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EX-32 - EXHIBIT 32 - UGI UTILITIES INCc06627exv32.htm
EX-23 - EXHIBIT 23 - UGI UTILITIES INCc06627exv23.htm
EX-21 - EXHIBIT 21 - UGI UTILITIES INCc06627exv21.htm
EX-12.1 - EXHIBIT 12.1 - UGI UTILITIES INCc06627exv12w1.htm
EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INCc06627exv31w1.htm
EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INCc06627exv31w2.htm
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2010
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)
(610) 796-3400
(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. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer þ   Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
At September 30, 2010, 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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Index to Financial Statements and Financial Statement Schedules
    F-2  
 
       
 Exhibit 12.1
 Exhibit 21
 Exhibit 23
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32

 

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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. The acquisition of PPL Gas, now known as UGI Central Penn Gas, Inc. (“CPG”), significantly increased our natural gas distribution business in eastern and central Pennsylvania. 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.
The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of UGI Utilities, PNG, and CPG. Gas Utility serves approximately 568,000 customers in eastern 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 with Fiscal 2009, CPG was included in the Company’s Gas Utility segment. 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, with respect to a small service territory, the Maryland Public Service Commission. Electric Utility is regulated by the PUC.

 

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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 2010” and “Fiscal 2009” refer to the fiscal years ended September 30, 2010 and September 30, 2009, respectively.
GAS UTILITY
Gas Utility is authorized to distribute natural gas to approximately 568,000 customers in portions of 45 eastern 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. Gas Utility also distributes natural gas to several hundred customers in portions of one Maryland county.
System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2010 was approximately 153.9 billion cubic feet (“bcf”). System sales of gas accounted for approximately 37% of system throughput, while gas transported for residential, commercial and industrial customers (who bought their gas from others) accounted for approximately 63% of system throughput.
Sources of Supply and Pipeline Capacity
Gas Utility is permitted to recover prudently incurred costs of natural gas it sells to its customers. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures.” 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 2010, Gas Utility purchased approximately 91 bcf of natural gas for sale to core-market customers (principally comprised of firm-residential, commercial and industrial customers who purchase their gas from Gas Utility (“retail core-market”) and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers) and off-system sales customers. Approximately 75% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 25% of gas purchased by Gas Utility was supplied by approximately 21 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 a typical 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 expired at the end of 2009 or are scheduled to expire at the end of 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 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 31% 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 28 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, 22 of which extend beyond the 2011 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 2011. 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 2010, Gas Utility supplied transportation service to 2 major co-generation installations and 5 electric generation facilities. Gas Utility continues to seek new residential, commercial and industrial customers for both firm and interruptible service. In the residential market sector, Gas Utility connected approximately 7,700 residential heating customers during Fiscal 2010. These customers consisted primarily of (i) customers converting from other energy sources, mainly oil and electricity, (ii) existing non-heating gas customers who added gas heating systems to replace other energy sources and (iii) new home construction customers.
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 (i) the pricing of pipeline services in a competitive energy marketplace; (ii) the flexibility of the terms and conditions of pipeline service tariffs and contracts; and (iii) pipelines’ requests to increase their base rates, or change the terms and conditions of their storage and transportation services.
UGI Utilities’ objective in negotiations with interstate pipeline and natural gas suppliers, and in proceedings before regulatory agencies, is to assure availability of supply, transportation and storage alternatives to serve market requirements at the lowest cost possible, taking into account the need for security of supply. Consistent with that objective, UGI Utilities negotiates the terms of firm transportation capacity on all pipelines serving it, arranges for appropriate storage and peak-shaving resources, negotiates with producers for competitively priced gas purchases and aggressively participates in regulatory proceedings related to transportation rights and costs of service.

 

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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 2,120 miles of transmission and distribution lines and 13 transmission substations. For Fiscal 2010, 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 18% of total sales of electricity during Fiscal 2010.
Sources of Supply
In accordance with Electric Utility’s default service settlement with the PUC effective January 1, 2010, Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with the PUC. 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. As of September 30, 2010, 4 electric generation suppliers provided energy for customers representing 13% of Electric Utility’s sales volume. See “Gas Utility and Electric Utility Regulation and Rates — Electric Utility Rates.”
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 “default service” provider for its customers who do not choose an alternate electric generation supplier. In Fiscal 2010, 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. As an energy source, electricity competes with natural gas, oil, propane and other heating fuels for residential heating purposes.
The terms and conditions under which Electric Utility provides default service, and rules governing the rates that may be charged for such service, have been established in a Default Service Rate Plan (“DSR Plan”) approved by the PUC. Consistent with the terms of the DSR Plan, effective January 1, 2010, default service rates are designed to recover all reasonable and prudent costs incurred in providing electricity to default service customers. This recovery, through default service rates, no longer subjects Electric Utility to the risk that actual costs for purchased power will exceed default service revenues. Conversely, effective January 1, 2010, Electric Utility does not have the opportunity to recover revenues in excess of actual power costs. See “Gas Utility and Electric Utility Regulation and Rates — Electric Utility Rates.”
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. There are primarily two types of rates that UGI Utilities may charge customers for gas and electric service: (1) rates designed to recover costs other than purchased gas costs (“PGCs”) and electric default service costs; and (2) rates designed to recover PGCs and electric default service costs. Rates designed to recover costs other than PGCs and electric default service costs are primarily established in general base rate proceedings. Rates designed to recover PGCs and electric default service costs are established in PGC and electric default service rate proceedings.

 

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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
Rates that UGI Utilities’ utility operations may charge for gas service come in two forms: 1) rates designed to recover costs other than purchased gas costs; and 2) rates designed to recover purchase gas costs. Rates designed to recover costs other than purchased gas costs are primarily established in general base rate proceedings. Rates designed to recover purchased gas costs are reviewed in a purchased gas costs (“PGC”) rate proceeding. 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 PGC variable credit equal to a portion of the margin received from customers served under interruptible rates to the extent such interruptible customers use third-party pipeline capacity contracted for by UGI Gas for retail core-market customers.
On August 27, 2009, the PUC approved PNG’s and CPG’s base 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: (1) PGC is applicable to small, firm, retail core-market customers consisting of the residential and small commercial and industrial classes; and (2) PGC 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.
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.

 

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PUC default service regulations became applicable to Electric Utility’s provision of default service effective January 1, 2010 and Electric Utility, consistent with these regulations, has received 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 recover the cost of acquiring default service supplies for service rendered on or after 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 recover the costs of complying with AEPS Act requirements applicable to default service supplies for service rendered on or after 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, and our subsidiaries UGI Energy Services, Inc. and UGI Development Company, 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, CERCLA 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.
Employees
At September 30, 2010, UGI Utilities had approximately 1,400 employees.

 

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GLOBAL CLIMATE CHANGE
There continues to be concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global warming. In addition to carbon dioxide, greenhouse gases include, among others, methane, a component of natural gas. 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 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. The United States Senate has been considering a number of related proposals, ranging from “energy only” bills to proposals that place an economy-wide cap on greenhouse gas emissions. No legislation can be enacted until a final reconciled bill is approved by both the House of Representatives and the Senate and signed by the President.
Even if Congress does not pass legislation mandating GHG emissions reductions, there continue to be regulatory developments under the Clean Air Act applicable to GHGs. In September 2009, the Environmental Protection Agency (“EPA”) issued a final rule establishing a system for mandatory reporting of GHG emissions. In November 2010, the EPA expanded the reach of its GHG reporting requirements to include the petroleum and natural gas industries. Petroleum and natural gas facilities subject to the rule, which include facilities of our natural gas distribution business, are required to begin emissions monitoring in January 2011 and to submit detailed annual reports beginning in March 2012. The rule does not require affected facilities to implement GHG emission controls or reductions. In December 2009, the EPA published its findings that emissions of GHGs constitute an endangerment to public health and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would limit GHG emissions from new motor vehicles and that would impose permit requirements for GHG emissions from certain stationary sources. Legal challenges have been filed against many of EPA’s rulemakings, and we are unable to predict the results of those challenges.
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 2010, 2009 and 2008 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 structures do 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 recent 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.

 

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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.
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 continues to be concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global warming. In addition to carbon dioxide, greenhouse gases include, among others, methane, a component of natural gas. 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. The United States Senate has been considering a number of related proposals, ranging from “energy only” bills to proposals that place an economy-wide cap on greenhouse gas emissions. No legislation can be enacted until a final reconciled bill is approved by both the House of Representatives and the Senate and signed by the President.
Even if Congress does not pass legislation mandating GHG emissions reductions, there continue to be regulatory developments under the Clean Air Act applicable to GHGs. In September 2009, the Environmental Protection Agency (“EPA”) issued a final rule establishing a system for mandatory reporting of GHG emissions. In November 2010, the EPA expanded the reach of its GHG reporting requirements to include the petroleum and natural gas industries. Petroleum and natural gas facilities subject to the rule, which include facilities of our natural gas distribution business, are required to begin emissions monitoring in January 2011 and to submit detailed annual reports beginning in March 2012. The rule does not require affected facilities to implement GHG emission controls or reductions. In December 2009, the EPA published its findings that emissions of GHGs constitute an endangerment to public health and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would limit GHG emissions from new motor vehicles and that would impose permit requirements for GHG emissions from certain stationary sources. Legal challenges have been filed against many of EPA’s rulemakings, and we are unable to predict the results of those challenges.
It is expected that climate change legislation will continue to be part of the legislative and regulatory discussion for the foreseeable future. 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.

 

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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.
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 $74.0 million in Fiscal 2010, $61.2 million in Fiscal 2009, and $68.8 million in Fiscal 2008.

