrowings. In June 2007, UGI Utilities refinanced $20 million of maturing 7.17% Medium-Term Notes with proceeds from the issuance of $20 million of 6.17% Medium-Term Notes.
Capital Expenditures
In the following table, we present capital expenditures by business segment for Fiscal 2009, Fiscal 2008 and Fiscal 2007. We also provide amounts we expect to spend in Fiscal 2010. We expect to finance a substantial portion of Fiscal 2010 capital expenditures from cash generated by operations and the remainder from borrowings under our Revolving Credit Agreement.
| (Millions of dollars) | 2010 | 2009 | 2008 | 2007 | ||||||||||||
| (estimate) | ||||||||||||||||
| Gas Utility | $ | 71.1 | $ | 73.8 | $ | 58.3 | $ | 66.2 | ||||||||
| Electric Utility | 12.9 | 5.3 | 6.0 | 7.2 | ||||||||||||
| $ | 84.0 | $ | 79.1 | $ | 64.3 | $ | 73.4 | |||||||||
The greater Electric Utility capital expenditures forecast for Fiscal 2010 includes expenditures related to increased transmission capacity associated with additions to electric generating capacity in its service territory.
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Contractual Cash Obligations and Commitments
UGI Utilities has contractual cash obligations that extend beyond Fiscal 2009 including scheduled repayments of long-term debt and interest, operating lease obligations, unconditional purchase obligations for pipeline transportation and natural gas storage services, and commitments to purchase natural gas and electricity. The following table presents significant contractual cash obligations under agreements existing as of September 30, 2009.
| Payments Due by Period | ||||||||||||||||||||
| Fiscal | Fiscal | Fiscal | ||||||||||||||||||
| (Millions of dollars) | Total | 2010 | 2011-2012 | 2013-2014 | Thereafter | |||||||||||||||
| Long-term debt (a) | $ | 640.0 | $ | — | $ | 40.0 | $ | 133.0 | $ | 467.0 | ||||||||||
| Interest on long-term fixed rate debt (b) | 399.8 | 37.1 | 75.0 | 61.9 | 225.8 | |||||||||||||||
| Operating leases | 22.4 | 5.0 | 7.7 | 5.0 | 4.7 | |||||||||||||||
| Gas Utility and Electric Utility supply, storage and transportation contracts | 704.1 | 240.8 | 233.4 | 121.4 | 108.5 | |||||||||||||||
| Total | $ | 1,766.3 | $ | 282.9 | $ | 356.1 | $ | 321.3 | $ | 806.0 | ||||||||||
| (a) | Based upon stated maturity dates. | |
| (b) | Based upon stated interest rates. | |
The components of the other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2009 principally consist of pension and other postretirement benefit liabilities recorded in accordance with GAAP and estimated obligations for environmental investigation and remediation. These liabilities are not included in the table of Contractual Cash Obligations and Commitments above because they are estimates of future payments and not contractually fixed as to timing or amount. For additional information on these liabilities see Notes 10 and 13 to Consolidated Financial Statements.
Acquisition of PPL Gas Utilities Corporation
On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas Utilities Corporation (now “CPG”), the natural gas distribution utility of PPL Corporation (the “CPG Acquisition”), and its subsidiaries for cash consideration of $267.6 million plus estimated working capital of $35.4 million. Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central Penn Propane, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas Propane, L.P. (“AmeriGas OLP”), an affiliate of UGI, for cash consideration of $32 million plus estimated working capital of $1.6 million. CPG distributes natural gas to approximately 76,000 customers in eastern and central Pennsylvania and also distributes natural gas to several hundred customers in portions of one Maryland county. CPP sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition with a combination of $120 million cash contributed by UGI on September 25, 2008, proceeds from the issuance on October 1, 2008 of $108 million principal amount of 6.375% Senior Notes due 2013 and approximately $75 million of borrowings under UGI Utilities’ Revolving Credit Agreement. The cash proceeds of $33.6 million from the sale of the assets of CPP to AmeriGas OLP were used to reduce borrowings under UGI Utilities’ Revolving Credit Agreement.
Pursuant to the CPG Acquisition purchase agreement, the purchase price was subject to adjustment for the difference between an estimated $35.4 million and the actual working capital as of the closing date agreed to by both UGI Utilities and PPL Corporation (“PPL”). During Fiscal 2009, UGI Utilities and PPL reached an agreement on the working capital adjustment pursuant to which PPL paid UGI Utilities $9.7 million in cash plus interest. Also during Fiscal 2009, UGI Utilities and AmeriGas OLP reached an agreement on the working capital adjustment associated with UGI Utilities’ sale of the assets of CPP to AmeriGas OLP pursuant to which UGI Utilities paid AmeriGas OLP $1.4 million.
For additional information regarding the CPG Acquisition, see Note 4 to Consolidated Financial Statements.
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Pension Plans
As of September 30, 2009, we sponsor two defined benefit pension plans (“Pension Plans”) for employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries.
Effective December 31, 2008, we merged two of our defined benefit pension plans. As a result of the merger, we were required under U.S. generally accepted accounting principles (“GAAP”) to remeasure the combined plan’s assets and benefit obligations as of December 31, 2008. As a result of the remeasurement, Fiscal 2009 pension expense increased approximately $3.9 million for the period subsequent to the remeasurement due to the amortization of actuarial losses resulting from the general decline in the financial markets and a lower discount rate. The fair value of Pension Plans’ assets totaled $276.4 million and $241.0 million at September 30, 2009 and 2008, respectively. At September 30, 2009 and 2008, the underfunded position of Pension Plans, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plans’ assets, was $145.6 million and $59.6 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 Pension Plans during Fiscal 2010 but such contributions are not expected to be material. Pre-tax pension costs associated with Pension Plans in Fiscal 2009 were $7.1 million. Pension cost associated with Pension Plans in Fiscal 2010 is expected to be approximately $7.9 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. In accordance with this guidance, through September 30, 2009 we have recorded cumulative after-tax charges to Common Stockholders’ Equity of $79.1 million in order to reflect the funded status of these plans. For a more detailed discussion of the Pension Plans and other postretirement benefit plans, see Note 10 to Consolidated Financial Statements.
REGULATORY MATTERS
Gas Utility.On January 28, 2009, PNG and CPG filed separate requests with the PUC to increase base operating revenues by $38.1 million annually for PNG and $19.6 million annually for CPG to fund system improvements and operations necessary to maintain safe and reliable natural gas service and energy assistance for low income customers as well as energy conservation programs for all customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on agreements with the opposing parties regarding the requested base operating revenue increases. On August 27, 2009, the PUC approved the settlement agreements which resulted in a $19.8 million base operating revenue increase for PNG Gas and a $10.0 million base operating revenue increase for CPG Gas. The increases became effective August 28, 2009 and did not have a material effect on Fiscal 2009 results.
Electric Utility.As a result of Pennsylvania’s Electricity Generation Customer Choice and Competition Act that became effective January 1, 1997, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. Electric Utility remains the provider of last resort (“POLR”) for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006.
In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement, Electric Utility increased its POLR rates effective January 1, 2009, which increased the average cost to a residential heating customer by approximately 1.5% over such costs in effect during calendar year 2008. Effective January 1, 2008, Electric Utility increased its POLR rates which increased the average cost to a residential heating customer by approximately 5.5% over such costs in effect during calendar year 2007. Effective January 1, 2007, Electric Utility increased the average cost to a residential heating customer by approximately 35% over such costs in effect during calendar year 2006.
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On July 17, 2008, the PUC approved Electric Utility’s default service procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s default service regulations. These plans do not affect Electric Utility’s existing POLR settlement effective through December 31, 2009. The approved plans specify how Electric Utility will solicit and acquire default service supplies for residential customers for the period January 1, 2010 through May 31, 2014, and for commercial and industrial customers for the period January 1, 2010 through May 31, 2011 (collectively, the “Settlement Term”). UGI Utilities filed a rate plan on August 29, 2008 for the Settlement Term. On January 22, 2009, the PUC approved a settlement of the rate filing that provides for Electric Utility to fully recover its default service costs. On October 1, 2009, UGI Utilities filed a default service plan to establish procurement rules applicable to the period after May 31, 2011 for its commercial and industrial customers.
Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010 Electric Utility will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues. However, beginning January 1, 2010, Electric Utility will forego the opportunity to recover revenues in excess of actual costs as currently permitted under the POLR Settlement. This will result in a reduction in Electric Utility’s Fiscal 2010 operating income.
MANUFACTURED GAS PLANTS
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 million and $1.1 million, respectively, in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP Properties and at the end of 2013 for well plugging activities. 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, 2009, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $25.0 million. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets totaling $25.0 million.
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 UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. At September 30, 2009 and 2008, neither UGI Gas’ undiscounted nor its accrued liability for environmental investigation and cleanup costs was material.
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UGI Utilities has been notified of several 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 are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating three claims against it relating to out-of-state sites.
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 the MGP sites outside of Pennsylvania currently subject to third-party claims or litigation, see Note 13 to Consolidated Financial Statements.
We cannot predict with certainty the final results of any of the MGP 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, 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.
RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula based upon the relative percentage of UGI Utilities’ revenues, operating expenses and net assets employed to the total of such items for UGI’s other operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses totaled $15.0 million in Fiscal 2009, $11.8 million in Fiscal 2008 and $11.6 million in Fiscal 2007 and are classified as operating and administrative expenses — related parties in the Consolidated Statements of Income. UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries, principally payroll-related services. Amounts billed to these entities by UGI Utilities were not material.
At September 30, 2009, UGI Utilities was a party to a one-year storage contract administrative agreement (“SCAA”) with Energy Services expiring on October 31, 2009. At September 30, 2008, UGI Utilities was a party to a one-year SCAA with Energy Services expiring on October 31, 2008. Pursuant to the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the storage 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. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with the SCAAs totaling $55.8 million in Fiscal 2009, $111.8 million in Fiscal 2008 and $92.7 million in Fiscal 2007. UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at September 30, 2009, comprising approximately 7.7 billion cubic feet of natural gas, was $67.4 million. The carrying value of these gas storage inventories at September 30, 2008, comprising approximately 8.3 billion cubic feet of natural gas, was $70.8 million. Effective November 1, 2009, UGI Utilities entered into a new SCAA with Energy Services expiring on October 31, 2012.
UGI Utilities also has a Gas Supply and Delivery Service Agreement with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to UGI Utilities during the peak heating-season months of November to March. In addition, from time to time, UGI Utilities purchases natural gas or pipeline capacity from Energy Services. The aggregate amount of these transactions during Fiscal 2009, Fiscal 2008 and Fiscal 2007 (exclusive of Storage Agreement transactions described above) totaled $24.4 million, $52.6 million and $36.3 million, respectively.
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From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During Fiscal 2009, Fiscal 2008 and Fiscal 2007, revenues associated with sales to Energy Services totaled $30.9 million, $66.1 million, and $39.6 million, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to those transactions already described above). During Fiscal 2009, Fiscal 2008 and Fiscal 2007, such purchases totaled $17.3 million, $29.5 million and $2.0 million, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
We do not have any off-balance sheet arrangements that are expected to have an effect on the Company’s financial condition, revenues and expenses, results of operations, liquidity, capital expenditures or capital resources.
MARKET RISK DISCLOSURES
As previously mentioned, Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers. 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 contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. There were no natural gas futures contracts outstanding at September 30, 2009. The fair value of natural gas futures contracts at September 30, 2008 were losses of $23.3 million. The cost of natural gas derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At September 30, 2008, Gas Utility had approximately $34.0 million of restricted cash associated with natural gas futures accounts with brokers. At September 30, 2009, there were no restricted cash balances.
Our 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. The amount of the unrealized gains or loss on these contracts and associated volumes under contract at September 30, 2009 were not material. A 10% adverse change in the market value of gasoline futures contracts would not have a material effect on the Company’s operating income.
Electric Utility purchases its electric power needs from electricity suppliers under fixed-price energy contracts and, to a much lesser extent, on the spot market. Wholesale prices for electricity can be volatile especially during periods of high demand or tight supply. As previously mentioned and in accordance with POLR settlements approved by the PUC, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. Electric Utility’s fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 31, 2009. With respect to its existing fixed-price power contracts, should any of the counterparties fail to provide electric power under the terms of such contracts, any increases in the cost of replacement power could negatively impact Electric Utility results. In order to reduce this nonperformance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. Changes in electricity prices could require Electric Utility to provide cash collateral to its supply counterparties. Electric Utility also obtains financial transmission rights (“FTRs”) through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, by purchases at monthly PJM auctions. FTRs are 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 electricity transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Although FTRs are economically effective as hedges of congestion charges, they do not currently qualify for hedge accounting treatment. At September 30, 2009, the fair value of Electric Utility’s FTRs was $0.8 million. A 10% adverse change in the market value of FTRs would not have a material impact on the Company’s operating income.
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As previously mentioned, on January 22, 2009, the PUC approved a settlement of a rate filing that provides for Electric Utility to fully recover its default service costs. Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010, Electric Utility will no longer be subject to the risk that actual costs for purchased power, including FTRs, will exceed POLR revenues.
Our variable-rate debt includes our bank loan borrowings. These agreements provide for interest rates on borrowings that are indexed to short-term market interest rates. Based upon the average level of borrowings outstanding under these agreements in Fiscal 2009 and Fiscal 2008, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $1.8 million and $1.2 million, respectively.
Our long-term debt 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 expect to refinance such debt with new debt having interest rates reflecting then-current market conditions. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of $51.8 million and $34.4 million at September 30, 2009 and 2008, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $58.9 million and $38.8 million at September 30, 2009 and 2008, respectively.
In order to reduce interest rate risk associated with near or medium term issuances of fixed-rate debt, we may enter into interest rate protection agreements.
Our unsettled derivative instruments at September 30, 2009 comprised Electric Utility’s FTRs and exchange-traded gasoline futures and swap contracts.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance with accounting principles generally accepted in the United States of America requires the selection and application of accounting principles appropriate to the relevant facts and circumstances of the Company’s operations and the use of estimates made by management. The Company has identified the following critical accounting policies and estimates that are most important to the portrayal of the Company’s financial condition and results of operations. 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.
Purchase Price Allocations.In the event that the Company enters into a material business combination, in accordance with accounting guidance associated with business combinations the purchase price is allocated to the various assets and liabilities acquired at their estimated fair value. Fair values of assets 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.Our allocation of the purchase price of acquisitions has resulted in the Company recording goodwill. In accordance with GAAP, a reporting unit with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, management must determine the reporting unit’s fair value using quoted market prices or, in the absence of quoted market prices, valuation techniques which use discounted estimates of future cash flows to be generated by the reporting unit. These cash flow estimates involve management judgments based on a broad range of information and historical results. 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, 2009, our goodwill totaled $180.1 million. We did not record any impairments of goodwill during Fiscal 2009, Fiscal 2008 or Fiscal 2007.
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Litigation Accruals and Environmental Remediation Liabilities.We are involved in litigation regarding pending claims and legal actions that arise in the normal course of our businesses. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere and PNG Gas and CPG Gas owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with GAAP, we establish reserves for pending claims and legal actions or environmental remediation obligations when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. 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.
Depreciation of Property, Plant and Equipment.We compute depreciation on UGI Utilities property, plant and equipment on a straight-line basis over the average remaining lives of its various classes of depreciable property. Changes in the estimated useful lives of property, plant and equipment could have a material effect on our results of operations. As of September 30, 2009, UGI Utilities net property, plant and equipment totaled $1,364.8 million and we recorded depreciation expense of $48.9 million during Fiscal 2009.
Regulatory Assets and Liabilities.Gas Utility and Electric Utility’s distribution businesses 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, 2009, our regulatory assets totaled $141.5 million. For additional information on our regulatory assets, see Note 5 to the Consolidated Financial Statements.
Pension Plan Assumptions.The costs of providing benefits under our Pension Plans 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 Pension Plans 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 plan assets of 50 basis points to a rate of 8.0% would result in an increase in pre-tax pension cost of approximately $1.1 million in Fiscal 2010. A decrease in the discount rate of 50 basis points to a rate of 5.0% would result in an increase in pre-tax pension cost of approximately $1.7 million in Fiscal 2010.
NEWLY ADOPTED AND RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
See Note 3 to Consolidated Financial Statements for a discussion of the effects of accounting guidance we adopted in Fiscal 2009, Fiscal 2008 and Fiscal 2007 as well as recently issued accounting guidance not yet adopted.
| 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 herein by reference.
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| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
The financial statements and the financial statement schedule referred to in the Index contained on page F-2 of this Report are incorporated herein by reference.
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| ITEM 9A. | CONTROLS AND PROCEDURES |
| (a) | The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures as of the end of the period covered by this Report were designed and functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. |
| (b) | Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. 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, 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 participation of management including our Chief Executive Officer and Chief Financial Officer, 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 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. |
| Based on its assessment, management has concluded that the Company maintained effective internal control over financial reporting as of September 30, 2009, based on the COSO Framework. |
| (c) | No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. |
| ITEM 9B. | OTHER INFORMATION |
None.
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PART III:
| ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent registered public accountants, in Fiscal 2009 and Fiscal 2008 were as follows:
| 2009 | 2008 | |||||||
| Audit Fees | $ | 991,250 | $ | 848,898 | ||||
| Audit-Related Fees | - 0 - | - 0 - | ||||||
| Tax Fees | - 0 - | - 0 - | ||||||
| All Other Fees | - 0 - | - 0 - | ||||||
| Total Fees for Services Provided | $ | 991,250 | $ | 848,898 | ||||
Consistent with SEC policies regarding auditor independence, the Audit Committee has responsibility for appointing, setting compensation and overseeing the work of the Company’s independent accountants. In recognition of this responsibility, the Audit Committee has a policy of pre-approving all audit and permissible non-audit services provided by the independent accountants.
Prior to engagement of the Company’s independent accountants for the next year’s audit, management submits a list of services and related fees expected to be rendered during that year within each of the four categories of services noted above to the Audit Committee for approval.
PART IV:
| ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
(a) Documents filed as part of this report:
(1) Financial Statements:
Included under Item 8 are the following financial statements and supplementary data:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of September 30, 2009 and 2008
Consolidated Statements of Income for the fiscal years ended September 30, 2009, 2008 and 2007
Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2009, 2008 and 2007
Consolidated Statements of Stockholder’s Equity for the fiscal years ended September 30, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
(2) Financial Statement Schedule:
For the years ended September 30, 2009, 2008 and 2007
II — Valuation and Qualifying Accounts
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 notes thereto contained in this Report.
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(3) List of Exhibits:
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 3.1 | UGI Utilities’ Amended and Restated Articles of Incorporation | Utilities | Registration Statement No. 333-72540 (10/31/01) | 3 | ||||||||
| 3.2 | Bylaws of UGI Utilities as amended through September 30, 2003 | Utilities | Form 10-K (9/30/03) | 3.2 | ||||||||
| 4 | Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of its long-term debt not required to be filed pursuant to the description of Exhibit 4 contained in Item 601 of Regulation S-K) | |||||||||||
| 4.1 | UGI Utilities’ Articles of Incorporation and Bylaws referred to in Exhibit Nos. 3.1 and 3.2 | UGI | Form 8-B/A (4/17/96) | 3. | (4) | |||||||
| 4.2 | Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994 | Utilities | Registration Statement No. 33-77514 (4/8/94) | 4 | (c) | |||||||
| 4.3 | Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association | Utilities | Form 8-K (9/12/06) | 4.2 | ||||||||
| 4.4 | Form of Fixed Rate Medium-Term Note | Utilities | Form 8-K (8/26/94) | (4)i | ||||||||
| 4.5 | Form of Fixed Rate Series B Medium-Term Note | Utilities | Form 8-K (8/1/96) | 4(i) | ||||||||
| 4.6 | Form of Floating Rate Series B Medium-Term Note | Utilities | Form 8-K (8/1/96) | 4(ii) | ||||||||
| 4.7 | Officer’s Certificate establishing Medium-Term Notes Series | Utilities | Form 8-K (8/26/94) | 4(iv) | ||||||||
| 4.8 | Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture | Utilities | Form 8-K (8/1/96) | 4(iv) | ||||||||
| 4.9 | Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture | Utilities | Form 8-K (5/21/02) | 4.2 | ||||||||
| 4.10 | Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes | Utilities | Form 8-K (5/21/02) | 4.1 | ||||||||
| 10.1 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 | UGI | Form 8-K (3/27/07) | 10.1 | |||||||
| 10.2 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 — Terms and Conditions as amended and restated effective January 1, 2009 | UGI | Form 10-K (9/30/09) | 10.2 | |||||||
| 10.3 | ** | UGI Corporation 1997 Stock Option and Dividend Equivalent Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.10 | |||||||
| 10.4 | ** | UGI Corporation 2000 Stock Incentive Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.14 | |||||||
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Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.5** | UGI Corporation 2009 Deferral Plan | UGI | Form 8-K (12/12/08) | 10.1 | ||||||||
| 10.6** | UGI Corporation Senior Executive Employee Severance Plan as in effect as of January 1, 2008 | UGI | Form 10-Q (3/31/08) | 10.1 | ||||||||
| 10.7** | UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective January 1, 2009 | UGI | Form 10-K (9/30/09) | 10.11 | ||||||||
| 10.8** | UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006 | UGI | Form 10-K (9/30/07) | 10.8 | ||||||||
| 10.9** | UGI Utilities, Inc. Executive Annual Bonus Plan effective as of October 1, 2006 | Utilities | Form 10-K (9/30/07) | 10.5 | ||||||||
| *10.10** | UGI Utilities, Inc. Senior Executive Employee Severance Plan as in effect as of November 1, 2008 | |||||||||||
| 10.11** | UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for UGI Employees, dated January 1, 2009 | UGI | Form 10-Q (3/31/09) | 10.8 | ||||||||
| 10.12** | UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for Utilities Employees, dated January 1, 2009 | UGI | Form 10-K (9/30/09) | 10.23 | ||||||||
| 10.13** | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2009 | UGI | Form 10-Q (3/31/09) | 10.5 | ||||||||
| 10.14** | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Utilities Employees, dated January 1, 2009 | UGI | Form 10-Q (3/31/09) | 10.6 | ||||||||
| 10.15** | UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Employees, dated January 1, 2009 | UGI | Form 10-Q (3/31/09) | 10.1 | ||||||||
| 10.16** | UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for Utilities Employees, dated January 1, 2009 | UGI | Form 10-Q (3/31/09) | 10.2 | ||||||||
| 10.17** | Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Messrs. Greenberg and Walsh | UGI | Form 10-Q (6/30/08) | 10.3 | ||||||||
| *10.18** | Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Messrs. Barney and Terranova and Ms. Ebner | |||||||||||
27