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) discusses our results of operations and our financial condition. MD&A should be read in conjunction with our Items 1 & 2, “Business and Properties,” 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 2010 was $90.3 million, an increase of 14.7% from Fiscal 2009 net income of $78.7 million. The increase in net income reflects the full-year effects of the August 28, 2009 CPG Gas and PNG Gas base rate revenue settlements and lower Fiscal 2010 Gas Utility operating and administrative expenses. In August 2009, CPG Gas and PNG Gas received PUC approval of base rate revenue increases that went into effect on August 28, 2009. The combined increases in annual base rate revenues approved totaled $29.8 million and are included in the Fiscal 2010 results. Electric Utility sales benefited from Fiscal 2010 late spring and summer temperatures that were much warmer than the prior year, increasing electricity demand for air conditioning. These benefits were partially offset by the negative effects on Gas Utility’s and Electric Utility’s results from warmer heating-season weather and the lingering effects of the recession. In addition, Electric Utility’s Fiscal 2010 results were negatively impacted by lower total margin under Default Service (“DS”) rates that became effective on January 1, 2010 compared to the margins recorded under the Provider of Last Resort (“POLR”) rates in effect prior to January 1, 2010. Notwithstanding the recent economic recession’s impact on new construction in our franchise territories, we continued to experience customer growth at our Gas Utility in Fiscal 2010.
Looking ahead, our results in Fiscal 2011 will be influenced by a number of factors including temperatures during the peak heating-season months, the strength of the economic recovery, the lingering effects of the weak economy on customer growth from new construction and conversion activity and ongoing customer conservation.
We believe that we have sufficient liquidity in the form of cash generated from operations and our revolving credit facility to fund business operations for the foreseeable future. We expect to renew our revolving credit agreement prior to its expiration in August 2011.
ANALYSIS OF RESULTS OF OPERATIONS
The following results of operations covers Fiscal 2010, Fiscal 2009 and the year ended September 30, 2008 (“Fiscal 2008”). Fiscal 2010 and Fiscal 2009 results reflect the full-year impact from the October 1, 2008 acquisition of CPG (see “Acquisition of PPL Gas Utilities Corporation” below).

 

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Fiscal 2010 Compared with Fiscal 2009
                                 
                    Increase  
(Millions of dollars)   2010     2009     (Decrease)  
 
                               
Gas Utility:
                               
Revenues
  $ 1,047.5     $ 1,241.0     $ (193.5 )     (15.6 )%
Total margin (a)
  $ 394.1     $ 387.8     $ 6.3       1.6 %
Operating income
  $ 175.3     $ 153.5     $ 21.8       14.2 %
Income before income taxes
  $ 134.8     $ 111.3     $ 23.5       21.1 %
System throughput — bcf
    153.9       149.7       4.2       2.8 %
Heating degree days — % (warmer) colder than normal (b)
    (5.3 )%     4.1 %            
 
                               
Electric Utility:
                               
Revenues
  $ 120.2     $ 138.5     $ (18.3 )     (13.2 )%
Total margin (a)
  $ 36.5     $ 39.3     $ (2.8 )     (7.1 )%
Operating income
  $ 13.7     $ 15.4     $ (1.7 )     (11.0 )%
Income before income taxes
  $ 11.9     $ 13.7     $ (1.8 )     (13.1 )%
Distribution sales — gwh
    972.6       965.7       6.9       0.7 %
bcf — billions of cubic feet.
gwh — millions of kilowatt-hours.
     
(a)  
Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $6.6 million and $7.6 million during Fiscal 2010 and Fiscal 2009, respectively. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” in 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 5.3% warmer than normal in Fiscal 2010 compared with temperatures that were 4.1% colder than normal in Fiscal 2009. Total distribution system throughput increased 4.2 bcf in Fiscal 2010, despite the warmer weather, principally reflecting an 8.5 bcf increase in low margin interruptible delivery service volumes. Gas Utility’s core market volumes decreased 6.2 bcf (9.0%) due to the previously mentioned warmer weather and to a lesser extent the sluggish economy and customer conservation. Gas Utility’s core-market customers are comprised of firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.
Gas Utility revenues decreased $193.5 million during Fiscal 2010 principally reflecting a decline in revenues from retail core-market customers ($232.3 million) partially offset by a $29.4 million increase in revenues from low-margin off-system sales. The decrease in retail core-market revenues principally resulted from the effects of lower average PGC rates ($135.0 million) and the lower retail core-market volumes ($125.5 million). These decreases in revenues were partially offset by the effects of the PNG Gas and CPG Gas base operating revenue increases that became effective August 28, 2009. 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 $653.4 million in Fiscal 2010 compared with $853.2 million in Fiscal 2009 principally reflecting the previously mentioned lower retail core-market sales and average PGC rates ($227.8 million) due to lower natural gas commodity prices.

 

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Notwithstanding the decrease in distribution system volumes, Gas Utility total margin increased $6.3 million in Fiscal 2010. The increase is principally the result of the PNG Gas and CPG Gas base operating revenue increases ($28.2 million) substantially offset by the effect on total margin from the lower core-market volumes.
Gas Utility operating income in Fiscal 2010 increased $21.8 million principally reflecting lower operating and administrative costs ($15.6 million) and the previously mentioned increase in total margin ($6.3 million). Fiscal 2010 operating and administrative costs include, among other things, lower uncollectible accounts and customer assistance expenses ($11.5 million), and lower costs associated with environmental matters ($6.6 million). These decreases were partially offset by higher depreciation expense ($2.2 million) and higher pension expense ($2.1 million). The increase in income before income taxes reflects the previously mentioned higher operating income ($21.8 million) and lower interest expense ($1.6 million) due to lower average bank loan borrowings.
Electric Utility. Temperatures based upon heating degree days in Fiscal 2010 were approximately 6.8% warmer than in Fiscal 2009. The impact on kilowatt-hour sales from the warmer heating-season weather was more than offset by higher air-conditioning related sales from significantly warmer 2010 late spring and summer weather.
Electric Utility revenues decreased $18.3 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the generation portion of their service and, to a lesser extent, lower DS rates effective January 1, 2010. Electric Utility decreased its DS rates effective January 1, 2010 pursuant to a January 22, 2009 settlement of its DS rate filing with the PUC. This reduced average costs to a residential general and residential heating customer by nearly 10% and 4%, respectively, over such costs in Fiscal 2009 and also reduced rates to commercial and industrial customers. Under DS rates, Electric Utility is no longer subject to electric generation price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under previous POLR rates in effect prior to January 1, 2010. Electric Utility cost of sales declined to $77.1 million in Fiscal 2010 compared to $91.6 million in Fiscal 2009 principally reflecting the effects of the previously mentioned generation supplier customer switching and lower purchased power costs. For additional information on Electric Utility DS and POLR service, see Note 5 to Consolidated Financial Statements.
Electric Utility total margin declined $2.8 million in Fiscal 2010 principally reflecting the reduction in margin resulting from the implementation of lower DS rates effective January 1, 2010.
Electric Utility operating income and income before income taxes in Fiscal 2010 were $1.7 million and $1.8 million lower, respectively, than in Fiscal 2009 reflecting the lower total margin ($2.8 million) partially offset by lower operating and administrative expenses ($1.1 million).

 

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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 — 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 — 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. Total distribution system throughput increased 16.0 bcf in Fiscal 2009 principally reflecting the effects of the October 1, 2008 CPG Acquisition (22.2 bcf) and increases in core-market volumes resulting from the colder Fiscal 2009 weather and year-over-year customer growth. 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.
Gas Utility revenues increased $102.7 million in Fiscal 2009 principally reflecting incremental revenues from CPG Gas ($187.4 million) somewhat offset by lower revenues from low-margin off-system sales ($90.3 million). 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 associated with CPG Gas ($117.0 million) partially offset principally by the cost of sales effect of the lower off-system revenues ($89.1 million).
Gas Utility total margin increased $80.6 million in Fiscal 2009 principally reflecting incremental margin from CPG Gas ($70.4 million) and higher total core-market margin from UGI Gas and PNG Gas ($11.3 million) resulting principally 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 ($80.6 million) partially offset by higher operating and administrative and depreciation expenses ($59.3 million), principally incremental expenses associated with CPG Gas ($47.2 million), higher costs associated with environmental matters ($4.1 million) and, to a lesser extent, higher pension and 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 ($7.2 million).

 

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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, to a much lesser extent, the effects of the lower sales volumes.
Electric Utility operating income and income before income taxes in Fiscal 2009 were $9.0 million and $8.7 million lower than in Fiscal 2008, respectively, reflecting the previously mentioned lower total margin ($7.7 million) and higher operating and administrative costs ($0.9 million).
FINANCIAL CONDITION AND LIQUIDITY
Capitalization and Liquidity
UGI Utilities’ total debt outstanding was $657 million at September 30, 2010 compared with total debt outstanding of $794 million at September 30, 2009. Included in these amounts are $17 million and $154 million, respectively, of bank loans outstanding under UGI Utilities’ Revolving Credit Agreement (as further described below). The weighted average interest rate on bank loan borrowings at September 30, 2010 was 3.25%. UGI Utilities’ total debt outstanding at September 30, 2010, other than bank loans, comprises $383 million of Senior Notes and $257 million of Medium-Term Notes.
UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement which expires in August 2011. UGI Utilities expects to renew this facility before its expiration. At September 30, 2010 and 2009, there were $17 million and $154 million of borrowings outstanding under the Revolving Credit Agreement having average interest rates of 3.25% and 0.59%, respectively. The higher average interest rate at September 30, 2010 is the result of a prime rate borrowing compared to LIBOR borrowings at September 30, 2009. Borrowings under the Revolving Credit Agreement are classified as bank loans on the Consolidated Balance Sheets. During Fiscal 2010 and Fiscal 2009, average daily bank loan borrowings were $69.9 million and $180.0 million, respectively, and peak bank loan borrowings totaled $203 million and $312 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January. During Fiscal 2009, average daily and peak bank loan borrowings were higher than during Fiscal 2010 due in large part to higher margin deposits associated with natural gas futures accounts as a result of declines in wholesale natural gas prices and higher Fiscal 2009 borrowings needed to fund working capital. UGI Utilities Revolving Credit Agreement requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. UGI Utilities was in compliance with this covenant at September 30, 2010.
Based upon cash expected to be generated from operations and borrowings under Revolving Credit Agreement, management believes the Company will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2011. 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.

 

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Cash provided by operating activities was $291.6 million in Fiscal 2010, $176.4 million in Fiscal 2009 and $142.6 million in Fiscal 2008. Cash provided by operating activities before changes in operating working capital was $235.0 million in Fiscal 2010, $187.1 million in Fiscal 2009 and $143.3 million in Fiscal 2008. Fiscal 2010 cash provided by operating activities before changes in operating working capital reflects the improved Fiscal 2010 results greater noncash charges for deferred taxes due in large part to a change in the tax method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009 (see “Change in Tax Method of Accounting” below and Note 9 to Consolidated Financial statements). This change in tax method resulted in significantly lower required federal and state tax payments during Fiscal 2010. Changes in operating working capital provided $56.6 million of cash in Fiscal 2010, used $10.7 million of cash in Fiscal 2009 and used $0.8 million of cash in Fiscal 2008. The significantly higher cash flow provided by changes in operating working capital in Fiscal 2010 as compared with Fiscal 2009 principally reflects significantly less cash needed to fund purchases of natural gas inventories due to lower natural gas commodity prices. 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.
Investing activities. Cash used by investing activities was $90.3 million in Fiscal 2010, $310.4 million in Fiscal 2009, and $92.3 million in Fiscal 2008. Expenditures for property, plant and equipment increased slightly to $81.6 million in Fiscal 2010 compared with $79.1 million in Fiscal 2009 principally reflecting higher Electric Utility capital expenditures for transmission projects. 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. Fiscal 2010 investing activities cash flow includes a $4.7 million increase in restricted cash in futures and options accounts compared to a $34.0 million decrease in Fiscal 2009 and a $27.4 million increase of 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.
Financing activities. Cash provided (used) by financing activities was $210.5 million in Fiscal 2010, $144.1 million in Fiscal 2009 and ($63.0) million in Fiscal 2008. 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 2010 net bank loan repayments totaled $137 million compared with net bank loan borrowings of $97 million in Fiscal 2009 and $133 million of repayments in Fiscal 2008. 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. 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.
Capital Expenditures
In the following table, we present capital expenditures by business segment for Fiscal 2010, Fiscal 2009 and Fiscal 2008. We also provide amounts we expect to spend in Fiscal 2011. We expect to finance a substantial portion of Fiscal 2011 capital expenditures from cash generated by operations and the remainder from borrowings under our Revolving Credit Agreement.
                                 
(Millions of dollars)   2011     2010     2009     2008  
    (estimate)                          
Gas Utility
  $ 76.7     $ 73.5     $ 73.8     $ 58.3  
Electric Utility
    9.5       8.1       5.3       6.0  
 
                       
 
  $ 86.2     $ 81.6     $ 79.1     $ 64.3  
 
                       

 

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The greater Electric Utility capital expenditures in Fiscal 2010 and Fiscal 2011 include actual and anticipated expenditures related to increased transmission capacity associated with additions to electric generating capacity in its service territory.
Contractual Cash Obligations and Commitments
UGI Utilities has contractual cash obligations that extend beyond Fiscal 2010 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, 2010.
                                         
    Payments Due by Period  
            Fiscal     Fiscal     Fiscal        
(Millions of dollars)   Total     2011     2012 - 2013     2014 - 2015     Thereafter  
Long-term debt (a)
  $ 640.0     $     $ 40.0     $ 133.0     $ 467.0  
Interest on long-term fixed rate debt (b)
    362.8       37.1       73.2       53.4       199.1  
Operating leases
    20.3       4.7       7.8       4.2       3.6  
Gas Utility and Electric Utility supply, storage and transportation contracts
    758.6       251.0       232.8       113.2       161.6  
 
                             
Total
  $ 1,781.7     $ 292.8     $ 353.8     $ 303.8     $ 831.3  
 
                             
     
(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, 2010 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. We believe we will be required to make contributions to the pension plans in Fiscal 2011 of approximately $20 million. Contributions to the pension plans in years beyond Fiscal 2011 will depend in large part on future returns on pension plans’ assets. 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.

 

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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.
Pension Plans
As of September 30, 2010, 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.
The fair value of Pension Plans’ assets totaled $287.9 million and $276.4 million at September 30, 2010 and 2009, respectively. At September 30, 2010 and 2009, the underfunded position of Pension Plans, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plans’ assets, was $177.1 million and $145.6 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 2011 of approximately $20 million. Pre-tax pension cost associated with Pension Plans in Fiscal 2010 were $10.1 million. Pre-tax pension cost associated with Pension Plans in Fiscal 2011 is expected to be approximately $13.0 million.
GAAP guidance associated with pension and other postretirement plans generally requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and other postretirement benefit plans with current year changes recognized in shareholder’s equity unless such amounts are subject to regulatory recovery. Based upon an August 2010 PUC order issued in response to UGI Utilities’ and PNG’s joint petition regarding the regulatory treatment of the funded status of their combined pension plan, effective September 30, 2010, UGI Utilities recorded a regulatory asset of $142.4 million associated with the underfunded position of the combined pension plan (see below and Note 8 to Consolidated Financial Statements). Previously, the effects of such underfunded position were reflected in accumulated other comprehensive income. Through September 30, 2010, we have recorded cumulative after-tax charges to stockholder’s equity of $8.1 million and regulatory assets of $159.2 million in order to reflect the funded status of our pension and postretirement benefit plans. For a more detailed discussion of the Pension Plans and other postretirement benefit plans, see Note 10 to Consolidated Financial Statements.
Change in Tax Method of Accounting
The Company received Internal Revenue Service (“IRS”) consent to change its tax method of accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. The filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30.2 million which was used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 stand alone Pennsylvania income tax return also produced a $43.4 million state net operating loss (“NOL”) carryforward. Under current Pennsylvania state income tax law, the NOL stated above can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded. For more information on the change in tax method of accounting, see Note 9 to Consolidated Financial Statements.

 

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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. The full-year effects of these rate increases are reflected in Gas Utility’s Fiscal 2010 results.
Electric Utility. As a result of Pennsylvania’s ECC Act, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. Electric Utility remains the DS provider for its customers that are not served by an alternate electric generation provider.
On July 17, 2008, the PUC approved Electric Utility’s DS procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s DS regulations. The approved plans specify how Electric Utility will solicit and acquire DS 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 DS costs. On October 1, 2009, UGI Utilities filed a DS plan to establish procurement rules applicable to the period after May 31, 2011 for its commercial and industrial customers. Because Electric Utility is assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010 Electric Utility is no longer subject to the risk that actual costs for purchased power will exceed POLR revenues. However, beginning January 1, 2010, Electric Utility no longer has the opportunity to recover revenues in excess of actual costs. On May 6, 2010, the PUC approved the plan, as modified by the terms of a March 2010 settlement.
Prior to January 1, 2010, the terms and conditions under which Electric Utility provided POLR service, and rules governing the rates that could 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 could 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.
Regulatory Asset — UGI Utilities Pension Plan. On April 14, 2010, UGI Utilities, Inc. and PNG filed a petition with the PUC requesting permission to record a regulatory asset or liability for amounts relating to their combined pension plan that otherwise would be recorded to accumulated other comprehensive income under the FASB’s Accounting Standards Codification (“ASC”) 715, “Compensation — Retirement Benefits.” On August 23, 2010, the PUC issued an order permitting UGI Utilities and PNG to establish regulatory assets for such amounts relating to their regulated operations. Effective September 30, 2010, UGI Utilities recorded a regulatory asset totaling $142.4 million associated with the underfunded position of the combined pension plan.
Subsequent Event — Approval of Transfer of CPG Storage Assets. On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to a special purpose entity, UGI Storage Company, a subsidiary of Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI. CPG will transfer the natural gas storage facilities on or before April 1, 2011. The net book value of the storage facility assets was approximately $11.0 million as of September 30, 2010. The transfer will be reflected as a dividend of net assets.

 

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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, 2010 and 2009, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $21.4 million and $25.0 million, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because 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, 2010, 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.
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.
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.
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 comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to 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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From time to time, UGI Utilities is a party to storage contract administrative agreements (“SCAAs”) with Energy Services. At September 30, 2010, UGI Utilities was a party to a three-year SCAA with Energy Services expiring October 31, 2012 and, during the periods covered by the financial statements, was a party to one-year SCAAs with Energy Services. Under all of the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives 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 Energy Services’ SCAAs totaling $21.8 million, $55.8 million and $111.8 million in Fiscal 2010, Fiscal 2009 and Fiscal 2008, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in other current liabilities on the Consolidated Balance Sheets, were $7.5 million and $15.0 million at September 30, 2010 and 2009, respectively. Effective November 1, 2010, UGI Utilities and Energy Services entered into a new SCAA having a term of three years.
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, 2010, comprising approximately 4.1 bcf feet of natural gas, was $20.7 million. The carrying value of these gas storage inventories at September 30, 2009, comprising approximately 7.7 bcf of natural gas, was $67.4 million.
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 Gas Utility during the months of November through March. In addition, from time to time, Gas Utility purchases natural gas or pipeline capacity from Energy Services. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during Fiscal 2010, Fiscal 2009 and Fiscal 2008 totaled $25.9 million, $24.4 million and $52.6 million, respectively.
From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2010, Fiscal 2009 and Fiscal 2008, revenues associated with sales to Energy Services totaled $62.1 million, $30.9 million and $66.1 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 2010, Fiscal 2009 and Fiscal 2008, such purchases totaled $31.2 million, $17.3 million and $29.5 million, 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.
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
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 Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of 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, 2010 Gas Utility had $4.7 million of restricted cash associated with natural gas futures accounts with brokers. There was no restricted cash at September 30, 2009. At September 30, 2010, the fair values of our natural gas futures and option contracts were losses of $1.4 million. There were no such gains or losses at September 30, 2009.