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.19 | Credit Agreement, dated as of August 11, 2006, among UGI Utilities, Inc., as borrower, and Citibank, N.A., as agent, Wachovia Bank, National Association, as syndication agent, and Citizens Bank of Pennsylvania, Credit Suisse, Cayman Islands Branch, Deutsche Bank AG New York Branch, JPMorgan Chase Bank, N.A., Mellon Bank, N.A., PNC Bank, National Association, and the other financial institutions from time to time parties thereto | Utilities | Form 8-K (8/11/06) | 10.1 | ||||||||
| 10.20 | Stock Purchase Agreement by and between PPL Corporation, as Seller, and UGI Utilities, Inc., as Buyer, dated as of March 5, 2008 | Utilities | Form 8-K (3/5/08) | 10.1 | ||||||||
| 10.21 | Amendment dated May 2, 2008 to the Stock Purchase Agreement by and between PPL Corporation, as Seller, and UGI Utilities, Inc., as Buyer, dated as of March 5, 2008 | Utilities | Form 10-Q (3/31/08) | 10.2 | ||||||||
| 10.22 | Purchase and Sale Agreement by and between Southern Union Company, as Seller, and UGI Corporation, as Buyer, dated as of January 26, 2006 | UGI | Form 8-K (1/26/06) | 10.1 | ||||||||
| 10.23 | Gas Service Delivery and Supply Agreement between Utilities and UGI Energy Services, Inc. dated August 1, 2004 | Utilities | Form 10-K (9/30/04) | 10.32 | ||||||||
| 10.24 | Service Agreement (Rate FSS) dated as of November 1, 1989 between Utilities and Columbia, as modified pursuant to the orders of the Federal Energy Regulatory Commission at Docket No. RS92-5-000 reported at Columbia Gas Transmission Corp., 64 FERC ¶61,060 (1993), order on rehearing, 64 FERC ¶61,365 (1993) | UGI | Form 10-K (9/30/95) | 10.5 | ||||||||
| 10.25 | Storage Transportation Service Agreement (Rate Schedule SST) between Utilities and Columbia dated November 1, 1993, as modified pursuant to orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.25 | ||||||||
| 10.26 | Amendment No. 1 dated November 1, 2004, to the Service Agreement (Rate FSS) dated as of November 1, 1989 between UGI Utilities and Columbia, as modified pursuant to the orders of the Federal Energy Regulatory Commission at Docket No. RS92-5-000 reported at Columbia Gas Transmission Corp., 64 FERC ¶61,060 (1993), order on rehearing, 64 FERC ¶61,365 (1993) | Utilities | Form 10-K (9/30/04) | 10.26 | ||||||||
| 10.27 | Firm Transportation Service Agreement (Rate Schedule FTS) between Utilities and Columbia Gas Transmission dated November 1, 2004 | Utilities | Form 10-K (9/30/04) | 10.34 | ||||||||
28
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.28 | Service Agreement (Rate FSS) dated August 16, 2004 between Columbia Gas Transmission Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.4 | ||||||||
| 10.29 | Service Agreement (Rate SST) dated August 16, 2004 between Columbia Gas Transmission Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.5 | ||||||||
| 10.30 | FSS Service Agreement No. 49789, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.) | Utilities | Form 8-K (10/1/08) | 10.2 | ||||||||
| 10.31 | FSS Service Agreement No. 49791, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.) | Utilities | Form 8-K (10/1/08) | 10.3 | ||||||||
| 10.32 | FSS Service Agreement No. 80935, dated October 29, 2004, by and between Columbia Gas Transmission, LLC and UGI Central Penn Gas, Inc. | Utilities | Form 10-Q (3/31/09) | 10.3 | ||||||||
| 10.33 | SST Service Agreement No. 49788, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.) | Utilities | Form 8-K (10/1/08) | 10.5 | ||||||||
| 10.34 | SST Service Agreement No. 49790, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.) | Utilities | Form 8-K (10/1/08) | 10.6 | ||||||||
| 10.35 | SST Service Agreement No. 80934, dated as of October 29, 2004, by and between Columbia Gas Transmission, LLC and UGI Central Penn Gas, Inc. | Utilities | Form 10-Q (3/31/09) | 10.4 | ||||||||
| 10.36 | No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.27 | ||||||||
| 10.37 | No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated October 31, 2000, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.28 | ||||||||
| 10.38 | Firm Transportation Service Agreement (Rate Schedule FT-1) between Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.29 | ||||||||
29
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.39 | Service Agreement for comprehensive delivery service (Rate CDS) dated February 23, 1999 between UGI Utilities, Inc. and Texas Eastern Transmission Corporation | UGI | Form 10-K (9/30/00) | 10.41 | ||||||||
| 10.40 | Amendment No. 1 dated November 1, 2004, to the No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/04) | 10.30 | ||||||||
| 10.41 | Amendment No. 1 dated November 1, 2004, to the Firm Transportation Service Agreement (Rate Schedule FT-1) between Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/04) | 10.33 | ||||||||
| 10.42 | Firm Transportation Service Agreement (Rate Schedule FT) between Utilities and Transcontinental Gas Pipe Line dated October 1, 1996, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.31 | ||||||||
| 10.43 | Amendment dated March 20, 2007 to the Firm Transportation Service Agreement (Rate Schedule FT) dated October 1, 1996 between UGI Utilities and Transcontinental Gas Pipe Line Corporation, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 8-K (3/20/07) | 10.1 | ||||||||
| 10.44 | Firm Transportation Service Agreement (Rate FT) dated February 1, 1992 between Transcontinental Gas Pipe Line Corporation and PG Energy (as successor to Pennsylvania Gas and Water Company) | Utilities | Form 8-K (8/24/06) | 10.7 | ||||||||
| 10.45 | Firm Transportation Service Agreement (Rate FT) dated July 10, 1997 between Transcontinental Gas Pipe Line Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.6 | ||||||||
| 10.46 | Firm Storage and Delivery Service Agreement (Rate GSS) dated July 1, 1996 between Transcontinental Gas Pipe Line Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.8 | ||||||||
| *12.1 | Computation of Ratio of Earnings to Fixed Charges | |||||||||||
| 14 | Code of Ethics for principal executive, financial and accounting officers | UGI | Form 10-K (9/30/03) | 14 | ||||||||
| *23 | Consent of PricewaterhouseCoopers LLP | |||||||||||
30
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| *31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2009 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||||
| *31.2 | Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2009 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||||
| *32 | Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2009, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |||||||||||
| * | Filed herewith. | |
| ** | As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement. |
31
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
| UGI UTILITIES, INC. | ||||
| Date: November 20, 2009 | By: | /s/ John C. Barney | ||
| John C. Barney | ||||
| Senior Vice President — Finance and Chief Financial Officer | ||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 20, 2009 by the following persons on behalf of the Registrant in the capacities indicated.
| Signature | Title | |
/s/ John L. Walsh | President and Chief Executive Officer (Principal Executive Officer), Vice Chairman and Director | |
| /s/ Lon R. Greenberg | Chairman and Director | |
/s/ John C. Barney | Sr. Vice President — Finance and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | |
| /s/ Stephen D. Ban | Director | |
| /s/ Richard C. Gozon | Director | |
| /s/ Ernest E. Jones | Director | |
| /s/ Anne Pol | Director | |
| /s/ M. Shawn Puccio | Director | |
| /s/ Marvin O. Schlanger | Director | |
| /s/ Roger B. Vincent | Director | |
Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:
No annual report or proxy material was sent to security holders in Fiscal 2009.
32
Table of Contents
UGI UTILITIES, INC.
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2009
F-1
Table of Contents
UGI UTILITIES, INC.
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
| Pages | ||||
| Financial Statements: | ||||
| F-3 | ||||
| F-4 | ||||
| F-5 | ||||
| F-6 | ||||
| F-7 | ||||
| F-8 to F-31 | ||||
| Financial Statement Schedule: | ||||
| For the years ended September 30, 2009, 2008 and 2007: | ||||
| S-1 | ||||
We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
F-2
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of UGI Utilities, Inc.:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1), present fairly, in all material respects, the financial position of UGI Utilities, Inc. and its subsidiaries at September 30, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under item 15(a)(2) presents 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 maintained, in all material respects, effective internal control over financial reporting as of September 30, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, 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 on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, 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.
As discussed in Note 3 to the consolidated financial statements, the Company has adopted new accounting guidance for uncertain tax positions effective October 1, 2007.
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
November 20, 2009
Philadelphia, Pennsylvania
November 20, 2009
F-3
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
| September 30, | ||||||||
| 2009 | 2008 | |||||||
ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 13,523 | $ | 3,483 | ||||
| Restricted cash | — | 34,037 | ||||||
| Accounts receivable (less allowances for doubtful accounts of $11,384 and $10,369, respectively) | 74,286 | 70,259 | ||||||
| Accounts receivable — related parties | 3,378 | 1,946 | ||||||
| Accrued utility revenues | 20,980 | 20,823 | ||||||
| Inventories | 196,598 | 161,272 | ||||||
| Deferred income taxes | 24,905 | 13,712 | ||||||
| Regulatory assets | 19,584 | 15,987 | ||||||
| Derivative financial instruments | 867 | 506 | ||||||
| Prepaid expenses & other current assets | 5,167 | 3,380 | ||||||
| Total current assets | 359,288 | 325,405 | ||||||
| Property, plant and equipment | 2,056,877 | 1,669,056 | ||||||
| Less accumulated depreciation and amortization | (692,082 | ) | (562,135 | ) | ||||
| Net property, plant and equipment | 1,364,795 | 1,106,921 | ||||||
| Goodwill | 180,145 | 161,726 | ||||||
| Regulatory assets | 121,960 | 91,396 | ||||||
| Other assets | 4,049 | 9,018 | ||||||
| Total assets | $ | 2,030,237 | $ | 1,694,466 | ||||
LIABILITIES AND STOCKHOLDER’S EQUITY | ||||||||
| Current liabilities: | ||||||||
| Bank loans | $ | 154,000 | $ | 57,000 | ||||
| Accounts payable | 53,265 | 57,384 | ||||||
| Accounts payable — related parties | 8,746 | 14,680 | ||||||
| Employee compensation and benefits accrued | 12,504 | 9,105 | ||||||
| Dividends and interest accrued | 10,507 | 8,797 | ||||||
| Customer deposits and refunds | 48,073 | 40,422 | ||||||
| Derivative financial instruments | — | 23,488 | ||||||
| Deferred fuel refunds | 30,846 | — | ||||||
| Other current liabilities | 39,882 | 13,287 | ||||||
| Total current liabilities | 357,823 | 224,163 | ||||||
| Long-term debt | 640,000 | 532,000 | ||||||
| Deferred income taxes | 168,830 | 171,623 | ||||||
| Deferred investment tax credits | 5,670 | 6,039 | ||||||
| Pension and postretirement benefit obligations | 150,499 | 59,993 | ||||||
| Other noncurrent liabilities | 61,372 | 33,078 | ||||||
| Total liabilities | 1,384,194 | 1,026,896 | ||||||
| Commitments and contingencies (note 13) | ||||||||
| Common stockholder’s equity: | ||||||||
| Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares) | 60,259 | 60,259 | ||||||
| Additional paid-in capital | 467,160 | 466,888 | ||||||
| Retained earnings | 201,710 | 184,201 | ||||||
| Accumulated other comprehensive loss | (83,086 | ) | (43,778 | ) | ||||
| Total common stockholder’s equity | 646,043 | 667,570 | ||||||
| Total liabilities and stockholder’s equity | $ | 2,030,237 | $ | 1,694,466 | ||||
See accompanying notes to consolidated financial statements.
F-4
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
| Year Ended | ||||||||||||
| September 30, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| Revenues | $ | 1,381,260 | $ | 1,289,053 | $ | 1,183,247 | ||||||
| Costs and expenses: | ||||||||||||
| Cost of sales — gas, fuel and purchased power (excluding depreciation shown below) | 944,793 | 920,413 | 816,451 | |||||||||
| Operating and administrative expenses | 191,263 | 147,131 | 140,013 | |||||||||
| Operating and administrative expenses — related parties | 14,964 | 11,802 | 11,584 | |||||||||
| Taxes other than income taxes | 16,917 | 18,264 | 17,736 | |||||||||
| Depreciation | 48,873 | 39,464 | 39,176 | |||||||||
| Amortization | 2,239 | 1,861 | 1,758 | |||||||||
| Other income, net | (7,261 | ) | (12,924 | ) | (8,564 | ) | ||||||
| 1,211,788 | 1,126,011 | 1,018,154 | ||||||||||
| Operating income | 169,472 | 163,042 | 165,093 | |||||||||
| Interest expense | 43,918 | 39,065 | 42,327 | |||||||||
| Income before income taxes | 125,554 | 123,977 | 122,766 | |||||||||
| Income taxes | 46,832 | 49,950 | 48,579 | |||||||||
| Net income | $ | 78,722 | $ | 74,027 | $ | 74,187 | ||||||
See accompanying notes to consolidated financial statements.