 

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Beginning January 1, 2010, Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs through the application of DS rates. The clauses provide for periodic adjustments to DS rates for differences between the total amount of power costs collected from customers and recoverable power costs incurred. Because of this ratemaking mechanism, beginning January 1, 2010 there is limited power cost risk, including the cost of financial transmission rights (“FTRs”), associated with our Electric Utility operations. 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. Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, through purchases at monthly PJM auctions. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. At September 30, 2010 and 2009, the fair values of FTRs were gains of $0.4 million and $0.8 million, respectively.
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 unrealized gains on these contracts and associated volumes under contract at September 30, 2010 and 2009 were not material.
Our variable-rate debt comprises borrowings under our Revolving Credit Agreement. This agreement provides 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 2010 and Fiscal 2009, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.7 million and $1.8 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 $50.7 million and $51.8 million at September 30, 2010 and 2009, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $57.7 million and $58.9 million at September 30, 2010 and 2009, respectively.
In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements. There were no unsettled interest rate protection agreements outstanding as of September 30, 2010 and 2009.
Our unsettled derivative instruments at September 30, 2010 comprise (1) Gas Utility’s exchange-traded natural gas futures and options contracts, which are included in Gas Utility’s PGC recovery mechanism; (2) Electric Utility’s FTRs and electricity forward contracts, which are included in Electric Utility’s DS recovery mechanism; and (3) exchange-traded gasoline futures and swap contracts.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance with GAAP 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.

 

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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 acquired and liabilities assumed are based upon available information and we may involve an independent third-party to perform appraisals. Estimating fair values can be complex and subject to significant business judgment and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, if necessary, up to one year from the acquisition date to finalize the purchase price allocation.
Impairment of Goodwill. 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, 2010, our goodwill totaled $180.1 million. We did not record any impairments of goodwill during Fiscal 2010, Fiscal 2009 or Fiscal 2008.
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, 2010, UGI Utilities net property, plant and equipment totaled $1,394.6 million and we recorded depreciation expense of $50.7 million during Fiscal 2010.
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, 2010, our regulatory assets totaled $306.7 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 Pension Plans’ assets of 50 basis points to a rate of 8.0% would result in an increase in pre-tax pension cost of approximately $1.4 million in Fiscal 2011. A decrease in the discount rate of 50 basis points to a rate of 4.5% would result in an increase in pre-tax pension cost of approximately $2.3 million in Fiscal 2011.

 

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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 2010.
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 disclosure controls and procedures are designed 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 required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were effective at the reasonable assurance level.
  (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.

 

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Based on its assessment, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2010, based on the COSO Framework. PricewaterhouseCoopers LLP, the Company’s independent registered public accounting firm, audited the effectiveness of the Company’s internal control over financial reporting as of September 30, 2010, as stated in their report, which appears herein.
  (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.
PART III:
ITEM 14.  
PRINCIPAL ACCOUNTING FEES AND SERVICES
The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent registered public accountants, in Fiscal 2010 and Fiscal 2009 were as follows:
                 
    2010     2009  
Audit Fees
  $ 739,800     $ 991,250  
Audit-Related Fees
    -0-       - 0 -  
Tax Fees
    -0-       - 0 -  
All Other Fees
    -0-       - 0 -  
 
           
Total Fees for Services Provided
  $ 739,800     $ 991,250  
 
           
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.

 

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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, 2010 and 2009
Consolidated Statements of Income for the fiscal years ended September 30, 2010, 2009 and 2008
Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2010, 2009 and 2008
Consolidated Statements of Stockholder’s Equity for the fiscal years ended September 30, 2010, 2009 and 2008
Notes to Consolidated Financial Statements
  (2)  
Financial Statement Schedule:
For the years ended September 30, 2010, 2009 and 2008
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  

 

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Incorporation by Reference
                         
Exhibit No.   Exhibit   Registrant   Filing   Exhibit
       
 
               
  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 (9/30/10)     10.7  
       
 
               
  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  
       
 
               
  10.5**    
UGI Corporation 2009 Deferral Plan Amended and Restated Effective June 1, 2010
  UGI   Form 10-Q (6/30/10)     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**    
Amendment 2009-1 to the UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan as Amended and Restated effective January 1, 2009
  UGI   Form 10-Q (12/31/09)     10.1  
       
 
               
  10.9**    
UGI Corporation 2009 Supplemental Executive
Retirement Plan For New Employees
  UGI   Form 10-Q (12/31/09)     10.2  
       
 
               
  10.10**    
UGI Utilities, Inc. Senior Executive Employee Severance Plan as in effect as of November 1, 2008
  Utilities   Form 10-K (9/30/10)     10.10  
       
 
               
  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  

 

30


Table of Contents

Incorporation by Reference
                         
Exhibit No.   Exhibit   Registrant   Filing   Exhibit
       
 
               
  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 **  
UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006
  UGI   Form 10-K (9/30/07)     10.8  
       
 
               
  10.19 **  
UGI Utilities, Inc. Executive Annual Bonus Plan effective as of October 1, 2006
  Utilities   Form 10-K (9/30/07)     10.5  
       
 
               
  10.20    
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  
       
 
               
  10.21    
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  
       
 
               
  10.22    
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  
       
 
               
  10.23    
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  
       
 
               
  10.24    
Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, Inc. effective as of May 1, 2007
  Utilities   Form 10-Q (6/30/10)     10.1  
       
 
               
  10.25    
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)
  UGI   Form 10-K (9/30/10)     10.60  

 

31


Table of Contents

Incorporation by Reference
                         
Exhibit No.   Exhibit   Registrant   Filing   Exhibit
       
 
               
  10.26    
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  
       
 
               
  10.27    
SST Service Agreement No. 79133 dated November 1, 2004 between Columbia Gas Transmission Corporation and UGI Utilities, Inc.
  Utilities   Form 10-Q (6/30/10)     10.2  
       
 
               
  *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  
       
 
               
  *21    
Subsidiaries of the Registrant
               
       
 
               
  *23    
Consent of PricewaterhouseCoopers LLP
               
       
 
               
  *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, 2010 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, 2010 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, 2010, 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.

 

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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 19, 2010  By:   /s/ Donald E. Brown    
    Donald E. Brown   
    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 19, 2010 by the following persons on behalf of the Registrant in the capacities indicated.
     
Signature   Title
 
   
/s/ John L. Walsh
 
John L. Walsh
  President and Chief Executive Officer (Principal Executive Officer), Vice Chairman and Director
 
   
/s/ Lon R. Greenberg
 
Lon R. Greenberg
  Chairman and Director 
 
   
/s/ Donald E. Brown
 
Donald E. Brown
  Vice President — Finance and Chief Financial Officer
(Principal Financial Officer)
 
   
/s/ Matthew J. Nolan
 
Matthew J. Nolan
  Controller
(Principal Accounting Officer)
 
   
/s/ Stephen D. Ban
 
Stephen D. Ban
  Director 
 
   
/s/ Richard C. Gozon
 
Richard C. Gozon
  Director 
 
   
/s/ Ernest E. Jones
 
Ernest E. Jones
  Director 
 
   
/s/ Anne Pol
 
Anne Pol
  Director 
 
   
/s/ M. Shawn Puccio
 
M. Shawn Puccio
  Director 
 
   
/s/ Marvin O. Schlanger
 
Marvin O. Schlanger
  Director 
 
   
/s/ Roger B. Vincent
 
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 2010.

 

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EXHIBIT INDEX
         
Exhibit No.   Description
       
 
  12.1    
Computation of Ratio of Earnings to Fixed Charges
       
 
  21    
Subsidiaries of the Registrant
       
 
  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

 

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UGI UTILITIES, INC.
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2010

 

F-1


 

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-37
 
       
Financial Statement Schedule:
       
 
       
For the years ended September 30, 2010, 2009 and 2008:
       
 
       
    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.

 

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Table of Contents

Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholder of UGI Utilities, Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of UGI Utilities, Inc. and its subsidiaries at September 30, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under item 15(a)(2) 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, 2010, 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 schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report 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.
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 19, 2010

 

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Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
                 
    September 30,  
    2010     2009  
ASSETS
               
 
               
Current assets:
               
Cash and cash equivalents
  $ 4,318     $ 13,523  
Restricted cash
    4,698        
Accounts receivable (less allowances for doubtful accounts of $7,072 and $11,384, respectively)
    64,844       74,286  
Accounts receivable — related parties
    6,313       3,378  
Accrued utility revenues
    13,988       20,980  
Inventories
    118,858       196,598  
Deferred income taxes
    19,431       24,905  
Regulatory assets
    26,100       19,584  
Derivative financial instruments
    486       867  
Prepaid expenses & other current assets
    21,117       5,167  
 
           
Total current assets
    280,153       359,288  
 
               
Property, plant and equipment
    2,129,324       2,056,877  
Less accumulated depreciation and amortization
    (734,739 )     (692,082 )
 
           
Net property, plant and equipment
    1,394,585       1,364,795  
 
               
Goodwill
    180,145       180,145  
Regulatory assets
    280,602       121,960  
Other assets
    4,091       4,049  
 
           
 
               
Total assets
  $ 2,139,576     $ 2,030,237  
 
           
 
               
LIABILITIES AND STOCKHOLDER’S EQUITY
               
 
               
Current liabilities:
               
Bank loans
  $ 17,000     $ 154,000  
Accounts payable — trade
    61,297       53,265  
Accounts payable — related parties
    8,144       8,746  
Employee compensation and benefits accrued
    12,268       12,504  
Interest accrued
    11,051       10,507  
Customer deposits and refunds
    57,465       48,073  
Derivative financial instruments
    10,564        
Deferred fuel refunds
    8,295       30,846  
Pension and postretirement benefit obligations
    20,303        
Other current liabilities
    32,848       39,882  
 
           
Total current liabilities
    239,235       357,823  
 
               
Long-term debt
    640,000       640,000  
Deferred income taxes
    281,101       168,830  
Deferred investment tax credits
    5,311       5,670  
Pension and postretirement benefit obligations
    161,338       150,499  
Other noncurrent liabilities
    78,137       61,372  
 
           
Total liabilities
    1,405,122       1,384,194  
 
               
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
    467,631       467,160  
Retained earnings
    217,960       201,710  
Accumulated other comprehensive loss
    (11,396 )     (83,086 )
 
           
Total common stockholder’s equity
    734,454       646,043  
 
           
 
               
Total liabilities and stockholder’s equity
  $ 2,139,576     $ 2,030,237  
 
           
See accompanying notes to consolidated financial statements.

 

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Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
                         
    Year Ended  
    September 30,  
    2010     2009     2008  
 
                       
Revenues
  $ 1,169,539     $ 1,381,260     $ 1,289,053  
 
                 
 
                       
Costs and expenses:
                       
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
    730,502       944,793       920,413  
Operating and administrative expenses
    169,464       191,263       147,131  
Operating and administrative expenses — related parties
    14,209       14,964       11,802  
Taxes other than income taxes
    18,638       16,917       18,264  
Depreciation
    50,747       48,873       39,464  
Amortization
    2,729       2,239       1,861  
Other income, net
    (6,269 )     (7,261 )     (12,924 )
 
                 
 
    980,020       1,211,788       1,126,011  
 
                 
 
                       
Operating income
    189,519       169,472       163,042  
Interest expense
    42,336       43,918       39,065  
 
                 
 
                       
Income before income taxes
    147,183       125,554       123,977  
Income taxes
    56,925       46,832       49,950  
 
                 
 
                       
Net income
  $ 90,258     $ 78,722     $ 74,027  
 
                 
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,  
    2010     2009     2008  
CASH FLOWS FROM OPERATING ACTIVITIES:
                       
Net income
  $ 90,258     $ 78,722     $ 74,027  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    53,476       51,112       41,325  
Deferred income taxes, net
    63,654       17,530       7,516  
Pension expense, net of contributions paid
    6,698       7,124       134  
Provision for uncollectible accounts
    10,651       19,193       18,210  
Other, net
    10,257       13,456       2,115  
Net change in:
                       
Accounts receivable and accrued utility revenues
    2,847       (15,133 )     (19,293 )
Inventories
    77,740       (12,742 )     491  
Deferred fuel costs, net of changes in unsettled derivatives
    (18,500 )     10,272       21,521  
Accounts payable
    7,424       (19,437 )     (3,311 )
Storage agreement security deposits
    3,500       19,000        
Other current assets
    (15,511 )     (1,072 )     696  
Other current liabilities
    (889 )     8,389       (875 )
 
                 
Net cash provided by operating activities
    291,605       176,414       142,556  
 
                 
 
                       
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
Expenditures for property, plant and equipment
    (81,595 )     (79,084 )     (64,351 )
Net costs of property, plant and equipment disposals
    (3,980 )     (5,114 )     (521 )
Acquisitions of businesses, net of cash acquired
          (292,551 )      
Proceeds from sale of CPP
          32,269        
(Increase) decrease in restricted cash
    (4,698 )     34,037       (27,395 )
 
                 
Net cash used by investing activities
    (90,273 )     (310,443 )     (92,267 )
 
                 
 
                       
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
Payment of dividends
    (74,008 )     (61,211 )     (68,762 )
Increase (decrease) in bank loans
    (137,000 )     97,000       (133,000 )
Issuances of long-term debt
          108,000       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
    471       280       130  
 
                 
Net cash (used) provided by financing activities
    (210,537 )     144,069       (63,013 )
 
                 
 
                       
Cash and cash equivalents (decrease) increase
  $ (9,205 )   $ 10,040     $ (12,724 )
 
                 
 
                       
CASH AND CASH EQUIVALENTS:
                       
End of year
  $ 4,318     $ 13,523     $ 3,483  
Beginning of year
    13,523       3,483       16,207  
 
                 
(Decrease) increase
  $ (9,205 )   $ 10,040     $ (12,724 )
 
                 
 
                       
SUPPLEMENTAL CASH FLOW INFORMATION:
                       
Cash paid for:
                       
Interest
  $ 39,917     $ 40,452     $ 44,273  
Income taxes
  $ 6,217     $ 26,919     $ 40,625  
See accompanying notes to consolidated financial statements.

 

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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, 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  
 
                                       
Net income
                    90,258               90,258  
Reclassifications of net losses on derivative instruments (net of tax of $483)
                            681       681  
Benefit plans, principally actuarial losses (net of tax of $11,134)
                            (15,699 )     (15,699 )
Reclassifications of benefit plans actuarial losses and prior service costs to net income (net of tax of $2,414)
                            3,406       3,406  
Reclassifications of pension plans actuarial losses and prior service costs to regulatory asset (net of tax of $59,078)
                            83,302       83,302  
 
                                 
Comprehensive income
                    90,258       71,690       161,948  
Cash dividends — Common Stock
                    (74,008 )             (74,008 )
Other
            471                       471  
 
                             
 
                                       
Balance September 30, 2010
  $ 60,259     $ 467,631     $ 217,960     $ (11,396 )   $ 734,454  
 
                             
 
                                       
See accompanying notes to consolidated financial statements.

 

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Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
1. NATURE OF OPERATIONS
Nature of Operations
UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ 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 April 1, 2008, UGI Utilities transferred by dividend its ownership interest in its wholly owned second-tier subsidiary UGI HVAC Services, Inc. (“UGI HVAC”) to UGI. UGI HVAC (prior to its dividend to UGI) and PNG’s wholly owned subsidiary 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, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
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 in Accounting Standards Codification (“ASC”) 980 related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for 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)
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 option contracts and non exchange-traded electricity forward contracts whose underlying is identical to an exchange-traded electricity contract.
 
Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include financial transmission rights (“FTRs”) and non exchange-traded electricity forward contracts not qualifying for Level 1.
 
Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 2010 or 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 our 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, and electricity forward purchase contracts used by Electric Utility, changes in fair value are included in deferred fuel and power costs or deferred fuel and power refunds 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.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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.
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, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to Utilities’ plant additions over the service lives of the related property. Utilities reduces 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.
Effective October 1, 2007, we adopted new interpretive guidance issued by the FASB on accounting for uncertainty related to income taxes. The cumulative effect from the adoption of the new guidance was recorded as a $230 decrease to the October 1, 2007 retained earnings balance.
Comprehensive Income
The components of AOCI at September 30, 2010 and 2009 follow:
                         
            Derivative        
    Postretirement     Instruments Net        
    Benefit Plans     Losses     Total  
Balance, September 30, 2010
  $ (8,133 )   $ (3,263 )   $ (11,396 )
Balance, September 30, 2009
  $ (79,142 )   $ (3,944 )   $ (83,086 )
Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) of $71,690, $(39,308) and $(28,461) for Fiscal 2010, Fiscal 2009 and Fiscal 2008, respectively, principally reflects changes in actuarial gains and losses on postretirement benefit plans 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. Other comprehensive income in Fiscal 2010 also includes the reclassification of $83,302 of accumulated other comprehensive losses associated with UGI Utilities’ pension plan, principally actuarial losses, to regulatory assets and deferred income taxes as a result of an August 2010 PUC order regarding regulatory treatment of the pension plan’s funded status (see Note 5). Other comprehensive income (loss) for all periods presented also includes reclassifications of net losses on previously settled interest rate protection agreements (“IRPAs”).

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Cash and Cash Equivalents
All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.
Restricted Cash
Restricted cash represents those cash balances in our commodity futures and option 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 basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.5% in Fiscal 2010, and 2.4% in Fiscal 2009 and Fiscal 2008. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.6% in Fiscal 2010, 2.9% in Fiscal 2009 and 2.6% in Fiscal 2008. 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 2010, Fiscal 2009 or Fiscal 2008.
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 2010, Fiscal 2009 or Fiscal 2008.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Employee Retirement Plans
We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 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, equity-based compensation costs are measured based upon the fair value of the award on the date of grant or the fair value of the award as of the end of each reporting period.
For additional information on our equity-based compensation plans and related disclosures, see Note 12.
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 include amounts for estimated environmental investigation and remediation costs associated with Pennsylvania sites. For further information, see Note 13.
3. ACCOUNTING CHANGES
Adoption of New Accounting Standards
Business Combinations. Effective October 1, 2009, we adopted new guidance on 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 October 1, 2009. Among the more significant changes in accounting for acquisitions are (1) transaction costs are generally expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, are generally 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 are recognized in operations (rather than as decreases in goodwill). The new guidance did not have an impact on our Fiscal 2010 financial statements.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Intangible Asset Useful Lives. Effective October 1, 2009, we adopted new accounting 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 must be applied prospectively to intangible assets acquired after the effective date. The adoption of the new guidance did not impact our financial statements.
Enhanced Disclosures of Postretirement Plan Assets. Effective September 30, 2010, we adopted accounting 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. Because this new guidance relates to disclosures only, it did not impact the financial statements. The enhanced disclosures are presented in Note 10.
Fair Value Measurements. In January 2010, the FASB issued new guidance with respect to fair value measurements disclosures. The new guidance requires additional disclosure related to transfers between Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements related to Level 3. The new guidance clarifies existing disclosure guidance about inputs and valuation techniques for fair value measurements and levels of disaggregation. We apply fair value measurements to certain assets and liabilities, principally commodity derivative instruments. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009 except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2009 (Fiscal 2011) and interim periods thereafter. The adoption of the new guidance that became effective during Fiscal 2010 did not have a material effect on our disclosures. See Note 2 and Note 14 for further information on fair value measurements.
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 Sheets at September 30, 2010 and 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.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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 is 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.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
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:
                 
    2010     2009  
Regulatory assets:
               
Income taxes recoverable
  $ 82,525     $ 79,492  
Underfunded pension and postretirement plans
    159,154       8,572  
Environmental costs
    22,587       26,877  
Deferred fuel and power costs
    36,597       19,584  
Other
    5,839       7,019  
 
           
Total regulatory assets
  $ 306,702     $ 141,544  
 
           
 
               
Regulatory liabilities:
               
Postretirement benefits
  $ 10,472     $ 9,310  
Environmental overcollections
    7,211       8,720  
Deferred fuel and power refunds
    8,298       30,846  
State tax benefits — distribution system repairs
    6,685        
 