F-5
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
| Year Ended | ||||||||||||
| September 30, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
| Net income | $ | 78,722 | $ | 74,027 | $ | 74,187 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
| Depreciation and amortization | 51,112 | 41,325 | 40,934 | |||||||||
| Deferred income taxes, net | 17,530 | 7,516 | 16,281 | |||||||||
| Pension expense | 7,124 | 134 | 1,871 | |||||||||
| Provision for uncollectible accounts | 19,193 | 18,210 | 14,353 | |||||||||
| Other, net | 13,456 | 2,115 | 2,962 | |||||||||
| Net change in: | ||||||||||||
| Accounts receivable and accrued utility revenues | (15,133 | ) | (19,293 | ) | (27,934 | ) | ||||||
| Inventories | (12,742 | ) | 491 | 351 | ||||||||
| Deferred fuel costs, net of changes in unsettled derivatives | 10,272 | 21,521 | (26,953 | ) | ||||||||
| Accounts payable | (19,437 | ) | (3,311 | ) | 14,386 | |||||||
| Storage agreement security deposits | 19,000 | — | — | |||||||||
| Other current assets | (1,072 | ) | 696 | 2,033 | ||||||||
| Other current liabilities | 8,389 | (875 | ) | 21,021 | ||||||||
| Net cash provided by operating activities | 176,414 | 142,556 | 133,492 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
| Expenditures for property, plant and equipment | (79,084 | ) | (64,351 | ) | (73,411 | ) | ||||||
| Net costs of property, plant and equipment disposals | (5,114 | ) | (521 | ) | (1,492 | ) | ||||||
| Acquisitions of businesses, net of cash acquired | (292,551 | ) | — | 23,670 | ||||||||
| Proceeds from sale of CPP | 32,269 | — | — | |||||||||
| Decrease (increase) in restricted cash | 34,037 | (27,395 | ) | (3,945 | ) | |||||||
| Net cash used by investing activities | (310,443 | ) | (92,267 | ) | (55,178 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
| Payment of dividends | (61,211 | ) | (68,762 | ) | (40,006 | ) | ||||||
| Increase (decrease) in bank loans | 97,000 | (133,000 | ) | (26,000 | ) | |||||||
| Issuances of long-term debt | 108,000 | 20,000 | 20,000 | |||||||||
| Repayments of long-term debt | — | — | (20,000 | ) | ||||||||
| Capital contribution from UGI Corporation | — | 120,000 | — | |||||||||
| Cash portion of UGI HVAC dividend | — | (1,381 | ) | — | ||||||||
| Excess tax benefits from equity-based payment arrangements | 280 | 130 | 957 | |||||||||
| Net cash provided (used) by financing activities | 144,069 | (63,013 | ) | (65,049 | ) | |||||||
| Cash and cash equivalents increase (decrease) | $ | 10,040 | $ | (12,724 | ) | $ | 13,265 | |||||
CASH AND CASH EQUIVALENTS: | ||||||||||||
| End of year | $ | 13,523 | $ | 3,483 | $ | 16,207 | ||||||
| Beginning of year | 3,483 | 16,207 | 2,942 | |||||||||
| Increase (decrease) | $ | 10,040 | $ | (12,724 | ) | $ | 13,265 | |||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
| Cash paid for: | ||||||||||||
| Interest | $ | 40,452 | $ | 44,273 | $ | 32,944 | ||||||
| Income taxes | $ | 26,919 | $ | 40,625 | $ | 27,547 | ||||||
See accompanying notes to consolidated financial statements.
F-6
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(Thousands of dollars)
| Accumulated | Total | |||||||||||||||||||
| Additional | Other | Common | ||||||||||||||||||
| Common | Paid-in | Retained | Comprehensive | Stockholder’s | ||||||||||||||||
| Stock | Capital | Earnings | Income (Loss) | Equity | ||||||||||||||||
| Balance September 30, 2006 | $ | 60,259 | $ | 345,801 | $ | 144,833 | $ | (3,794 | ) | $ | 547,099 | |||||||||
| Net income | 74,187 | 74,187 | ||||||||||||||||||
| Net change in fair value of derivative instruments (net of tax of $21) | (30 | ) | (30 | ) | ||||||||||||||||
| Reclassifications of net gains on derivative instruments (net of tax of $1,068) | (1,506 | ) | (1,506 | ) | ||||||||||||||||
| Comprehensive income | 74,187 | (1,536 | ) | 72,651 | ||||||||||||||||
| Adjustment to initially apply new accounting for pension and postretirement benefits | (9,987 | ) | (9,987 | ) | ||||||||||||||||
| Cash dividends — Common Stock | (40,006 | ) | (40,006 | ) | ||||||||||||||||
| Other | 957 | 957 | ||||||||||||||||||
| Balance September 30, 2007 | 60,259 | 346,758 | 179,014 | (15,317 | ) | 570,714 | ||||||||||||||
| Net income | 74,027 | 74,027 | ||||||||||||||||||
| Cumulative effect from initial adoption of new accounting for uncertain tax positions | (230 | ) | (230 | ) | ||||||||||||||||
| Net change in fair value of derivative instruments (net of tax of $695) | 979 | 979 | ||||||||||||||||||
| Reclassifications of net gains on derivative instruments (net of tax of $176) | (248 | ) | (248 | ) | ||||||||||||||||
| Benefit plans, principally actuarial losses (net of tax of $20,718) | (29,211 | ) | (29,211 | ) | ||||||||||||||||
| Reclassifications of benefit plans actuarial losses and prior service costs (net of tax of $13) | 19 | 19 | ||||||||||||||||||
| Comprehensive income | 73,797 | (28,461 | ) | 45,336 | ||||||||||||||||
| Cash dividends — Common Stock | (68,762 | ) | (68,762 | ) | ||||||||||||||||
| Capital contribution from UGI | 120,000 | 120,000 | ||||||||||||||||||
| Dividend of UGI HVAC | 152 | 152 | ||||||||||||||||||
| Other | 130 | 130 | ||||||||||||||||||
| Balance September 30, 2008 | 60,259 | 466,888 | 184,201 | (43,778 | ) | 667,570 | ||||||||||||||
| Net income | 78,722 | 78,722 | ||||||||||||||||||
| Reclassifications of net losses on derivative instruments (net of tax of $483) | 681 | 681 | ||||||||||||||||||
| Benefit plans, principally actuarial losses (net of tax of $29,978) | (42,270 | ) | (42,270 | ) | ||||||||||||||||
| Reclassifications of benefit plans actuarial losses and prior service costs (net of tax of $1,617) | 2,281 | 2,281 | ||||||||||||||||||
| Comprehensive income | 78,722 | (39,308 | ) | 39,414 | ||||||||||||||||
| Cash dividends — Common Stock | (61,221 | ) | (61,221 | ) | ||||||||||||||||
| Other | 272 | 8 | 280 | |||||||||||||||||
| Balance September 30, 2009 | $ | 60,259 | $ | 467,160 | $ | 201,710 | $ | (83,086 | ) | $ | 646,043 | |||||||||
See accompanying notes to consolidated financial statements.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
| 1. | NATURE OF OPERATIONS |
Organization and Principles of Consolidation
UGI Utilities, Inc., a wholly owned subsidiary of UGI Corporation (“UGI”), and its wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”) own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania. 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;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and 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.”
Effective January 1, 2007, UGI Utilities contributed its heating, ventilation and air conditioning services business to its wholly owned second-tier subsidiary, UGI HVAC Services, Inc. (“UGI HVAC”). Effective April 1, 2008, UGI Utilities transferred by dividend its ownership interest in UGI HVAC to UGI. UGI HVAC (prior to its dividend to UGI) and UGI Penn HVAC Services, Inc. are hereafter referred to as the “HVAC Business.”
The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.
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, revenue, 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. As a result, actual results may be different from these estimates and assumptions.
Certain prior-year amounts have been reclassified to conform to the current year presentation.
Principles of Consolidation
Our consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or “the Company”). We eliminate all significant intercompany accounts when we consolidate.
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance on regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs will be recovered in rates in the future. Likewise, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. 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, see Note 5.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Fair Value Measurements
We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments. We adopted new accounting guidance with respect to determining fair value measurements effective October 1, 2008. The new guidance defines fair value 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. The new guidance clarifies that fair value should be 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. The new guidance requires fair value measurements to 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 swap contracts. | |
| • | 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 financial transmission rights (“FTRs”). | |
| • | 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, 2009. |
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. The adoption of the new fair value guidance effective October 1, 2008 did not have a material impact on the financial statements. See Note 14 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 be recognized as either assets or liabilities and measured at fair value. 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.
In the case of natural gas derivative financial instruments used by Gas Utility, changes in fair value are included in deferred fuel costs 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”), 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. Certain of our derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments are included in cash flows from operating activities.
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and related supplemental information required by GAAP, see Note 15.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Revenue Recognition
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. Nonregulated revenues are recognized as services are performed or products are delivered.
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.
Income Taxes
We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to Utilities’ plant additions over the service lives of the related property. Utilities reduce its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize.
We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is generally consistent with income taxes calculated on a separate return basis. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income.
Comprehensive Income
The components of AOCI at September 30, 2009 and 2008 follow:
| Derivative | ||||||||||||
| Postretirement | Instruments Net | |||||||||||
| Benefit Plans | Losses | Total | ||||||||||
| Balance, September 30, 2009 | $ | (79,142 | ) | $ | (3,944 | ) | $ | (83,086 | ) | |||
| Balance, September 30, 2008 | $ | (39,152 | ) | $ | (4,626 | ) | $ | (43,778 | ) | |||
Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive loss of $39,308, $28,461 and $1,536 for Fiscal 2009, Fiscal 2008 and Fiscal 2007, respectively, reflects changes in actuarial gains and losses on postretirement benefit plans, gains or losses on interest rate protection agreements (“IRPAs”) and, through the date of its expiration in December 2007, changes in the fair value of an electric price swap agreement, net of reclassifications to net income. Fiscal 2007 AOCI also includes an after-tax charge of $9,987 associated with the initial adoption of FASB guidance for employers’ accounting for defined benefit pension and other postretirement plans effective September 30, 2007 (see “Accounting Changes” below).
Cash and Cash Equivalents
All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Restricted Cash
Restricted cash represents those cash balances in our commodity futures brokerage accounts which are restricted from withdrawal.
Inventories
Our inventories are stated at the lower of cost or market. Substantially all of our inventory is determined on an average cost method.
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 for Utilities’ plant and equipment on a straight-line method 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 2.4% in Fiscal 2009 and Fiscal 2008, and 2.7% in Fiscal 2007. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.9% in Fiscal 2009, 2.6% in Fiscal 2008 and 2.7% in Fiscal 2007. When Utilities retires depreciable utility plant and equipment, we charge the original cost, net of removal costs and salvage value, 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
Our goodwill is the result of business acquisitions. Goodwill is subject to tests for impairment at least annually. We perform goodwill impairment tests more frequently than annually if events or circumstances indicate that the value of goodwill might be impaired. When performing our impairment tests, we use discounted estimates of future cash flows. No provisions for goodwill impairments were recorded during Fiscal 2009, Fiscal 2008 or Fiscal 2007.
Impairment of Long-Lived Assets
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 to be generated by such assets. No provisions for impairments were recorded during Fiscal 2009, Fiscal 2008 or Fiscal 2007.
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 market prices. 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 10).
Equity-Based Compensation
All of our equity-based compensation principally comprising UGI stock options and grants of UGI stock-based equity instruments (“Units”) is 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.
For additional information on our equity-based compensation plans and related disclosures, see Note 12.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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. CPG Gas and PNG Gas base rate revenues provide for the recovery of environmental investigation and remediation costs associated with Pennsylvania sites. For further information, see Note 13.
Subsequent Events
Management has evaluated the impact of subsequent events through November 20, 2009, the date the financial statements were filed with the U.S. Securities and Exchange Commission, and the effects of such evaluation have been reflected in the financial statements and related disclosures.
3. ACCOUNTING CHANGES
Adoption of New Accounting Standards
FASB Accounting Standards Codification.In June 2009, the FASB issued guidance identifying the sources of accounting principles and the framework for selecting principles used in the preparation of financial statements by nongovernmental entities in accordance with GAAP. The guidance has established the FASB Accounting Standards Codification (“Codification”) as the source of such authoritative accounting principles. The identification of the Codification as the source of authoritative accounting principles does not change existing GAAP. The Codification is effective for all financial statements issued after September 15, 2009.
Subsequent Events.On June 30, 2009, we adopted accounting guidance issued by the FASB in May 2009 on accounting and disclosure of subsequent events. The adoption of this guidance did not change our prior accounting practice other than to disclose the date through which subsequent events were evaluated and the basis for that date. Other than this new disclosure, adoption of this guidance did not have a significant impact on our consolidated financial statements.
Disclosures about Derivative Instruments and Hedging Activities.Effective with our disclosures for the quarter ended March 31, 2009, we adopted accounting guidance issued by the FASB in March 2008 on enhanced disclosures about derivative instruments and hedging activities. The enhanced disclosures provide greater transparency by requiring entities to provide qualitative disclosures about their objectives and strategies for using derivative instruments and quantitative disclosures that detail the fair value amounts of, and gains and losses on, derivative instruments. Disclosures about credit risk-related contingent features of derivative instruments are also required See Note 15 for disclosures required by the new guidance.
Fair Value Measurements.On October 1, 2008, we adopted new guidance issued by the FASB in September 2006 on fair value measurements. The new guidance defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. In February 2008, two amendments to this guidance were issued to exclude leases from the new fair value guidance and to delay the effective date of the new fair value guidance until fiscal years beginning after November 15, 2008 (Fiscal 2010) for non-financial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a non-recurring basis. The adoption of the initial phase of the fair value guidance did not have a material effect on our financial statements and we do not anticipate that the adoption of the remainder of the fair value guidance will have a material effect on our consolidated financial statements. In October 2008, two additional amendments to the fair value guidance were issued which clarify the application of the fair value measurement guidance to financial assets in a market that is not active and when the volume and level of activity for the asset or liability have significantly decreased. These further amendments did not have an impact on our results of operations or financial condition. See Notes 2 and 14 for further information on fair value measurements in accordance with the new guidance.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Offsetting of Amounts Related to Certain Contracts. On October 1, 2008, we adopted accounting guidance issued by the FASB in April 2007 which permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. In addition, upon the adoption, companies are permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements. The new guidance requires retrospective application for all periods presented. We have elected to continue our policy of reflecting derivative asset or liability positions, as well as cash collateral, on a gross basis in our Consolidated Balance Sheets. Accordingly, the adoption of the new guidance did not impact our financial statements.