           
Total regulatory liabilities
  $ 32,666     $ 48,876  
 
           
Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 50 years.
Underfunded pension and other postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and other postretirement benefits which is probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP relating to pension and postretirement plans. These costs are amortized over the average remaining future service lives of plan participants.
Based upon the FASB’s guidance related to rate-regulated entities and an August 2010 PUC order issued in response to UGI Utilities’ and PNG’s April 2010 joint petition regarding the regulatory treatment of their combined pension plan (see “Other Regulatory Matters” below), effective September 30, 2010, UGI Utilities recorded a regulatory asset for the amounts associated with regulated operations that would otherwise be recorded in AOCI under ASC 715, “Compensation — Retirement Benefits.” Based upon established rate treatment, CPG historically has recorded regulatory assets associated with its underfunded pension and other postretirement plans.
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 principally at manufactured gas plant (“MGP”) sites 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 prudently incurred remediation costs at Pennsylvania sites. PNG Gas and CPG Gas are currently recovering and expect to continue to recover these costs in base rate revenues. At September 30, 2010, the period over which PNG Gas and CPG Gas expect to recover these costs will depend upon future remediation activity.
Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and, commencing January 1, 2010, Electric Utility’s default service (“DS”) tariffs, contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and DS rates in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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 costs or refunds. Net unrealized losses on such contracts at September 30, 2010 were $1,359. There were no such unrealized gains or losses at September 30, 2009.
Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. As more fully described in Note 15 to Consolidated Financial Statements, during Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value, with an associated adjustment to regulatory assets or liabilities in accordance with ASC 980 and Electric Utility’s DS procurement, implementation and contingency plans (as further described below). At September 30, 2010, the fair values of Electric Utility’s electricity supply contracts was a loss of $19,702 which amount is reflected in current derivative financial instruments and other noncurrent liabilities on the September 30, 2010 Consolidated Balance Sheet with an equal and offsetting amount reflected in deferred fuel and power costs in the table above.
In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010 through DS rates, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains on FTRs at September 30, 2010 were not material.
Postretirement benefits. Gas Utility and Electric Utility are recovering ongoing postretirement benefit costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI Gas and Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above.
Environmental overcollections. This regulatory liability represents the difference between amounts recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms of a consent order agreement between CPG and the Pennsylvania Department of Environmental Protection to remediate certain gas plant sites.
State income tax benefits — distribution system repairs. As described in Note 9 below, the Company received IRS consent to change its tax method of accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of these repair and maintenance expenses which expenses are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.
Other. Other regulatory assets comprise a number of items including, among others, deferred postretirement costs, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2010, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
UGI Utilities’ regulatory liabilities relating to postretirement benefits, environmental overcollections and state tax benefits — distribution system repairs are included in “Other noncurrent liabilities” on the Consolidated Balance Sheets. UGI Utilities does not recover a rate of return on its regulatory assets.
Other Regulatory Matters
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 DS provider for its customers that are not served by an alternate electric generation provider.
On July 17, 2008, the PUC approved Electric Utility’s DS procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s DS regulations. These plans did not affect Electric Utility’s existing POLR settlement effective through December 31, 2009. The approved plans specify how Electric Utility will solicit and acquire DS 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 DS costs. On October 1, 2009, UGI Utilities filed a DS plan to establish procurement rules applicable to the period after May 31, 2011 for its commercial and industrial customers. On May 6, 2010, the PUC approved the plan, as modified by the terms of a March 2010 settlement.
Prior to January 1, 2010, the terms and conditions under which Electric Utility provided provider of last resort (“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 could 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.
Regulatory Asset — UGI Utilities Pension Plan. On April 14, 2010, UGI Utilities, Inc. and PNG filed a petition with the PUC requesting permission to record a regulatory asset or liability for amounts relating to their combined pension plan that otherwise would be recorded to AOCI under ASC 715, “Compensation — Retirement Benefits.” On August 23, 2010, the PUC issued an order permitting UGI Utilities and PNG to establish regulatory assets for such amounts relating to their regulated operations. Effective September 30, 2010, UGI Utilities recorded a regulatory asset totaling $142,382 associated with the underfunded position of the combined pension.
Subsequent Event — Approval of Transfer of CPG Storage Assets. On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to a special purpose entity, UGI Storage Company, a subsidiary of Energy Services, Inc. (“Energy Services”), a second-tier wholly owned subsidiary of UGI. CPG will transfer the natural gas storage facilities on or before April 1, 2011. The net book value of the storage facility assets was approximately $11,000 as of September 30, 2010. The transfer will be reflected as a dividend of net assets.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
6. INVENTORIES
Inventories comprise the following at September 30:
                 
    2010     2009  
Gas Utility natural gas
  $ 111,531     $ 189,747  
Materials, supplies and other
    7,327       6,851  
 
           
Total inventories
  $ 118,858     $ 196,598  
 
           
At September 30, 2010, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”) two of which expire in October 2012 and one of which expires in October 2010. At September 30, 2009, UGI Utilities was a party to two SCAA’s which expired in October 2009. Pursuant to these SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represent a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above. The carrying value of gas storage inventories released under the SCAAs at September 30, 2010 and 2009 comprising 12.1 billion cubic feet (“bcf”) and 9.0 bcf of natural gas was $62,653 and $77,948, respectively. Effective November 1, 2010, UGI Utilities entered into a new SCAA having a term of three years (see Note 18).
7. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment comprise the following categories at September 30:
                 
    2010     2009  
Distribution
  $ 1,865,980     $ 1,813,201  
Transmission
    78,190       76,826  
General and other, including construction in process
    185,154       166,850  
 
           
Total property, plant and equipment
  $ 2,129,324     $ 2,056,877  
 
           

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
8. DEBT
Long-term debt comprises the following at September 30:
                 
    2010     2009  
Senior Notes:
               
6.375% Notes, due September 2013
  $ 108,000     $ 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     $ 640,000  
 
           
There are no principal payments of long-term debt due in Fiscal 2011; $40,000 is due in Fiscal 2012; $133,000 is due in Fiscal 2013; and $20,000 is due in Fiscal 2015.
UGI Utilities has a revolving credit agreement (“Revolving Credit Agreement”) with a group of 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 $17,000 at September 30, 2010 and $154,000 at September 30, 2009. The weighted-average interest rates on Revolving Credit Agreement borrowings at September 30, 2010 and 2009 were 3.25% and 0.59%, respectively. The higher interest rate at September 30, 2010 is the result of a prime rate borrowing compared to LIBOR borrowings at September 30, 2009.
The Revolving Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
9. INCOME TAXES
The provisions for income taxes consist of the following:
                         
    2010     2009     2008  
Current expense:
                       
Federal
  $ (8,577 )   $ 19,302     $ 31,974  
State
    1,848       10,000       10,460  
 
                 
Total current (benefit) expense
    (6,729 )     29,302       42,434  
 
                       
Deferred expense
    64,022       17,898       7,894  
Investment tax credit amortization
    (368 )     (368 )     (378 )
 
                 
Total income tax expense
  $ 56,925     $ 46,832     $ 49,950  
 
                 

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:
                         
    2010     2009     2008  
U.S. federal statutory tax rate
    35.0 %     35.0 %     35.0 %
Difference in tax rate due to:
                       
State income taxes, net of federal
    4.3       3.6       4.7  
Other, net
    (0.6 )     (1.3 )     0.6  
 
                 
Effective tax rate
    38.7 %     37.3 %     40.3 %
 
                 
Deferred tax liabilities (assets) comprise the following at September 30:
                 
    2010     2009  
Excess book basis over tax basis of property, plant and equipment
  $ 248,153     $ 199,213  
Goodwill
    17,962       13,444  
Regulatory assets
    127,262       51,576  
Other
    1,856       1,883  
 
           
Gross deferred tax liabilities
    395,233       266,116  
 
           
 
               
Pension plan liabilities
    (76,103 )     (60,350 )
Allowance for doubtful accounts
    (2,934 )     (4,723 )
Deferred investment tax credits
    (2,203 )     (2,352 )
Employee-related expenses
    (8,771 )     (8,832 )
Regulatory liabilities
    (13,336 )     (16,648 )
Environmental liabilities
    (7,040 )     (9,256 )
Derivative financial instruments
    (5,195 )     (2,781 )
Other
    (17,981 )     (17,249 )
 
           
Gross deferred tax assets
    (133,563 )     (122,191 )
 
           
 
               
Net deferred tax liabilities
  $ 261,670     $ 143,925  
 
           
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 2007. UGI’s federal income tax return for Fiscal 2008 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 Internal Revenue Service’s (“IRS’s”) audit of UGI’s Fiscal 2008 U.S. federal income tax return will likely be completed during Fiscal 2011.
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 2010 and 2009, interest income of $25 and $55, respectively, was recognized in income taxes in the Consolidated Statements of Income. As of September 30, 2010, we have unrecognized income tax benefits totaling $4,194 including related accrued interest of $46. If these unrecognized tax benefits were subsequently recognized, $282 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 $200.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
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  
Additions for tax positions of the current year
    3,907  
Additions for tax positions of prior years
    9  
Settlements with tax authorities
    (331 )
Decreases for tax positions related to prior years
    (25 )
 
     
Balance at September 30, 2010
  $ 4,194  
 
     
The Company received IRS consent to change its tax method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. The filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30,200 which was used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 Pennsylvania income tax return also produced a $43,393 state net operating loss (“NOL”) carryforward. Under current Pennsylvania state income tax law, the NOL can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded. The Company’s determination of what constitutes a capital cost versus ordinary expense as it relates to the new tax method will likely be reviewed upon audit by the IRS and may be subject to subsequent adjustment. Accordingly, the status of this tax return position is uncertain at this time. In accordance with accounting guidance regarding uncertain tax positions, the Company has added $3,907 to its liability for unrecognized tax benefits related to this tax method. However, because this tax matter relates only to the timing of tax deductibility, we have recorded an offsetting deferred tax asset of an equal amount. For further information regarding the regulatory impact of this change, see Note 5.
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 active employees 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.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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, 2010 and 2009. 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.
                                 
    Pension     Other Postretirement  
    Benefits     Benefits  
    2010     2009     2010     2009  
Change in benefit obligations:
                               
Benefit obligations — beginning of year
  $ 422,041     $ 300,578     $ 14,610     $ 9,713  
Service cost
    8,122       6,831       186       139  
Interest cost
    23,161       22,904       772       843  
Actuarial loss
    29,667       64,709       720       1,557  
Plan amendments
          42             46  
Acquisitions
          44,465             3,418  
Benefits paid
    (18,014 )     (17,488 )     (1,148 )     (1,106 )
 
                       
Benefit obligations — end of year
  $ 464,977     $ 422,041     $ 15,140     $ 14,610  
 
                               
Change in plan assets:
                               
Fair value of plan assets — beginning of year
  $ 276,438     $ 240,997     $ 9,714     $ 10,002  
Actual gain on assets
    26,125       14,527       723       46  
Employer contributions
    3,353             718       772  
Acquisitions
          38,402              
Benefits paid
    (18,014 )     (17,488 )     (1,148 )     (1,106 )
 
                       
Fair value of plan assets — end of year
  $ 287,902     $ 276,438     $ 10,007     $ 9,714  
 
                               
Funded status of the plans — end of year
  $ (177,075 )   $ (145,603 )   $ (5,133 )   $ (4,896 )
 
                       
 
                               
Assets (liabilities) recorded in the balance sheet:
                               
Unfunded liabilities — included in other current liabilities
  $ (20,303 )   $     $     $  
Unfunded liabilities — included in other noncurrent liabilities
    (156,772 )     (145,603 )     (5,133 )     (4,896 )
 
                       
Net amount recognized
  $ (177,075 )   $ (145,603 )   $ (5,133 )   $ (4,896 )
 
                       
 
                               
Amounts recorded in stockholder’s equity (pre-tax):
                               
Prior service cost
  $ 24     $ 392     $ 55     $ 61  
Net actuarial loss
    13,640       134,878       192       93  
 
                       
Total
  $ 13,664     $ 135,270     $ 247     $ 154  
 
                       
 
                               
Amounts recorded in regulatory assets and liabilities (pre-tax):
                               
Prior service cost (credit)
  $ 271     $     $ (3,420 )   $ (3,853 )
Net actuarial loss
    155,585       11,120       5,915       6,429  
 
                       
Total
  $ 155,856     $ 11,120     $ 2,495     $ 2,576  
 
                       
In Fiscal 2011, we estimate that we will amortize $9,200 of net actuarial losses and $400 of prior service credits from stockholder’s equity and regulatory assets.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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:   2010     2009     2008     2007     2010     2009     2008     2007  
Discount rate
    5.0 %     5.5 %     6.8 %     6.4 %     5.0 %     5.5 %     6.8 %     6.4 %
Expected return on plan assets
    8.5 %     8.5 %     8.5 %     8.5 %     5.5 %     5.5 %     5.5 %     5.5 %
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 $413,814 and $374,213 as of September 30, 2010 and 2009, respectively. Included in the end of year Pension Plans PBOs above are $43,550 at September 30, 2010 and $37,023 at September 30, 2009 relating to employees of UGI and certain of its other subsidiaries. Included in the end of year other postretirement plans ABOs above are $666 at September 30, 2010 and $665 at September 30, 2009 relating to employees of UGI and certain of its other subsidiaries.
Net periodic pension expense and other postretirement benefit costs relating to the Company’s employees include the following components:
                                                 
    Pension Benefits     Other Postretirement Benefits  
    2010     2009     2008     2010     2009     2008  
Service cost
  $ 6,980     $ 5,975     $ 5,053     $ 175     $ 131     $ 261  
Interest cost
    21,137       21,326       17,757       752       820       775  
Expected return on assets
    (23,433 )     (23,794 )     (22,702 )     (508 )     (523 )     (640 )
Curtailment gain
                                  (2,202 )
Amortization of:
                                               
Prior service cost (benefit)
    36       29       26       (406 )     (410 )     (388 )
Actuarial loss
    5,331       3,588             231       88        
 
                                   
Net benefit cost (income)
    10,051       7,124       134       244       106       (2,194 )
Change in associated regulatory liabilities
                      3,137       3,271       3,435  
 
                                   
Benefit cost after change in regulatory liabilities
  $ 10,051     $ 7,124     $ 134     $ 3,381     $ 3,377     $ 1,241  
 
                                   
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. During Fiscal 2010, we made contributions to the Plans of $3,353. We did not make any contributions to the Pension Plans in Fiscal 2009 or Fiscal 2008. We believe that we will be required to make contributions during Fiscal 2011 of approximately $20,300.
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 2011 is not expected to be material.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Expected payments for pension benefits and other postretirement welfare benefits are as follows:
                 
            Other  
    Pension     Postretirement  
    Benefits     Benefits  
Fiscal 2011
  $ 19,363     $ 1,594  
Fiscal 2012
    20,345       1,561  
Fiscal 2013
    21,464       1,499  
Fiscal 2014
    22,679       1,510  
Fiscal 2015
    23,992       1,497  
Fiscal 2016 - 2020
    140,526       7,374  
The assumed health care cost trend rates are 7.5% for Fiscal 2011, 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 2010 postretirement benefit cost and obligation as follows:
                 
    1% Increase     1% Decrease  
Service and interest costs in Fiscal 2010
  $ 11     $ (11 )
ABO at September 30, 2010
  $ 221     $ (207 )
We also sponsor an unfunded and non-qualified supplemental executive retirement income plan. At September 30, 2010 and 2009, the projected benefit obligations of this plan were $3,074 and $2,773, respectively. We recorded expense for this plan of $249 in Fiscal 2010, $635 in Fiscal 2009 and $362 in Fiscal 2008.
Pension Plans and Postretirement Plan Assets. The assets of the Pension Plans and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the Pension Plans and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
The targets, target ranges and actual allocations for the Pension Plans’ and VEBA trust assets at September 30 are as follows:
                             
                    Target      
    Actual     Asset     Permitted
Pension Plans:   2010     2009     Allocation     Range
Equity investments:
                           
Domestic
    56.1 %     54.9 %     52.5 %   40.0% - 65.0%
International
    12.2 %     12.8 %     12.5 %   7.5% - 17.5%
 
                     
Total
    68.3 %     67.7 %     65.0 %   60.0% - 70.0%
 
                           
Fixed income funds & cash equivalents
    31.7 %     32.3 %     35.0 %   30.0% - 40.0%
 
                     
Total
    100.0 %     100.0 %     100.0 %    
 
                     
 
                           
                             
                    Target      
    Actual     Asset     Permitted
VEBA:   2010     2009     Allocation     Range
Domestic equity investments
    64.9 %     64.4 %     65.0 %   60.0% - 70.0%
 
                           
Fixed income funds & cash equivalents
    35.1 %     35.6 %     35.0 %   30.0% - 40.0%
 
                     
Total
    100.0 %     100.0 %     100.0 %    
 
                     
Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds. Investments in international equity mutual funds are indexed to various Morgan Stanley Composite indices. The fixed income investments comprise investments designed to match the duration of the Barclays Capital Aggregate Bond Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 8.3% and 7.5% of Pension Plans assets at September 30, 2010 and 2009, respectively. At September 30, 2010, there were no significant concentrations of risk (defined as greater than 10% of the fair value of total assets) associated with any individual company, industry sector or international geographic region.
GAAP establishes a hierarchy that prioritizes fair value measurements based upon the inputs and valuation techniques used to measure fair value. This fair value hierarchy groups assets into three levels, as described in Note 2. We maximize the use of observable inputs and minimize the use of unobservable inputs when determining fair value. The fair values of Pension Plans and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
The fair values of the Pension Plans’ assets at September 30, 2010 and 2009 by asset class are as follows:
                                 
    Pension Plans  
    Quoted Prices                    
    in Active     Significant              
    Markets for     Other              
    Identical Assets     Observable     Unobservable        
    and Liabilities     Inputs     Inputs        
    (Level 1)     (Level 2)     (Level 3)     Total  
September 30, 2010:
                               
Equity investments:
                               
Domestic
  $ 161,485     $     $     $ 161,485  
International
    35,232                   35,232  
Fixed income
    88,924                   88,924  
Cash equivalents
          2,261             2,261  
 
                       
Total
  $ 285,641     $ 2,261     $     $ 287,902  
 
                       
 
                               
September 30, 2009:
                               
Equity investments:
                               
Domestic
  $ 151,567     $     $     $ 151,567  
International
    35,555                   35,555  
Fixed income
    87,122                   87,122  
Cash equivalents
          2,194             2,194  
 
                       
Total
  $ 274,244     $ 2,194     $     $ 276,438  
 
                       
The fair values of the VEBA trust assets at September 30, 2010 and 2009 by asset class are as follows:
                                 
    Postretirement Plans  
    Quoted Prices                    
    in Active     Significant              
    Markets for     Other              
    Identical Assets     Observable     Unobservable        
    and Liabilities     Inputs     Inputs        
    (Level 1)     (Level 2)     (Level 3)     Total  
September 30, 2010:
                               
Domestic equities
  $ 6,498     $     $     $ 6,498  
Fixed income
    2,964                   2,964  
Cash equivalents
          545             545  
 
                       
Total
  $ 9,462     $ 545     $     $ 10,007  
 
                       
 
                               
September 30, 2009:
                               
Domestic equities
  $ 6,257     $     $     $ 6,257  
Fixed income
    2,921                   2,921  
Cash equivalents
          536             536  
 
                       
Total
  $ 9,178     $ 536     $     $ 9,714  
 
                       