Fair Value Option for Financial Assets and Liabilities.On October 1, 2008, we adopted accounting guidance issued by the FASB in February 2007 by which we may elect to report individual financial instruments and certain items at fair value with changes in fair value reported in earnings. Once made, this election is irrevocable for those items. The adoption of this guidance did not impact our financial statements.
Uncertainty in Income Taxes.Effective October 1, 2007, we adopted new interpretive guidance issued by the FASB on accounting for uncertainty related to income taxes. The new guidance provides a comprehensive model for the recognition, measurement and disclosure in financial statements of uncertain income tax positions that a company has taken or expects to take on a tax return. The cumulative effect from the adoption of the new guidance was recorded as a $230 decrease to the October 1, 2007 retained earnings balance.
Pension and Postretirement Plans.Effective September 30, 2007, we adopted new accounting guidance issued by the FASB relating to employers accounting for pension and postretirement benefit plans. The new guidance requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and postretirement benefit plans, such as retiree health and life, with current year changes recognized in shareholders’ equity. The new guidance did not change the existing criteria for measurement of periodic benefit costs, plan assets or benefit obligations. The incremental effect of the initial adoption of the new guidance reduced stockholders’ equity at September 30, 2007 by $9,987.
New Accounting Standards Not Yet Implemented
Enhanced Disclosures of Postretirement Plan Assets. In December 2008, the FASB issued new guidance requiring more detailed disclosures about employers’ postretirement plan assets, including employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets, and valuation techniques used to measure the fair value of plan assets. The provisions of this guidance are effective for fiscal years ending after December 15, 2009 (Fiscal 2010). Because this new guidance relates to disclosure only, it will not impact the financial statements.
Intangible Asset Useful Lives.In April 2008, the FASB issued new guidance which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under GAAP. The intent of the new guidance is to improve the consistency between the useful life of a recognized intangible asset under GAAP relating to intangible asset accounting and the period of expected cash flows used to measure the fair value of the asset under GAAP relating to business combinations and other applicable accounting literature. The new guidance is effective for financial statements issued for fiscal years beginning after December 15, 2008 (Fiscal 2010) and must be applied prospectively to intangible assets acquired after the effective date. We do not believe the new guidance will have a significant impact on our financial statements.
Business Combinations.In December 2007, the FASB issued new guidance on the accounting for business combinations. The new guidance applies to all transactions or other events in which an entity obtains control of one or more businesses. The new guidance establishes, among other things, principles and requirements for how the acquirer (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in a business combination or gain from a bargain purchase; and (3) determines what information with respect to a business combination should be disclosed. The new guidance applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008 (Fiscal 2010). Among the more significant changes in accounting for acquisitions are (1) transaction costs will generally be expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, will generally be recorded at fair value with subsequent adjustments recognized in operations (rather than as adjustments to the purchase price); and (3) decreases in valuation allowances on acquired deferred tax assets will be recognized in operations (rather than decreases in goodwill). Generally, the effects of the new guidance will depend on future acquisitions.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
4. ACQUISITION OF PPL GAS UTILITIES CORPORATION
On October 1, 2008, UGI Utilities acquired all of the outstanding stock of PPL Gas Utilities Corporation (now CPG), the natural gas distribution utility of PPL Corporation (“PPL”), for cash consideration of $267,600 plus estimated working capital of $35,370 (the “CPG Acquisition”). Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central Penn Propane, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas Propane, L.P. (“AmeriGas OLP”), an affiliate of UGI, for cash consideration of $32,000 plus estimated working capital of $1,621. CPG distributes natural gas to approximately 76,000 customers in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. CPP sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition at closing with a combination of $120,000 cash contributed by UGI on September 25, 2008, proceeds from the issuance on October 1, 2008 of $108,000 principal amount of 6.375% Senior Notes due 2013 and approximately $75,000 of borrowings under UGI Utilities’ Revolving Credit Agreement. UGI Utilities used the $33,621 of cash proceeds from the sale of the assets of CPP to AmeriGas OLP to reduce its revolving credit agreement borrowings.
The assets and liabilities resulting from the CPG Acquisition which reflect the final purchase price allocation are included in our Consolidated Balance Sheet at September 30, 2009. Pursuant to the CPG Acquisition purchase agreement, the purchase price was subject to adjustment for the difference between the estimated working capital of $35,370 and the actual working capital as of the closing date agreed to by both UGI Utilities and PPL. During Fiscal 2009, UGI Utilities and PPL reached an agreement on the working capital adjustment pursuant to which PPL paid UGI Utilities $9,738 in cash, including interest. Also during Fiscal 2009, UGI Utilities and AmeriGas OLP reached an agreement on the working capital adjustment associated with UGI Utilities’ sale of the assets of CPP to AmeriGas OLP pursuant to which UGI Utilities reimbursed AmeriGas OLP $1,352.
The purchase price of the CPG Acquisition, including transaction fees and expenses and incurred liabilities totaling approximately $2,300, has been allocated to the assets acquired and liabilities assumed as follows:
| Current assets less current liabilities | $ | 22,065 | ||
| Property, plant and equipment | 227,301 | |||
| Goodwill | 18,419 | |||
| Utility regulatory assets | 22,466 | |||
| Other assets | 7,412 | |||
| Noncurrent liabilities | (34,383 | ) | ||
| Total | $ | 263,280 | ||
The primary item that results in goodwill are the synergies between CPG Gas and our existing utility businesses. Substantially all of the goodwill is deductible for income tax purposes over a fifteen-year period.
The operating results of CPG are included in our consolidated results beginning October 1, 2008. The following table presents pro forma income statement data for Fiscal 2008 as if the CPG Acquisition had occurred as of October 1, 2007:
| 2008 | ||||
| (pro forma) | ||||
| Revenues | $ | 1,475,113 | ||
| Net income | $ | 82,927 | ||
The pro forma results of operations reflect CPG’s historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The pro forma amounts are not necessarily indicative of the operating results that would have occurred had the CPG Acquisition been completed as of the date indicated, nor are they necessarily indicative of future operating results.
Also during Fiscal 2007, UGI Utilities received a $23,670 working capital adjustment payment associated with its Fiscal 2006 acquisition of Southern Union Company’s PG Energy Division, a natural gas distribution utility located in northeastern Pennsylvania (now PNG Gas).
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
5. 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:
| 2009 | 2008 | |||||||
| Regulatory assets: | ||||||||
| Income taxes recoverable | $ | 79,492 | $ | 73,695 | ||||
| Postretirement benefits | 2,473 | 4,321 | ||||||
| CPG Gas pension and postretirement plans | 8,572 | — | ||||||
| Environmental costs | 26,877 | 9,009 | ||||||
| Deferred fuel costs | 19,584 | 15,987 | ||||||
| Other | 4,546 | 4,371 | ||||||
| Total regulatory assets | $ | 141,544 | $ | 107,383 | ||||
| Regulatory liabilities: | ||||||||
| Postretirement benefits | $ | 9,310 | $ | 8,886 | ||||
| Environmental overcollections | 8,720 | — | ||||||
| Deferred fuel refunds | 30,846 | — | ||||||
| Total regulatory liabilities | $ | 48,876 | $ | 8,886 | ||||
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.
Postretirement benefits.The PUC has authorized UGI Utilities to recover certain early retirement benefit costs as well as other postretirement benefit costs incurred prior to such amounts being reflected in tariff rates. These costs are reflected as regulatory assets in the table above. At September 30, 2009, UGI Utilities expects to recover these costs over periods ranging from 1 to approximately 10 years.
Gas Utility and Electric Utility are also 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, in accordance with GAAP relating to pension and postretirement plans, UGI Utilities’ postretirement regulatory liability is adjusted annually to reflect changes in the funded status of UGI Gas’ and Electric Utility’s postretirement benefit plan.
CPG Gas pension and postretirement plans.This regulatory asset represents the portion of prior service cost and net actuarial losses associated with CPG Gas pension and postretirement plans that will be 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 relating to pension and postretirement plans. These costs are amortized over the average remaining life expectancy of the plan participants. These regulatory assets are reflected net of associated deferred income taxes.
Environmental costs.Environmental costs represents 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 that CPG Gas and PNG Gas expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 13). UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. PNG Gas and CPG Gas are currently recovering and expect to continue to recover these costs in base rate revenues. At September 30, 2009, the period over which PNG Gas and CPG Gas expect to recover these costs will depend upon future remediation activity.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Deferred fuel costs and refunds.Gas Utility’s tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost (“PGC”) rates. The clauses provide for periodic adjustments to PGC rates for the difference between the total amount of purchased gas costs collected from customers and the recoverable costs incurred. In accordance with GAAP relating to rate-regulated entities, we defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers. Net undercollected gas 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 financial instruments are included in deferred fuel refunds or costs. Unrealized losses on such contracts at September 30, 2008 were $23,321. There were no such gains or losses at September 30, 2009. UGI Utilities expects to recover or refund deferred fuel costs generally over a period of 1 to 2 years.
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.
Other.Other regulatory assets comprise a number of items including, among others, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2009, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.
UGI Utilities’ regulatory liabilities relating to postretirement benefits and environmental overcollections 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
PNG and CPG Base Rate Filings. On January 28, 2009, PNG and CPG filed separate requests with the PUC to increase base operating revenues by $38,118 annually for PNG and $19,635 annually for CPG to fund system improvements and operations necessary to maintain safe and reliable natural gas service and energy assistance for low income customers as well as energy conservation programs for all customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on agreements with the opposing parties regarding the requested base operating revenue increases. On August 27, 2009, the PUC approved the settlement agreements which resulted in a $19,800 base operating revenue increase for PNG Gas and a $10,000 base operating revenue increase for CPG Gas. The increases became effective August 28, 2009 and did not have a material effect on Fiscal 2009 results.
Electric Utility.As a result of Pennsylvania’s Electricity Generation Customer Choice and Competition Act that became effective January 1, 1997, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. Electric Utility remains the provider of last resort (“POLR”) for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006.
In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement, Electric Utility increased its POLR rates effective January 1, 2009, which increased the average cost to a residential heating customer by approximately 1.5% over such costs in effect during calendar year 2008. Effective January 1, 2008, Electric Utility increased its POLR rates which increased the average cost to a residential heating customer by approximately 5.5% over such costs in effect during calendar year 2007. Effective January 1, 2007, Electric Utility increased the average cost to a residential heating customer by approximately 35% over such costs in effect during calendar year 2006.
On July 17, 2008, the PUC approved Electric Utility’s default service procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s default service regulations. These plans do not affect Electric Utility’s existing POLR settlement effective through December 31, 2009. The approved plans specify how Electric Utility will solicit and acquire default service supplies for residential customers for the period January 1, 2010 through May 31, 2014, and for commercial and industrial customers for the period January 1, 2010 through May 31, 2011 (collectively, the “Settlement Term”). UGI Utilities filed a rate plan on August 29, 2008 for the Settlement Term. On January 22, 2009, the PUC approved a settlement of the rate filing that provides for Electric Utility to fully recover its default service costs. On October 1, 2009, UGI Utilities filed a default service plan to establish procurement rules applicable to the period after May 31, 2011 for its commercial and industrial customers.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
6. INVENTORIES
Inventories comprise the following at September 30:
| 2009 | 2008 | |||||||
| Gas Utility natural gas | $ | 189,747 | $ | 155,843 | ||||
| Materials, supplies and other | 6,851 | 5,429 | ||||||
| Total inventories | $ | 196,598 | $ | 161,272 | ||||
At September 30, 2009 and 2008, UGI Utilities was a party to one-year storage contract administrative agreements (“SCAAs”) expiring on October 1, 2009 and 2008, respectively. Pursuant to the 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 term of the SCAAs. Included among these contract administrative agreements is an agreement with UGI Energy Services, Inc., a second-tier, wholly owned subsidiary of UGI (see Note 18). 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 agreements but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above. The carrying value of gas storage inventories released under the SCAAs at September 30, 2009 and 2008 comprising 9.0 billion cubic feet (“bcf”) and 9.8 bcf of natural gas was $77,948 and $81,182, respectively. Effective November 1, 2009, UGI Utilities entered into three new SCAAs with terms ranging from one to three years.
7. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment comprise the following categories at September 30:
| 2009 | 2008 | |||||||
| Distribution | $ | 1,813,201 | $ | 1,520,346 | ||||
| Transmission | 76,826 | 28,547 | ||||||
| General and other | 166,850 | 120,163 | ||||||
| Total property, plant and equipment | $ | 2,056,877 | $ | 1,669,056 | ||||
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
8. DEBT
Long-term debt comprises the following at September 30:
| 2009 | 2008 | |||||||
| Senior Notes: | ||||||||
| 6.375% Notes, due September 2013 | $ | 108,000 | $ | — | ||||
| 5.75% Notes, due October 2016 | 175,000 | 175,000 | ||||||
| 6.21% Notes, due October 2036 | 100,000 | 100,000 | ||||||
| Medium-Term Notes: | ||||||||
| 5.53% Notes, due September 2012 | 40,000 | 40,000 | ||||||
| 5.37% Notes, due August 2013 | 25,000 | 25,000 | ||||||
| 5.16% Notes, due May 2015 | 20,000 | 20,000 | ||||||
| 7.37% Notes, due October 2015 | 22,000 | 22,000 | ||||||
| 5.64% Notes, due December 2015 | 50,000 | 50,000 | ||||||
| 6.17% Notes, due June 2017 | 20,000 | 20,000 | ||||||
| 7.25% Notes, due November 2017 | 20,000 | 20,000 | ||||||
| 5.67% Notes, due January 2018 | 20,000 | 20,000 | ||||||
| 6.50% Notes, due August 2033 | 20,000 | 20,000 | ||||||
| 6.13% Notes, due October 2034 | 20,000 | 20,000 | ||||||
| Total long-term debt | $ | 640,000 | $ | 532,000 | ||||
There are no principal payments of long-term debt due through Fiscal 2011; $40,000 is due in Fiscal 2012; $133,000 is due in Fiscal 2013; and no amounts are due in Fiscal 2014.
UGI Utilities has a revolving credit agreement (“Revolving Credit Agreement”) with banks providing for borrowings of up to $350,000 which expires in August 2011. Under The Revolving Credit Agreement, UGI Utilities may borrow at various prevailing interest rates, including LIBOR and the banks’ prime rate. UGI Utilities had borrowings outstanding under the Revolving Credit Agreement, which we classify as bank loans, totaling $154,000 at September 30, 2009 and $57,000 at September 30, 2008. The weighted-average interest rates on Revolving Credit Agreement borrowings at September 30, 2009 and 2008 were 0.59% and 5.0%, respectively. In conjunction with the October 1, 2008, CPG Acquisition, UGI made a $120,000 cash contribution to UGI Utilities on September 25, 2008. This cash contribution was used by UGI Utilities to reduce borrowings under the Revolving Credit Agreement. On October 1, 2008, UGI Utilities borrowed under the Revolving Credit Agreement to fund a portion of the CPG Acquisition (see Note 4).
The Revolving Credit Agreement requires UGI Utilities to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
9. INCOME TAXES
The provisions for income taxes consist of the following:
| 2009 | 2008 | 2007 | ||||||||||
| Current expense: | ||||||||||||
| Federal | $ | 19,302 | $ | 31,974 | $ | 24,727 | ||||||
| State | 10,000 | 10,460 | 7,571 | |||||||||
| Total current expense | 29,302 | 42,434 | 32,298 | |||||||||
| Deferred expense | 17,898 | 7,894 | 16,667 | |||||||||
| Investment tax credit amortization | (368 | ) | (378 | ) | (386 | ) | ||||||
| Total income tax expense | $ | 46,832 | $ | 49,950 | $ | 48,579 | ||||||
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
A reconciliation from the statutory federal tax rate to our effective tax rate is as follows:
| 2009 | 2008 | 2007 | ||||||||||
| Statutory federal tax rate | 35.0 | % | 35.0 | % | 35.0 | % | ||||||
| Difference in tax rate due to: | ||||||||||||
| State income taxes, net of federal | 3.6 | 4.7 | 4.8 | |||||||||
| Other, net | (1.3 | ) | 0.6 | (0.2 | ) | |||||||
| Effective tax rate | 37.3 | % | 40.3 | % | 39.6 | % | ||||||
Deferred tax liabilities (assets) comprise the following at September 30:
| 2009 | 2008 | |||||||
| Excess book basis over tax basis of property, plant and equipment | $ | 199,213 | $ | 164,870 | ||||
| Goodwill | 13,444 | 9,006 | ||||||
| Regulatory assets | 51,576 | 34,030 | ||||||
| Other | 1,883 | 1,954 | ||||||
| Gross deferred tax liabilities | 266,116 | 209,860 | ||||||
| Pension plan liabilities | (60,350 | ) | (21,713 | ) | ||||
| Allowance for doubtful accounts | (4,723 | ) | (4,340 | ) | ||||
| Deferred investment tax credits | (2,352 | ) | (2,505 | ) | ||||
| Employee-related expenses | (8,832 | ) | (5,224 | ) | ||||
| Regulatory liabilities | (16,648 | ) | (3,687 | ) | ||||
| Environmental liabilities | (9,256 | ) | (6,041 | ) | ||||
| Derivative financial instruments | (2,781 | ) | (3,280 | ) | ||||
| Other | (17,249 | ) | (5,159 | ) | ||||
| Gross deferred tax assets | (122,191 | ) | (51,949 | ) | ||||
| Net deferred tax liabilities | $ | 143,925 | $ | 157,911 | ||||
We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. UGI’s federal income tax returns are settled through the tax year 2006. UGI’s federal income tax return for Fiscal 2007 is currently under audit. Although it is not possible to predict with certainty the timing of the conclusion of UGI’s pending federal tax audit, we anticipate that the aforementioned federal tax audit will likely be completed during Fiscal 2010.
We file separate company income tax returns in a number of states but are subject to state income tax principally in Pennsylvania. Pennsylvania income tax returns are generally subject to examination for a period of three years after the filing of the respective returns.
During Fiscal 2009, $55 of interest income was recognized in income taxes in the Consolidated Statement of Income. As of September 30, 2009, we have unrecognized income tax benefits totaling $634 including related accrued interest of $71. If these unrecognized tax benefits were subsequently recognized, $560 would be recorded as a benefit to income taxes on the consolidated statement of income and, therefore, would impact the effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. The amount of reasonably possible changes in unrecognized tax benefits and related interest in the next twelve months is a net reduction of approximately $291.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
| Balance at October 1, 2007 | $ | 694 | ||
| Additions for tax positions of the current year | 66 | |||
| Additions for tax positions of prior years | 185 | |||
| Balance at September 30, 2008 | 945 | |||
| Additions for tax positions of the current year | 63 | |||
| Additions for tax positions of prior years | 197 | |||
| Settlements with tax authorities | (571 | ) | ||
| Balance at September 30, 2009 | $ | 634 | ||
10. EMPLOYEE RETIREMENT PLANS
Defined Benefit Pension and Other Postretirement Plans
We sponsor two defined benefit pension plans (“Pension Plans”) for employees hired prior to January 1, 2009 of UGI Utilities, PNG, CPG, UGI, and certain of UGI’s other wholly owned subsidiaries. In addition, we provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all active and retired employees.
Effective December 31, 2008, we merged two of our domestic defined benefit pension plans. The merged plan will maintain the separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger, we were required under GAAP to remeasure the combined plan’s assets and benefit obligations as of December 31, 2008 and recorded an after-tax charge to AOCI of $38,688. As a result of the remeasurement, Fiscal 2009 pension expense increased approximately $3,900 in the nine-month period subsequent to the remeasurement principally as a result of the amortization of actuarial losses.
The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets and the funded status of the pension and other postretirement plans as of September 30, 2009 and 2008. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect future compensation.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
| Pension | Other Postretirement | |||||||||||||||
| Benefits | Benefits | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Change in benefit obligations: | ||||||||||||||||
| Benefit obligations — beginning of year | $ | 300,578 | $ | 299,441 | $ | 9,713 | $ | 13,822 | ||||||||
| Service cost | 6,831 | 5,660 | 139 | 277 | ||||||||||||
| Interest cost | 22,904 | 19,064 | 843 | 802 | ||||||||||||
| Actuarial loss (gain) | 64,709 | (9,261 | ) | 1,557 | (1,794 | ) | ||||||||||
| Plan amendments | 42 | — | 46 | (357 | ) | |||||||||||
| Plan curtailment | — | — | — | (2,202 | ) | |||||||||||
| Acquisitions | 44,465 | — | 3,418 | — | ||||||||||||
| Benefits paid | (17,488 | ) | (14,326 | ) | (1,106 | ) | (835 | ) | ||||||||
| Benefit obligations — end of year | $ | 422,041 | $ | 300,578 | $ | 14,610 | $ | 9,713 | ||||||||
Change in plan assets: | ||||||||||||||||
| Fair value of plan assets — beginning of year | $ | 240,997 | $ | 290,112 | $ | 10,002 | $ | 12,173 | ||||||||
| Actual gain (loss) on assets | 14,527 | (34,789 | ) | 46 | (1,773 | ) | ||||||||||
| Employer contributions | — | — | 772 | 437 | ||||||||||||
| Acquisitions | 38,402 | — | — | — | ||||||||||||
| Benefits paid | (17,488 | ) | (14,326 | ) | (1,106 | ) | (835 | ) | ||||||||
| Fair value of plan assets — end of year | $ | 276,438 | $ | 240,997 | $ | 9,714 | $ | 10,002 | ||||||||
Funded status of the plans — end of year | $ | (145,603 | ) | $ | (59,581 | ) | $ | (4,896 | ) | $ | 289 | |||||
Assets (liabilities) recorded in the balance sheet: | ||||||||||||||||
| Prepaid assets (included in other assets) | $ | — | $ | — | $ | — | $ | 701 | ||||||||
| Unfunded liabilities (included in other noncurrent liabilities) | (145,603 | ) | (59,581 | ) | (4,896 | ) | (412 | ) | ||||||||
| Net amount recognized | $ | (145,603 | ) | $ | (59,581 | ) | $ | (4,896 | ) | $ | 289 | |||||
Amounts recorded in stockholder’s equity: | ||||||||||||||||
| Prior service cost | $ | 392 | $ | 321 | $ | 61 | $ | — | ||||||||
| Net actuarial loss (gain) | 134,878 | 66,645 | 93 | (142 | ) | |||||||||||
| Total | $ | 135,270 | $ | 66,966 | $ | 154 | $ | (142 | ) | |||||||
In Fiscal 2010, we estimate that we will amortize $5,900 of net actuarial losses and $40 of prior service cost from stockholder’s equity.
Actuarial assumptions are described below. The discount rates at September 30 are used to measure the year-end benefit obligations and the earnings effects for the subsequent year. The discount rate is based upon market-observed yields for high quality fixed income securities with maturities that correspond to the payment of benefits. 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.
| Pension Plans | Other Postretirement Benefits | |||||||||||||||||||||||||||||||
| Weighted-average assumptions: | 2009 | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||||||||||
| Discount rate | 5.5 | % | 6.8 | % | 6.4 | % | 6.0 | % | 5.5 | % | 6.8 | % | 6.4 | % | 6.0 | % | ||||||||||||||||
| Expected return on plan assets | 8.5 | % | 8.5 | % | 8.5 | % | 8.5 | % | 5.5 | % | 5.5 | % | 5.5 | % | 5.6 | % | ||||||||||||||||
| Rate of increase in salary levels | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | ||||||||||||||||
The ABO for the Pension Plans was $374,213 and $267,798 as of September 30, 2009 and 2008, respectively. Included in the end of year Pension Plans PBOs above are $37,023 at September 30, 2009 and $27,882 at September 30, 2008 relating to employees of UGI and certain of its other subsidiaries. Included in the end of year other postretirement plans ABOs above are $665 at September 30, 2009 and $562 at September 30, 2008 relating to employees of UGI and certain of its other subsidiaries.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Net periodic pension expense and other postretirement benefit costs relating to the Company’s employees include the following components:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
| Service cost | $ | 5,975 | $ | 5,053 | $ | 5,457 | $ | 131 | $ | 261 | $ | 273 | ||||||||||||
| Interest cost | 21,326 | 17,757 | 17,144 | 820 | 775 | 842 | ||||||||||||||||||
| Expected return on assets | (23,794 | ) | (22,702 | ) | (21,838 | ) | (523 | ) | (640 | ) | (596 | ) | ||||||||||||
| Curtailment gain | — | — | — | — | (2,202 | ) | — | |||||||||||||||||
| Amortization of: | ||||||||||||||||||||||||
| Prior service cost (benefit) | 29 | 26 | 242 | (410 | ) | (388 | ) | (350 | ) | |||||||||||||||
| Actuarial loss | 3,588 | — | 866 | 88 | — | 115 | ||||||||||||||||||
| Net benefit cost (income) | 7,124 | 134 | 1,871 | 106 | (2,194 | ) | 284 | |||||||||||||||||
| Change in associated regulatory liabilities | — | — | — | 3,271 | 3,435 | 3,123 | ||||||||||||||||||
| Benefit cost after change in regulatory liabilities | $ | 7,124 | $ | 134 | $ | 1,871 | $ | 3,377 | $ | 1,241 | $ | 3,407 | ||||||||||||
Pension Plans assets are held in trust. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. We did not make any contributions to the Pension Plans in Fiscal 2009, Fiscal 2008 or Fiscal 2007. We believe that we will be required to make contributions during Fiscal 2010 of approximately $3,400.