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
The expected long-term rates of return on Pension Plans and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.
Defined Contribution 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 $1,663 in Fiscal 2010, $1,758 in Fiscal 2009 and $1,256 in Fiscal 2008.
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, 2010 or 2009.
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 $853 ($499 after-tax) during Fiscal 2010; $1,142 ($668 after-tax) during Fiscal 2009; and $842 ($492 after-tax) during Fiscal 2008.
As of September 30, 2010, there was $392 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, 2010, there was a total of $514 of unrecognized compensation expense associated with 57,400 UGI Unit awards that is expected to be recognized over a weighted average period of 1.8 years. At September 30, 2010 and 2009, total liabilities of $550 and $560, 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)
The following table summarizes UGI Unit award activity for Fiscal 2010:
                                                 
    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, 2009
    50,334     $ 28.61       19,234     $ 28.62       31,100     $ 28.60  
Granted
    21,200     $ 22.72           $       21,200     $ 22.72  
Vested
        $       15,334     $ 27.01       (15,334 )   $ 27.01  
Forfeited
    (1,100 )   $ 25.10           $       (1,100 )   $ 25.10  
Unit awards paid
    (13,034 )   $ 27.71       (13,034 )   $ 27.71           $  
 
                                   
September 30, 2010
    57,400     $ 26.70       21,534     $ 28.02       35,866     $ 25.92  
 
                                   
13. COMMITMENTS AND CONTINGENCIES
Commitments
We lease various buildings and vehicles, 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 $5,737 in Fiscal 2010, $5,894 in Fiscal 2009 and $4,858 in Fiscal 2008.
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: 2011 — $4,650; 2012 — $4,197; 2013 — $3,600; 2014 — $2,518; 2015 — $1,736; after September 30, 2015 — $3,580.
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 2022. 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 electricity needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2014.
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: 2011 — $251,011; 2012 — $133,771; 2013 — $99,021; 2014 — $70,587; 2015 — $42,593; after 2015 — $161,589.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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 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, 2010 and 2009, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $21,385 and $25,042, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. 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, 2010, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities.
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.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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. The court referred the motion to a magistrate judge for findings and a recommendation. On October 19, 2010, the magistrate judge entered an order recommending that the court grant UGI Utilities’ motion.
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. The Northeast Companies have appealed the decision. With respect to Waterbury North, the Northeast Companies are expected to complete additional environmental investigations at Waterbury North by the end of 2010, after which there will be a second phase of the trial to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies previously estimated 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.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
14. FAIR VALUE MEASUREMENTS
Derivative Financial Instruments
The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of September 30, 2010 and 2009:
                                 
    Quoted                    
    Prices in                    
    Active                    
    Markets for     Significant              
    Identical     Other              
    Assets and     Observable     Unobservable        
    Liabilities     Inputs     Inputs        
    (Level 1)     (Level 2)     (Level 3)     Total  
September 30, 2010
                               
Derivative financial instruments
                               
Assets
  $ 61     $ 425     $     $ 486  
Liabilities
  $ (3,263 )   $ (17,798 )   $     $ (21,061 )
 
                               
September 30, 2009
                               
Derivative financial instruments
                               
Assets
  $ 102     $ 765     $     $ 867  
Liabilities
  $     $     $     $  
The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts and certain non exchange-traded electricity forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments and electricity forward contracts, which are designated as Level 2, are generally based upon recent market transactions and related market indicators.
Other 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 amount and estimated fair value of our long-term debt at September 30, 2010 were $640,000 and $749,227, respectively. The carrying amount and estimated fair value of our long-term debt at September 30, 2009 were $640,000 and $705,710, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt.
15. DISCLOSURES ABOUT DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk 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 most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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 and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers.
Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At September 30, 2010, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $19,702 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying September 30, 2010 Consolidated Balance Sheet. In accordance with ASC 980 related to rate regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets on the September 30, 2010 Consolidated Balance Sheet.
In order to reduce volatility associated with a substantial portion of its electric 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. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010 pursuant to the January 22, 2009 settlement of its DS filing with the PUC, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 5). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At September 30, 2010 and 2009, the volumes associated with Electric Utility FTRs totaled 546.8 million kilowatt hours and 1,009.0 million kilowatt hours, respectively.
At September 30, 2010, the volume of natural gas associated with our unsettled NYMEX natural gas futures and option contracts totaled 19.5 million dekatherms and the maximum period over which Gas Utility is hedging natural gas market price risk is 12 months. At September 30, 2009, we had no unsettled NYMEX gas futures or option contracts outstanding. At September 30, 2010, the volume of electricity under Electric Utility’s forward electricity purchase contracts was 990.7 million kilowatt hours and the maximum period over which these contracts extend is 43 months.
With respect to natural gas futures and option contracts associated with Gas Utility, gains and losses on unsettled natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets in accordance with the FASB’s guidance in ASC 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010 pursuant to a January 22, 2009 settlement of its DS rate filing with the PUC, gains and losses on FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets and liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 5). Gains and losses associated with periods prior to January 1, 2010 are reflected in cost of sales.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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 were not material for all periods presented.
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 accumulated other comprehensive income (“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, 2010 and 2009 there were no unsettled IRPA contracts outstanding. The amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $1,164.
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, 2010, Gas Utility’s restricted cash in brokerage accounts totaled $4,698. 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, 2010 and 2009:
                                                 
    Derivative Assets     Derivative (Liabilities)  
    Balance Sheet     Fair Value     Balance Sheet     Fair Value  
    Location     2010     2009     Location     2010     2009  
Derivatives Accounted for Under ASC 980:
                                               
Commodity contracts
 
Derivative financial instruments
    $ 425     $    
Derivative financial instruments and Other noncurrent liabilities
    $ (21,061 )   $  
 
                                               
Derivatives Not Designated as Hedging Instruments:
                                               
Commodity contracts
 
Derivative financial instruments
    $ 61     $ 867                          
 
                                       
Total Derivatives
          $ 486     $ 867             $ (21,061 )   $  
 
                                       

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
During the year ended September 30, 2010 and 2009, the amount of IRPA net losses included in AOCI that were reclassified into net income totaled $1,164. During the years ended September 30, 2010 and 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 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 in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
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.”
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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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Financial information by business segment follows:
                                 
            Gas     Electric        
    Total     Utility     Utility     Other  
2010
                               
Revenue
  $ 1,169,539     $ 1,047,521     $ 120,246     $ 1,772  
Cost of sales
    730,502       653,439       77,063        
Depreciation and amortization
    53,476       49,474       4,002        
Operating income
    189,519       175,272       13,676       571  
Interest expense
    42,336       40,515       1,821        
Income before income taxes
    147,183       134,757       11,855       571  
Total assets
    2,139,576       1,996,281       143,295        
Goodwill
    180,145       180,145              
Capital expenditures
    81,595       73,503       8,092        
 
                               
2009
                               
Revenue
  $ 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       1,917,036       113,201        
Goodwill
    180,145       180,145              
Capital expenditures
    79,084       73,825       5,259        
 
                               
2008
                               
Revenue
  $ 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  
17. OTHER INCOME, NET
Other income, net, comprises the following:
                         
    2010     2009     2008  
Non-tariff service income
  $ 2,437     $ 3,221     $ 6,191  
Interest income
    867       288       1,444  
Postretirement benefit plan curtailment gain
                2,202  
Other
    2,965       3,752       3,087  
 
                 
Total other income, net
  $ 6,269     $ 7,261     $ 12,924  
 
                 

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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 comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to 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 Condensed 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.
From time to time, UGI Utilities is a party to SCAAs with Energy Services. At September 30, 2010, UGI Utilities was a party to a three-year SCAA with Energy Services expiring October 31, 2012 and, during the periods covered by the financial statements, was a party to one-year SCAAs with Energy Services. Under all of the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives 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 Energy Services’ SCAAs totaling $21,826, $55,760 and $111,764 in Fiscal 2010, Fiscal 2009 and Fiscal 2008, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amount of such security deposits, which amounts are included in other current liabilities on the Consolidated Balance Sheets, was $7,500 and $15,000 at September 30, 2010 and 2009, respectively. Effective November 1, 2010, UGI Utilities and Energy Services entered into a new SCAA having a term of three years.
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, 2010, comprising approximately 4.1 bcf feet of natural gas, was $20,749. The carrying value of these gas storage inventories at September 30, 2009, comprising approximately 7.7 bcf of natural gas, was $67,436.
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 Gas Utility during the months of November through March. In addition, from time to time, Gas Utility purchases natural gas or pipeline capacity from Energy Services. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during Fiscal 2010, Fiscal 2009 and Fiscal 2008 totaled $25,941, $24,444 and $52,603, respectively.
From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2010, Fiscal 2009 and Fiscal 2008, revenues associated with sales to Energy Services totaled $62,074, $30,911 and $66,126, 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 2010, Fiscal 2009 and Fiscal 2008, such purchases totaled $31,157, $17,268 and $29,454, 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.

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
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,  
    2009     2008     2010     2009     2010     2009     2010     2009  
Revenues
  $ 362,203     $ 446,692     $ 477,273     $ 581,260     $ 175,021     $ 208,300     $ 155,042     $ 145,008  
Operating income
  $ 69,273     $ 62,012     $ 94,337     $ 85,673     $ 16,379     $ 16,443     $ 9,530     $ 5,344  
Net income (loss)
  $ 35,163     $ 31,134     $ 50,612     $ 44,746     $ 3,604     $ 3,113     $ 879     $ (271 )

 

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UGI UTILITIES, INC. AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Thousands of dollars)
                                 
    Balance at     Charged to             Balance at  
    beginning of     costs and             end of  
    year     expenses     Other     year  
Year Ended September 30, 2010
                               
Reserves deducted from assets in the consolidated balance sheet:
                               
Allowance for doubtful accounts
  $ 11,384     $ 10,651     $ (14,963 )(1)   $ 7,072  
 
                           
 
                               
Other reserves:
                               
Other, principally environmental
  $ 38,707     $ (1,547 )   $ (2,940 )(3)   $ 33,465  
 
                           
 
                  $ (755 )(5)        
 
                               
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)        
     
(1)  
Uncollectible accounts written off, net of recoveries
 
(2)  
Acquisition adjustments
 
(3)  
Payments, net
 
(4)  
Dividend of UGI HVAC
 
(5)  
Other adjustments

 

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