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 calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. The required contribution to the VEBA during Fiscal 2010 is not expected to be material.
Expected payments for pension benefits and other postretirement welfare benefits are as follows:
| Other | ||||||||
| Pension | Postretirement | |||||||
| Benefits | Benefits | |||||||
| Fiscal 2010 | $ | 18,551 | $ | 1,543 | ||||
| Fiscal 2011 | 19,388 | 1,563 | ||||||
| Fiscal 2012 | 20,425 | 1,525 | ||||||
| Fiscal 2013 | 21,566 | 1,469 | ||||||
| Fiscal 2014 | 22,783 | 1,472 | ||||||
| Fiscal 2015 – 2019 | 133,527 | 7,259 | ||||||
In accordance with our investment strategy to obtain long-term growth, our target asset allocations are to maintain a mix of 65% equities and the remainder in fixed income funds or cash equivalents in the Pension Plans. The targets and actual allocations for the Pension Plans’ and the VEBA trust assets at September 30 are as follows:
| Target | Pension Plan | VEBA | ||||||||||||||||||||||
| Pension Plan | VEBA | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
| Equities | 65 | % | 65 | % | 68 | % | 63 | % | 64 | % | 57 | % | ||||||||||||
| Fixed income funds | 35 | % | 35 | % | 32 | % | 37 | % | 30 | % | 34 | % | ||||||||||||
| Cash equivalents | N/A | 0 | % | N/A | N/A | 6 | % | 9 | % | |||||||||||||||
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
UGI Common Stock comprised approximately 8% and 9% of Pension Plans’ assets at September 30, 2009 and 2008, respectively.
The assumed health care cost trend rates are 8.0% for Fiscal 2010, decreasing to 5.0% in Fiscal 2016. A one percentage point change in the assumed health care cost trend rate would increase (decrease) the Fiscal 2009 postretirement benefit cost and obligation as follows:
| 1% Increase | 1% Decrease | |||||||
| Service and interest costs in Fiscal 2009 | $ | 13 | $ | (12 | ) | |||
| ABO at September 30, 2009 | $ | 219 | $ | (204 | ) | |||
We also sponsor an unfunded and non-qualified supplemental executive retirement income plan. At September 30, 2009 and 2008, the projected benefit obligations of this plan were $2,773 and $3,161, respectively. We recorded expense for this plan of $635 in Fiscal 2009, $362 in Fiscal 2008 and $355 in Fiscal 2007.
Defined Contribution Plan
We sponsor a 401(k) savings plan for eligible employees (“Utilities Savings Plan”). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. The Utilities Savings Plan provides for employer matching contributions. The cost of benefits under the Utilities Savings Plan totaled $1,758 in Fiscal 2009, $1,256 in Fiscal 2008 and $1,069 in Fiscal 2007.
11. SERIES PREFERRED STOCK
We have 2,000,000 shares of Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of Series Preferred Stock outstanding at September 30, 2009 or 2008.
12. EQUITY-BASED COMPENSATION
Under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “UGI OECP”), certain key employees of UGI Utilities may be granted stock options to acquire shares of UGI Common Stock, stock appreciation rights (“SARS”), UGI Units (comprising “Stock Units” or “Performance Units”) and other equity-based amounts. Under the UGI OECP, the exercise price for options may not be less than the fair market value on the grant date. Awards under the UGI OECP may vest immediately or ratably over a period of years (generally three-year periods), and stock options for UGI Common Stock can be exercised no later than ten years from the grant date. In addition, the UGI OECP provides that the awards of UGI Units may also provide for the crediting of UGI Common Stock 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.
UGI Stock 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 UGI market performance conditions. 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 and service conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of Performance Units ultimately paid at the end of the performance period (generally three years) may range from 0% to 200% of the target award based upon UGI’s Total Shareholder Return percentile rank relative to companies in the Standard & Poor’s Utilities Index.
We use a Black-Scholes option-pricing model to estimate the fair value of UGI stock options. We use a Monte Carlo valuation approach to estimate the fair value of UGI Performance Unit awards. We recorded total net pre-tax equity-based compensation expense associated with both UGI Units and UGI stock options of $1,142 ($668 after-tax) during Fiscal 2009; $842 ($492 after-tax) during Fiscal 2008; and $1,006 ($588 after-tax) during Fiscal 2007.
As of September 30, 2009, there was $387 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 1.9 years. As of September 30, 2009, there was a total of $638 of unrecognized compensation expense associated with 50,334 UGI Unit awards that is expected to be recognized over a weighted average period of 1.8 years. At September 30, 2009 and 2008, total liabilities of $560 and $357, respectively, associated with UGI Unit awards are reflected in “Other current liabilities” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
The following table summarizes UGI Unit award activity for Fiscal 2009:
| Total | Vested | Non-Vested | ||||||||||||||||||||||
| Weighted | Weighted | Weighted | ||||||||||||||||||||||
| Average | Average | Average | ||||||||||||||||||||||
| Number of | Grant Date | Number of | Grant Date | Number of | Grant Date | |||||||||||||||||||
| UGI | Fair Value | UGI | Fair Value | UGI | Fair Value | |||||||||||||||||||
| Units | (per Unit) | Units | (per Unit) | Units | (per Unit) | |||||||||||||||||||
| September 30, 2008 | 63,300 | $ | 26.68 | 18,333 | $ | 24.98 | 44,967 | $ | 27.37 | |||||||||||||||
| Granted | 31,700 | $ | 28.00 | — | $ | — | 31,700 | $ | 28.00 | |||||||||||||||
| Vested | — | $ | — | 19,901 | $ | 24.77 | (19,901 | ) | $ | 24.77 | ||||||||||||||
| Forfeited | (25,666 | ) | $ | 28.67 | — | $ | — | (25,666 | ) | $ | 28.67 | |||||||||||||
| Unit awards paid | (19,000 | ) | $ | 21.08 | (19,000 | ) | $ | 21.08 | — | $ | — | |||||||||||||
| September 30, 2009 | 50,334 | $ | 28.61 | 19,234 | $ | 28.62 | 31,100 | $ | 28.60 | |||||||||||||||
13. COMMITMENTS AND CONTINGENCIES
Commitments
We lease various buildings and transportation, computer and office equipment and other facilities under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $5,894 in Fiscal 2009, $4,858 in Fiscal 2008 and $4,519 in Fiscal 2007.
Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year for the fiscal years ending September 30 are as follows: 2010 — $5,047; 2011 — $4,183; 2012 — $3,496; 2013 — $2,966; 2014 — $2,074; after September 30, 2014 — $4,678.
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, natural gas storage and peaking service which Gas Utility may terminate at various dates through 2029. Gas Utility’s costs associated with transportation and storage service 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 electric energy needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2014.
Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2009 for fiscal years ending September 30 are as follows: 2010 — $240,831; 2011 — $125,169; 2012 — $108,188; 2013 — $66,905; 2014 — $54,531; after 2014 — $108,513.
Contingencies
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 $1,800 and $1,100, respectively, in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP Properties and at the end of 2013 for well plugging activities. 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, 2009, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $25,042. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets totaling $25,042.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share 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 UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. At September 30, 2009 and 2008, neither UGI Gas’ undiscounted nor its accrued liability for environmental investigation and cleanup costs was material.
UGI Utilities has been notified of several 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 are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating three claims against it relating to out-of-state sites.
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.
South Carolina Electric & Gas Company v. UGI Utilities, Inc.On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserts that it has spent approximately $22,000 in remediation costs and paid $26,000 in third-party claims relating to the site and estimates that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14,000. Trial took place in March 2009 and the court’s decision is pending.
Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens Communications Company, now known as Frontier Communications Company (“Frontier”), served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of any costs Frontier would be required to pay to the City for cleaning up tar deposits in the Penobscot River. Frontier alleged that through ownership and control of a subsidiary, Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Frontier made similar allegations of control against another third-party defendant, CenterPoint Energy Resources Corporation (“CenterPoint”), whose predecessor owned the Bangor subsidiary from 1928 to 1944. Frontier’s third-party claims were stayed pending a resolution of the City’s suit against Frontier, which was tried in September 2005. On June 27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup costs, which were estimated at $18,000. On February 14, 2007, Frontier and the City entered into a settlement agreement pursuant to which Frontier agreed to pay $7,600. Frontier subsequently filed the current action against the original third-party defendants, repeating its claims for contribution. On September 22, 2009, the court granted summary judgment in favor of co-defendant CenterPoint. UGI Utilities believes that it also has good defenses and has filed a motion for summary judgment with respect to Frontier’s claims.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Sag Harbor, New York Matter.By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2,300 and expects to spend another $11,000 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10,000. KeySpan believes that the cost could be as high as $20,000. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites could total approximately $215,000 and asserted that UGI Utilities is responsible for approximately $103,000 of this amount. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites, Waterbury North, pursuant to a lease. In April 2009, the court conducted a trial to determine whether UGI Utilities operated any of the nine remaining sites that were owned and operated by former subsidiaries. On May 22, 2009, the court granted judgment in favor of UGI Utilities with respect to all nine sites. In a second phase of the trial scheduled for early 2010, the court will determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies estimate that remediation costs at Waterbury North could total $25,000.
We cannot predict with certainty the final results of any of the environmental 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, 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 pending claims and legal actions arising in the normal course of our businesses. While the results of these other pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, the final outcome of such other matters will not have a significant effect on our consolidated financial position, results of operations or cash flows.
14. FAIR VALUE MEASUREMENTS
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, 2009:
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| Derivative financial instruments: | ||||||||||||||||
| Assets | $ | 102 | $ | 765 | $ | — | $ | 867 | ||||||||
| Liabilities | $ | — | $ | — | $ | — | $ | — | ||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
15. DISCLOSURES ABOUT DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND OTHER FINANCIAL INSTRUMENTS
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 and (2) interest 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. Because our derivative instruments, other than FTRs and gasoline futures and swap contracts (as further described below), generally qualify as hedges under GAAP or are recoverable or refundable pursuant to current regulatory practice, we expect that changes in the fair value of derivative instruments used to manage commodity or interest rate risk would be substantially offset by gains or losses on the associated anticipated transactions.
Commodity Price Risk
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. 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 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, 2009, there were no unsettled NYMEX natural gas futures contracts outstanding.
In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. 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. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states.
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. The volumes of gasoline under these contracts and the effect on net income from changes in fair value were not material for all periods presented.
Although we did not have any unsettled natural gas futures contracts outstanding at September 30, 2009, we typically hedge anticipated purchases of natural gas over periods of approximately 12 to 18 months. The volume of electricity congestion that is subject to FTRs at September 30, 2009 totaled 1.0 million kilowatt-hours and the maximum period over which we are currently hedging electricity congestion with FTRs is 20 months. At September 30, 2009, the maximum period over which we are hedging gasoline is 12 months.
With respect to natural gas futures contracts associated with our Gas Utility, gains and losses on unsettled natural gas futures contracts are recorded in deferred fuel costs on the Consolidated Balance Sheet in accordance with the FASB guidance related to rate-regulated entities and reflected in cost of sales through the PGC mechanism. At September 30, 2008, Gas Utility had recorded current liabilities of $23,321 representing the fair values of unsettled natural gas futures contracts as of that date and associated regulatory assets of equal amount. There were no such amounts at September 30, 2009. Because Electric Utility is entitled to fully recover its default service costs commencing January 1, 2010 pursuant to the January 22, 2009 settlement of its default service rate filing with the PUC (see Note 5), changes in the fair value of Electric Utility FTRs associated with periods beginning January 1, 2010 will not affect net income. Electric Utility FTRs associated with periods prior to January 2010 are recorded at fair value with changes in fair value reflected in cost of sales.
Interest Rate Risk
Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in AOCI, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At September 30, 2009 there were no unsettled IRPA contracts outstanding.
We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in AOCI 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, 2009, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $1,164.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Derivative Financial Instrument Credit Risk
Our natural gas exchange-traded futures contracts are guaranteed by the NYMEX and have limited credit risk. These contracts generally require cash deposits in margin accounts. At September 30, 2008, Gas Utility’s restricted cash in brokerage accounts totaled $34,037. There was no such restricted cash at September 30, 2009. We generally do not have credit-risk-related contingent features in our derivative contracts.
The following table provides information regarding the balance sheet location and fair values of derivative assets and liabilities existing as of September 30, 2009:
| As of September 30, 2009 | Derivative Assets | Derivative (Liabilities) | ||||||||||||||
| Balance Sheet | Fair | Balance Sheet | Fair | |||||||||||||
| Location | Value | Location | Value | |||||||||||||
Derivatives Not Designated as Hedging Instruments: | ||||||||||||||||
| FTRs | Derivative financial instruments | $ | 765 | $ | — | |||||||||||
| Gasoline futures contracts | Derivative financial instruments | 102 | — | |||||||||||||
Total Derivatives Not Designated as Hedging Instruments | $ | 867 | $ | — | ||||||||||||
During the year ended September 30, 2009, the amount of IRPA net losses included in AOCI that were reclassified into net income totaled $1,164. During the year ended September 30, 2009, the impact of changes in the fair value of FTRs and gasoline futures and swap contracts on our net income was not material.
We are also a party to a number of contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas 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 purchase and normal sale 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 based on the contract underlying is directly associated with the price or value of a service.
Financial Instruments
The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amounts and estimated fair values of our remaining financial instruments assets and (liabilities) at September 30 (including unsettled derivative instruments) are as follows:
| Asset (Liability) | ||||||||
| Carrying | Estimated | |||||||
| Amount | Fair Value | |||||||
| 2009: | ||||||||
| Derivative financial instruments | $ | 867 | $ | 867 | ||||
| Long-term debt | (640,000 | ) | (705,710 | ) | ||||
| 2008: | ||||||||
| Derivative financial instruments | $ | (22,982 | ) | $ | (22,982 | ) | ||
| Long-term debt | (532,000 | ) | (484,000 | ) | ||||
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. Fair values of derivative financial instruments are determined in accordance with the FASB’s guidance regarding fair value measurements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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 and securities guaranteed by the U.S. Government or its agencies. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different markets.
16. SEGMENT INFORMATION
We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The HVAC Business does not meet the quantitative thresholds for separate segment reporting under GAAP relating to business segment reporting and has been included in “Other” for periods commencing January 1, 2007, the date UGI Utilities contributed its heating, ventilation and air-conditioning services business to UGI HVAC. Periods prior to January 1, 2007 have not been restated.
The accounting policies of our reportable segments are the same as those described in Note 2. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.
No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States, and all of our reportable segments’ long-lived assets are located in the United States.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Financial information by business segment follows:
| Gas | Electric | |||||||||||||||
| Total | Utility | Utility | Other | |||||||||||||
2009 | ||||||||||||||||
| Revenues | $ | 1,381,260 | $ | 1,240,981 | $ | 138,495 | $ | 1,784 | ||||||||
| Cost of sales | 944,793 | 853,163 | 91,630 | — | ||||||||||||
| Depreciation and amortization | 51,112 | 47,228 | 3,884 | — | ||||||||||||
| Operating income | 169,472 | 153,457 | 15,376 | 639 | ||||||||||||
| Interest expense | 43,918 | 42,192 | 1,726 | — | ||||||||||||
| Income before income taxes | 125,554 | 111,265 | 13,650 | 639 | ||||||||||||
| Total assets | 2,030,237 | 1,915,901 | 113,201 | 1,135 | ||||||||||||
| Goodwill | 180,145 | 180,145 | — | — | ||||||||||||
| Capital expenditures | 79,084 | 73,825 | 5,259 | — | ||||||||||||
2008 | ||||||||||||||||
| Revenues | $ | 1,289,053 | $ | 1,138,346 | $ | 139,232 | $ | 11,475 | ||||||||
| Cost of sales | 920,413 | 831,066 | 84,312 | 5,035 | ||||||||||||
| Depreciation and amortization | 41,325 | 37,679 | 3,638 | 8 | ||||||||||||
| Operating income | 163,042 | 137,556 | 24,449 | 1,037 | ||||||||||||
| Interest expense | 39,065 | 37,068 | 1,997 | — | ||||||||||||
| Income before income taxes | 123,977 | 100,489 | 22,451 | 1,037 | ||||||||||||
| Total assets | 1,694,466 | 1,582,371 | 112,095 | — | ||||||||||||
| Goodwill | 161,726 | 161,726 | — | — | ||||||||||||
| Capital expenditures | 64,351 | 58,243 | 6,048 | 60 | ||||||||||||
2007 | ||||||||||||||||
| Revenues | $ | 1,183,247 | $ | 1,044,946 | $ | 121,935 | $ | 16,366 | ||||||||
| Cost of sales | 816,451 | 741,468 | 67,770 | 7,213 | ||||||||||||
| Depreciation and amortization | 40,934 | 37,396 | 3,532 | 6 | ||||||||||||
| Operating income | 165,093 | 136,586 | 25,995 | 2,512 | ||||||||||||
| Interest expense | 42,327 | 39,891 | 2,436 | — | ||||||||||||
| Income before income taxes | 122,766 | 96,695 | 23,559 | 2,512 | ||||||||||||
| Total assets | 1,649,038 | 1,530,399 | 110,076 | 8,563 | ||||||||||||
| Goodwill | 162,309 | 162,309 | — | — | ||||||||||||
| Capital expenditures | 73,411 | 66,164 | 7,212 | 35 | ||||||||||||
17. OTHER INCOME, NET
Other income, net, comprises the following:
| 2009 | 2008 | 2007 | ||||||||||
| Non-tariff service income | $ | 3,221 | $ | 6,191 | $ | 5,068 | ||||||
| Interest income | 288 | 1,444 | 2,480 | |||||||||
| Curtailment gain | — | 2,202 | — | |||||||||
| Other | 3,752 | 3,087 | 1,016 | |||||||||
| Total other income, net | $ | 7,261 | $ | 12,924 | $ | 8,564 | ||||||
18. RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula based upon the relative percentage of UGI Utilities’ revenues, operating expenses and net assets employed to the total of such item’s for UGI’s other operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as operating and administrative expenses — related parties in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries, principally payroll-related services. Amounts billed to these entities by UGI Utilities for all periods presented were not material.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
At September 30, 2009, UGI Utilities was a party to a one-year storage contract administrative agreement (“SCAA”) with Energy Services expiring on October 31, 2009. At September 30, 2008, UGI Utilities was a party to a one-year SCAA with Energy Services expiring on October 31, 2008. Pursuant to the 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 term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with the SCAAs totaling $55,760 in Fiscal 2009, $111,764 in Fiscal 2008 and $92,683 in Fiscal 2007. In conjunction with the SCAA expiring on October 31, 2009, UGI Utilities received $15,000 in security deposits from Energy Services which amount is included in other current liabilities on the September 30, 2009 Consolidated Balance Sheet.
UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at September 30, 2009, comprising approximately 7.7 bcf of natural gas, was $67,436. The carrying value of these gas storage inventories at September 30, 2008, comprising approximately 8.3 bcf feet of natural gas, was $70,833. Effective November 1, 2009, UGI Utilities entered into a new SCAA with Energy Services expiring on October 31, 2012.
UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to UGI Utilities during the peak heating-season months of November to March. In addition, from time to time, UGI Utilities purchases natural gas or pipeline capacity from Energy Services. The aggregate amount of these transactions (exclusive of SCAA transactions) during Fiscal 2009, Fiscal 2008 and Fiscal 2007 totaled $24,444, $52,603 and $36,286, respectively.
From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2009, Fiscal 2008 and Fiscal 2007, revenues associated with sales to Energy Services totaled $30,911, $66,126 and $39,564, respectively. Also from time to time, the Company purchases natural gas or pipeline capacity from Energy Services (in addition to those transactions already described above). During Fiscal 2009, Fiscal 2008 and Fiscal 2007, such purchases totaled $17,268, $29,454 and $2,008, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.
On October 1, 2008, in conjunction with the CPG Acquisition, CPG’s wholly owned subsidiary CPP sold its assets to AmeriGas OLP, an affiliate of UGI. See Note 4 for additional information regarding this transaction.
19. QUARTERLY DATA (unaudited)
The following quarterly information includes all adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of the Company’s businesses.
| December 31, | March 31, | June 30, | September 30, | |||||||||||||||||||||||||||||
| 2008 | 2007 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||
| Revenues | $ | 446,692 | $ | 364,388 | $ | 581,260 | $ | 519,998 | $ | 208,300 | $ | 235,544 | $ | 145,008 | $ | 169,123 | ||||||||||||||||
| Operating income | $ | 62,012 | $ | 58,609 | $ | 85,673 | $ | 81,669 | $ | 16,443 | $ | 20,058 | $ | 5,344 | $ | 2,706 | ||||||||||||||||
| Net income (loss) | $ | 31,134 | $ | 28,633 | $ | 44,746 | $ | 43,086 | $ | 3,113 | $ | 6,248 | $ | (271 | ) | $ | (3,940 | ) | ||||||||||||||
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Thousands of dollars)
(Thousands of dollars)
| Balance at | Charged to | Balance at | ||||||||||||||
| beginning | costs and | end of | ||||||||||||||
| of year | �� | expenses | Other | year | ||||||||||||
Year Ended September 30, 2009 | ||||||||||||||||
| Reserves deducted from assets in the consolidated balance sheet: | ||||||||||||||||
| Allowance for doubtful accounts | $ | 10,369 | $ | 19,193 | $ | (22,735 | )(1) | $ | 11,384 | |||||||
| $ | 4,557 | (2) | ||||||||||||||
| Other reserves: | ||||||||||||||||
| Other, principally environmental | $ | 16,011 | $ | 2,335 | $ | 18,495 | (2) | $ | 38,707 | |||||||
| $ | (3,678 | )(3) | ||||||||||||||
| $ | 5,544 | (5) | ||||||||||||||
Year Ended September 30, 2008 | ||||||||||||||||
| Reserves deducted from assets in the consolidated balance sheet: | ||||||||||||||||
| Allowance for doubtful accounts | $ | 10,824 | $ | 18,210 | $ | (18,533 | )(1) | $ | 10,369 | |||||||
| $ | (132 | )(4) | ||||||||||||||
| Other reserves: | ||||||||||||||||
| Other, principally environmental | $ | 18,562 | $ | 795 | $ | (4,101 | )(3) | $ | 16,011 | |||||||
| $ | 755 | (5) | ||||||||||||||
Year Ended September 30, 2007 | ||||||||||||||||
| Reserves deducted from assets in the consolidated balance sheet: | ||||||||||||||||
| Allowance for doubtful accounts | $ | 12,389 | $ | 14,353 | $ | (16,341 | )(1) | $ | 10,824 | |||||||
| $ | 423 | (2) | ||||||||||||||
| Other reserves: | ||||||||||||||||
| Other, principally environmental | $ | 8,868 | $ | 2,363 | $ | (923 | )(3) | $ | 18,562 | |||||||
| $ | 8,254 | (2) | ||||||||||||||
| (1) | Uncollectible accounts written off, net of recoveries | |
| (2) | Acquisition adjustments | |
| (3) | Payments, net | |
| (4) | Dividend of UGI HVAC | |
| (5) | Other adjustments |
S - 1
Table of Contents
EXHIBIT INDEX
| Exhibit No. | Description | |||
| 10.10 | UGI Utilities, Inc. Senior Executive Employee Severance Plan as in effect as of November 1, 2008 | |||
| 10.18 | Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Messrs. Barney and Terranova and Ms. Ebner | |||
| 12.1 | Computation of Ratio of Earnings to Fixed Charges | |||
| 23 | Consent of PricewaterhouseCoopers LLP | |||
| 31.1 | Certification by the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act | |||
| 31.2 | Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act | |||
| 32 | Certification by the Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act | |||